National Grid Electricity System Operator (ESO) – Written evidence (LES0032)

Introduction

As the Electricity System Operator (ESO) for Great Britain, we welcome the opportunity to submit a response to your inquiry. Our role is to operate the national electricity transmission system, whilst building a secure, clean, and fair system for tomorrow. We move electricity around the system, procuring services to balance demand and supply second by second, 24/7. We do not generate or sell electricity, or own and maintain any infrastructure, as the system operator we ensure fairness is at the heart of how we manage the system by remaining impartial and basing our decisions on consumer outcomes.

We work in partnership with Government, Ofgem, industry and consumers to guide Great Britain (GB) on the energy resources, markets and networks required to securely accelerate the transition away from fossil fuels. The ESO will make net zero carbon operation of the electricity system technically possible for short periods by 2025. By 2035, provided the market supplies a 100% zero carbon mix, we will operate a net zero carbon electricity system all the time, in line with government targets.

As part of the Government’s Energy Bill[1], the ESO will become an independent public body, with responsibility for advising government and Ofgem across the whole energy system as it transitions to net zero, from strategic network planning across electricity and gas to new vectors such as hydrogen.

Why are we submitting evidence

In the last decade, working with Government, industry and Ofgem, we have helped GB decarbonise its electricity system, with the pace and scale of decarbonisation amongst the fastest in the world. We are constantly thinking about how the whole energy system needs to evolve to meet current government targets. The scale of change needed to deliver a decarbonised energy system demands urgent and collaborative action to better understand the role storage can play in the wider energy system today and in the future.

Executive Summary

•          There is a need to accelerate the deployment of long-duration energy storage (LDES) as we do not see a sufficient pipeline of projects to bridge the gap between what is available now and what will be needed in the years ahead. The ESO is working to make our markets more accessible, but we do not believe that the actions we take alone will be sufficient to bring forward the quantities of storage needed for net zero.

•          Long duration storage will be required in significant volumes to achieve net zero. To achieve net zero targets, our scenario modelling shows capacities of longer duration storage technologies of 3 to 9 GW in 2030, rising to 12 to 17 GW in 2050. In addition, the same scenarios see hydrogen generation capacity (part of a hydrogen based long duration storage system) reaching 18 to 23 GW by 2050.

•          Long duration storage is not a silver bullet for achieving net zero or a decarbonised power system. The electricity system will need significant additional capacity of at least one of either new nuclear, carbon capture and storage and hydrogen fuelled generation to provide generation adequacy through long periods of low renewable output[2]. If all these technologies fail to deliver, maintaining a reliable net zero electricity system will be challenging.

•          Ensuring adequacy through very rare extreme weather events is likely to require assets with very low utilisation which may need business case support. The current market arrangements would not be able to support securing a rare asset that could only be used once in ten or twenty years, therefore new market conditions are required to provide alternative funding mechanisms.

•          We welcome the recognition[3] that energy storage with durations more than 200 hours will be required to support the electricity system through periods of excess or insufficient renewable generation that could last for weeks or longer.

•          A common definition of “long duration” to increase investor confidence in the market. There are currently multiple definitions of long-duration energy storage at the present time. There is a need for industry, regulators and Government to work together to define long-duration energy storage, to improve investor confidence in the market. The growing recognition of the importance of multiple storage durations, including much longer durations, is welcome, as this call for evidence defines long as longer than 200 hours, however the industry would benefit from some consistency. 

What is required to build a reliable net zero electricity system?

1.     As the UK moves towards its 2050 net zero target, the Electricity System Operator (ESO) has an ambition to operate a net zero electricity system for short periods of time by 2025, doing this all the time by 2035 in line with government targets.

2.     Analysis commissioned by the ESO[4] indicates that even at times of low renewable output, it will be possible to operate a net zero electricity system in the 2030s, however investment in clean, reliable technologies that are not weather dependent are required to reach this goal.

3.     Today, the majority of GB electricity system flexibility comes from unabated natural gas. When electricity demand is high and there is low output from wind and solar, gas can be used flexibly to create electricity. Achieving a 2035 net zero electricity system requires a controlled reduction in unabated natural gas use. This means that GB will need to find alternative sources of flexibility to fill the gaps when the sun doesn’t shine and the wind doesn’t blow, across durations of days to weeks.

4.     Future extended periods of low renewable generation could be covered by a mixture of natural gas with carbon capture and storage, power plants that use hydrogen, new nuclear power stations, energy storage that can discharge for tens of hours or days, and interconnectors that import to or export from other countries. Extended periods of excess low carbon electricity supply could also be addressed by LDES and interconnectors, as well as flexible technologies such as electrolysers, which use spare renewable electricity to split water and create green hydrogen.

5.     LDES can support the electricity system during sustained periods of low renewable energy output and high demand. However, long-duration weather events (where the weather causes demand to exceed renewable supply) are very rare, so securing the system through LDES for an event likely to only be seen once in ten or twenty years, will need a substantial business case to support it. As this would be used rarely, the current market arrangements we see today would need to change, as under current conditions it wouldn't be financeable.

6.     Decision making in these areas should consider impacts across the whole energy system. For example, building a lot of inflexible, non-weather dependent generation could cause more periods of excess electricity supply unless there are sufficient flexible options such as storage and interconnectors available. This is an example of a potential trade-off that should be considered in the context of keeping costs as low as possible, maintaining energy security and delivering net zero.

7.     The scale of the required build-out of new electricity generation and flexibility is immense. Some of the technologies required for a net zero electricity system still need proving at commercial scale and many have long lead times for delivery. The current barriers to delivering this capacity at scale by 2035should be identified and addressed as soon as possible to reduce and ideally eliminate dependence on unabated gas.

8.     Additionally, more transmission network infrastructure is needed to move energy from supply to demand. Our analysis[5] shows that GB Electricity Transmission System is facing significantly growing reinforcement needs in several regions. Across GB an investment of at least £50 billion in our electricity transmission network alone by 2030, this compares to around £100 billion invested in all energy networks since 1990. This scale of investment within GB’s transmission system could boost economic growth across the country over the next decade but developing this requires urgent anticipatory investment across the supply chain.

Significant volumes of long duration storage will be required to achieve net zero

9.     Electricity storage will need to increase significantly to support the decarbonisation of our electricity system, with as much as thirteen-fold and seven-fold increases in capacity (GW) and volume (GWh) respectively from 2021 to 2050[6]. Capacity here means the maximum power output at any point in time, where volume means the total amount of energy supplied over a period. One GWh corresponds to 1 GW operating for one hour. The relationship between capacity and volume depends on the design of the storage technology. Typically, batteries last for 1-4 hours, whereas other technologies (such as pumped storage) might have a longer duration.

10. Capacities of longer duration storage technologies such as compressed air, liquid air and pumped hydro, are seen at around 3 to 9 GW in 2030, rising to 12 to 17 GW in 2050, across the scenarios that achieve net zero by 2050. In addition, the same scenarios see hydrogen generation capacity (part of a hydrogen based long duration storage system) reaching 18 to 23 GW by 2050[7].

11. Different durations of energy storage provide different benefits to the energy system. Very fast acting storage, typically with durations of up to two hours, respond automatically to the system frequency helping to keep it stable. Longer duration storage can help secure the system over longer periods of high or low renewable generation output. However, non-electrical storage in mechanical systems or in other fuels such as hydrogen or gas is better suited to very long term or inter-seasonal storage.

What are the barriers that need addressing for long-duration energy storage?

12. Higher levels of flexibility will be needed to efficiently manage supply and demand, as we move towards net zero. Currently, not all forms of flexibility have the right route-to-market and market signals required for their delivery. For some flexible technologies, such as Long Duration Energy Storage (LDES) and Demand-Side Response (DSR) from various sectors, investment and market reform are needed in the short-term to ensure delivery in the 2030s and 2040s.

13. Demand Side Response involves businesses increasing, decreasing, or shifting their electricity use – in response to a signal – to help balance Britain’s electricity system. It will be crucial to help manage peak demands, but some demand is inflexible (hospitals, for example, need a constant supply of energy) and needs to be met by sources of supply under all conditions, even when renewable generation output is low.

14. Today the bulk of DSR comes through dispatchable technologies. This refers to an electrical power system, such as a power plant, that can adjust their power output when required. The most common forms of dispatchable sources are coal and nuclear power plants. In the future a much greater share will come from other sources, such as electricity storage and interconnection with other countries and electricity markets.

15. As renewable generation capacity is rising sharply in the future, this dispatchable supply may be required to run for several hours at a time, potentially over several days and so it is important that the energy storage deployed includes a suitable capacity of longer duration technologies. More broadly, this highlights the importance of ensuring these alternative dispatchable technologies are supported now so they are deployed at the required scale in the future and with the necessary carbon removal technology.

16. It should also be recognised that if demand side flexibility is to be deployed at scale, market changes are required. These changes must facilitate flexible tariffs, support innovation and reduce barriers to participation for new market entrants from the Industrial & Commercial sector or in the form of aggregated residential demand. A demand side strategy should identify strategic priorities and incentivise more flexible electricity consumption, as well as long duration storage and early hydrogen uptake.

17. Considerable uncertainty remains, around the policy, market structure and financial support mechanisms needed in the short-term to facilitate LDES deployment later in the 2030s and 2040s.

18. There is also a growing recognition in the importance of defining long-duration energy storage. Consistency is needed to increase investor confidence in the industry. A DESNZ consultation in 2021 defined “long” as longer than 4 hours[8], in comparison to this inquiry which defines long duration as longer than 200 hours.

19. The definitions proposed by AFRY Consulting in their work for DESNZ in 2022 split electricity storage into short-duration (less than 4 hours), medium-duration (4-12 hours), long-duration (12-72 hours) and an unnamed longer duration category of 72-720 hours.[9] In August 2023 AFRY published an article which used updated definitions of short (less than 4 hours), medium (4-10 hours), long (10-168 hours) and ultra-long (above 168 hours)[10].

Creating an electricity market that can deliver net zero

20. Electricity cannot be easily stored, which means that a unit of electricity is more valuable if it is generated close to where it is consumed, while electricity that cannot be transported where it is needed has less value. When the GB electricity system was dominated by fossil fuel plants, generation could be located close to demand and the wholesale electricity market did not need to recognise the locational value of electricity in its price. Instead, to signal locational value, GB uses a static system of network charges[11].

21. These charges can’t respond to the changing weather patterns in real-time. For example, when there is lots of renewable electricity and low demand, prices would ideally be cheaper, and consumers might use more. Not fully reflecting the value of electricity depending on the time and location at which it is generated leads to frequent periods where low-cost electricity can’t be transported to demand, leading to bottlenecks on the electricity system, often referred to as constraints.

22. When this happens, the ESO must procure electricity from a generator more closely located to the area of demand to balance the system, which incurs a higher cost. This often means that renewable electricity generators are asked to turn off in these bottlenecked areas to avoid overloading the system. To-date, these actions have been the most cost-effective option to operate the electricity system securely.

23. Current market design does not provide the signals required. For example, on a windy day, interconnectors can still be importing into GB, which can overload the system and exacerbate constraints. Although interconnectors and storage are a source of supply and flexibility, the current market signals hinder the flow of direction and can lead to further constraints.

24. Addressing these bottlenecks on the electricity network in future will require flexible assets such as interconnectors between countries, batteries, heat pumps, electric vehicles, and industrial demand to shift consumption when and where there is surplus renewable energy. However, all these participants use the GB national wholesale electricity price to plan whether they should generate or consume. Reforming the wholesale electricity price to include a better locational signal will incentivise these flexible assets to soak up spare renewable electricity and reduce costs as a result.

25. There are two broad options for locational wholesale pricing: zonal pricing or nodal pricing. Zonal pricing divides the market into several zones. The price of electricity is dictated by each zone; for example, an area where there is oversupply of generation will be cheaper compared to a zone where there is under-supply. Zonal pricing is currently adopted in Italy and Nordic countries.

26. Nodal pricing is where the market is divided into smaller nodes, and the price of electricity is determined by the cost of generation, and factors in the cost of constraints on the system and the cost with transporting the electricity to where it is required. Nodal pricing has been adopted by some US markets, Singapore, and New Zealand, and is being introduced in Ontario, Canada.

27. The ESO considers that nodal pricing presents the best value for consumers over the long term through a reduction in the overall cost of electricity. Zonal pricing would be preferable to today’s market and would offer consumer benefit, but international examples show that zonal markets tend to move towards nodal markets over time. External analysis commissioned by Ofgem indicates that zonal and nodal pricing could deliver net consumer benefit in Great Britain of £31bn and £51bn respectively between 2025-2040[12].

28. Concerns have been raised about the impact of market changes on GB green investment potential. The ESO has commissioned independent analysis of the investment community, with early indications showing that investors would be comfortable in a zonal or nodal market provided the right package of policy measures is in place to support the transition

29. The Government’s Review of Electricity Market Arrangements (REMA) is assessing a wide range of options for reform, including better locational and time-based signals, and splitting the cost of electricity from the cost of gas

11 September 2023