EDF – Written evidence (LES0026)

Summary

1.               EDF is the UK’s largest producer of low carbon electricity. EDF operates low carbon nuclear power stations and is building the first of a new generation of nuclear plants. EDF also has a large and growing portfolio of renewables, including onshore, offshore wind and solar generation, and energy storage. With around six million electricity and gas customer accounts, including residential and business users, EDF aims to help Britain achieve net zero by building a smarter energy future that will support delivery of net zero carbon emissions, including through digital innovations and new customer offerings that encourage the transition to low carbon electric transport and heating.

2.               EDF welcomes the opportunity to provide evidence to the committee. Variable renewables, especially wind, are expected to provide the backbone of the electricity system and the anticipated huge growth in output from variable renewables will require support from low-cost, low-carbon flexibility. In that context long-duration storage, potentially in a variety of forms, is likely to play an important role in the future energy system, helping to ensure security of supply. While battery storage is currently the leading commercial option for providing short duration storage in the electricity sector, there are a range of technology options and approaches available for providing medium and longer duration storage. Research, development and demonstration of these emerging technology options will be important and, as an example of this, EDF has examined as a future option the use of Compressed Air Energy Storage (CAES) at one of our gas storage sites, working with partners io consulting and Hydrostor. EDF is also working on low carbon hydrogen, which is capable of providing very long duration storage to the energy system.

3.               In considering the future role of long duration storage in the energy system, and the electricity sector it is important to place this in the context of a wide range of generation and technology options which can help to provide either firm low carbon power or flexible dispatchable power to the electricity system. These options include nuclear power, gas with carbon capture and storage, demand side response, interconnection, biofuels (also with carbon capture) and low carbon hydrogen – as well as those options which are typically defined as electricity storage technologies. An optimal future electricity mix is likely to require substantial additional capacity from a range of different flexible technologies (including storage) as well as firm generation such as nuclear power that reduces the total additional system flexibility requirements.

4.               This presents government with a complex challenge when seeking to design a policy landscape which will deliver a suitable technology mix. EDF considers that a strong carbon price, consistently applied, will be very important for sending the right signals for decarbonisation and this should be accompanied by reform of the Capacity Market to provide stronger signals for future investment in low carbon capacity. These interventions have the clear benefit of being technology neutral, facilitating competition between different approaches and avoiding market distortions. However, we also recognise that these approaches may need to be accompanied by some more technology specific interventions, where these can be justified. Such interventions should be designed to minimise impacts on wider markets and other technology options.

How much medium- and long-duration energy storage will be needed to reach the Government’s goal of a fully decarbonised power grid by 2035 and net zero by 2050, and by when will it need to be ready?

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

5.              Different analyses can apply varying definitions of medium or long duration storage. The government’s 2021 Call for Evidence on Large-scale Long-duration Storage defined long duration storage as anything providing over 4-hours duration of energy[1]. EDF considers it is more useful to classify storage into broad categories of short duration (1-4 hours), medium duration (typically around 4-24 hours) and longer duration options. Even within the longer duration category there may be distinctions between options which could provide energy over up to several days and those which can provide it over many days, weeks and even seasons.[2]

6.              Very long duration storage may provide an important security of supply role by being able to provide firm power to the electricity system during more extended periods of low output from renewable generation (primarily wind and solar). The German term “dunkelflaute” is widely used to capture this concept and examination of weather patterns indicates that periods of up to 2 weeks can occur with substantially below average output from renewable sources[3]. Where such periods coincide with high electricity demand (eg during mid-winter) the reliance of the electricity system on dispatchable options and sources of stored energy would be greatest.

7.              With respect to the scale of future storage requirements, there is no established consensus on the amount of short, medium or long duration storage which may be needed to support the Government’s goal of a fully decarbonised power sector by 2035 and net zero by 2050, with different analyses reaching different conclusions. This reflects the wide range of technology options and electricity mixes which could be used to decarbonise the power sector, and the uncertainties around the optimal mix of different options.

8.              To illustrate a range of potential outcomes, the chart below compares analyses from National Grid ESO’s Future Energy Scenarios (FES), the Department for Energy Security and Net Zero (DESNZ) and energy consultants AFRY for the Climate Change Committee, looking at potential capacity in the year 2035. While the volumes of storage vary considerably by scenario, a key point to note is that, in all scenarios, the anticipated volume of storage capacity by 2035 is substantially greater than that operational today – reflecting both the growth in electricity demand which is expected between now and 2035 and the increased variability of generation output. Much of that storage capacity is likely to be of a short duration nature, reflecting the benefits of this option in managing shorter-term fluctuations in supply and demand, addressing network constraints and the stronger commercial case for investment in short duration storage which exists today.

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

9.              The extent of future requirement for dispatchable generation and storage options will be significantly affected by a very wide number of factors – the chart above illustrates that different analyses have reached different conclusions in this area. As noted above, all scenarios envisage a large growth in the requirement for storage relative to capacity on the system today. We consider the most significant variables, when considering how substantial that growth in capacity will prove to be, are:

• Total electricity demand. While almost all analyses envisage substantial increases in demand by 2035 (and further by 2050) linked to greater electrification of the economy, the extent of this varies significantly – with projected electricity demand for 2035 varying from 377-495TWh across ESO and DESNZ scenarios (up to c.60% more than today’s c300TWh) and demand in 2050 varying from around 500 to ~900 TWh in different scenarios.
• The extent of nuclear capacity in the electricity mix – as nuclear provides firm year-round power, independent of weather patterns, higher volumes of nuclear generation within the electricity mix will reduce the overall system requirement for additional storage and dispatchable power.
• The extent to which flexible demand side response technologies have been deployed – in particular the extent to which electric vehicles are smartly charged (in line with peaks in renewable output) and vehicle-2-grid options have been adopted will substantially influence the scale of requirement for dispatchable generation and storage.
• Levels of interconnection with other electricity markets, and the extent to which these markets can provide power to GB at times of low renewable output - and with carbon emissions embedded in imported energy valued appropriately.
• The extent of the future role of low carbon hydrogen in providing peaking power to the electricity system. Low carbon hydrogen is itself a form of very long duration storage – if deployed at scale it may significantly reduce the requirement for other forms of longer duration storage capacity.

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

10.              Nuclear can play a significant role in the energy system as a source of predictable low carbon non-weather dependent power available in large volumes. At the energy system level, a significant role for new nuclear power in the electricity mix is likely to deliver a lower overall system cost.

11.              By providing more energy to the system when it is needed, nuclear power reduces the scale of additional flexible or storage capacity required to absorb surplus renewable generation and re-supply it to the system at a later date. Nuclear also provides vital inertia to the electricity system and an optimal level of nuclear also reduces the scale of network investment which would otherwise be required to support alternative generation capacity mixes. These benefits have been quantified in a recent study by energy analysts Aurora. Their independent assessment estimated that total power system costs are between ~£36-£65bn lower over the period 2022-2050 in a system with significant investment, materially above the levels which would be delivered by existing and under development new nuclear capacity[4].

12.              It is also worth noting that this Aurora analysis is restricted to the power sector benefits of nuclear. In addition to generating electricity, nuclear stations also produce provide the opportunity of very large volumes of low cost, low carbon heat. Historically this heat has not been utilised in the UK. However, in the net zero context, there are a range of future opportunities to take advantage of it, through for example improving the efficiency of hydrogen production, providing energy for Direct Air Capture processes, for synthetic fuels production, heat storage, and to support other industrial and commercial heating requirements.

13.              With respect to the use of natural gas with carbon capture and storage (CCS), increased capacity of this option would also reduce electricity system requirements for storage or other forms of low carbon flexibility. However, the costs of this option are today relatively uncertain, as is the ability to retain very high CO2 capture rates through flexible operation. Use of gas with CCS also comes with residual greenhouse gas emissions, both in relation to incomplete carbon capture and due to supply chain emissions associated with the exploration, extraction and transportation of natural gas, which can be significant but are today generally not subject to any form of carbon pricing. EDF considers that the full carbon costs associated with gas plus CCS power should be accounted for and that doing so would highlight a need to materially reduce the role of gas in the electricity mix to meet net zero objectives – as well as to support a broader energy policy objective of reducing dependence on imported fossil fuels.

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

14.              Greater grid interconnectivity is in principle of obvious benefit to security of supply and may help to reduce the national requirement for storage or flexible capacity. However, uncertainties will always remain around how much reliance can be placed on interconnectivity. For example, Dunkelflaute type weather conditions could well occur simultaneously across large parts of the European continent and other fuel supply, technical generation constraints or indeed political circumstances could also impact on the scope for interconnector imports to the UK at times of system stress. These considerations suggest that there are likely to be significant limits on the extent to which future governments are willing to rely on interconnection to deliver security of supply.

What role could demand-side management of electricity play in reducing the dependence on storage?

15.              Demand Side Response is expected to play a growing role in the electricity, particularly from electric vehicles, which are likely to become by far the single largest source of demand side flexibility. This will be both in the form of smarter control of EV charging (managing charging times to avoid peak demand periods / coincide with periods of strong renewables supply) and potentially through vehicle-2-grid approaches, which in principle could provide a very large source of additional storage capacity to the electricity system. If widely adopted, V2G would materially reduce the system requirement for other forms of storage, both of the shorter and medium-longer duration varieties.

16.              However, both the extent to which customers will smartly charge their vehicles, and the economic attractiveness and customer acceptance of V2G, remain highly uncertain and overall, even with relatively large utilisation of DSR from these options, there is likely to be a continuing requirement for substantial dispatchable capacity, including some forms of long duration storage. The level of uncertainty in this area can be illustrated by reference to the ESO Future Energy Scenarios, in which the contribution from electric vehicle related flexibility varies from 2-27 GW in 2035 and from 12-29 GW in 2050[5].

What impact will future climate change have on demand – for example, how much will the seasonal differences in power demand change with warmer winters and greater use of air conditioning?

17.              Climate Change seems likely to deliver changes in GB electricity demand patterns, arising from hotter summers, increasing air conditioning demand in summer and somewhat milder, yet wetter winters – however this conclusion is obviously subject to uncertainty on exactly how climate change will impact long-term weather conditions in the UK.

18.              Broadly speaking, however, EDF anticipates that GB winter demand will remain substantially larger than summer demand and that therefore any benefits of long duration storage will typically be most evident in winter and specifically in helping to meet demand during extended wind lulls. Some relevant considerations in this context are that:

• While summer demand from air-conditioning will rise, increased solar capacity is likely to be able to meet much or all of this demand on a daily basis, given the strong relationship between solar output and AC demand. Short duration flexibility options such as batteries can help manage these daily summer demand patterns.
• Increased electrification of heat will increase winter demand relative to summer demand.
• Wind is likely to be a major source of generation in the future GB mix, and wind output is higher in winter months, mitigating to some degree the requirement for seasonal storage.
• As well as changes to demand, a system dominated by variable renewables must also be resilient to any changes in weather patterns associated with climate change. Changes to weather patterns would affect flexibility requirements. Since we expect the GB energy system to be wind-dominated, the incidence and severity of extended low wind periods will be an important issue to characterise. We welcome initial work in this area[6] - and recommend it is maintained as a priority.

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

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

What are the technology readiness levels for these energy storage technologies?

19.              There are a very wide range of different storage technologies with different characteristics, scales, costs, efficiencies, durations, technological maturity and wider pros and cons. These have been discussed in a number of analyses.[7]

20.              At present lithium-ion batteries have established a dominant position in the market for short duration storage and substantial new lithium battery capacity is already being developed and deployed in the GB electricity market. These projects typically provide a variety of grid related services to the market, alongside storage - for example, responding instantly to grid fluctuations. Given the extensive scale of global manufacturing and wider research and development activities being undertaken (as noted in the UK Battery Strategy Call for Evidence[8]) to improve battery performance for electric vehicles, consumer devices and other sectors, as well as energy, EDF’s expectation is that batteries will remain the dominant option for shorter duration storage (daily cycling) in the foreseeable future and, as noted above, we expect to see substantial growth in the deployment of short duration battery storage in the coming decade.

21.              With respect to medium duration storage options there are a broad range of technology options, including established approaches such as pumped hydro and emerging options such as compressed air energy storage (CAES), liquid air energy storage (LAES) and gravitational storage,

22.              EDF has participated in a research project, working with io consulting and Hydrostor, to examine the potential for CAES at one of our gas storage sites (Hole House) in Cheshire. The project was supported by the government’s Long Duration Energy Storage (LODES) innovation programme – although it should be noted that with the potential to charge/discharge energy over roughly one day, CAES is perhaps better described as a medium duration storage technology The research project established that CAES was a technically viable storage technology for deployment at the site, but that current energy market and ancillary service market revenues would be insufficient to develop a commercially attractive project. This position is by no means unique to compressed air storage options and we consider that most medium and long duration storage options would require some form of market support to be commercially viable in the GB electricity system at the present time.

23.              Of the available options for providing longer duration storage, hydrogen (and its derivatives such as ammonia, e-methanol or other hydrogen derived synthetic fuels) is arguably in a relatively unique position in that it can provide extremely long duration storage (over weeks, months and seasons). The costs of storing hydrogen (eg in geological options such as salt caverns) and transporting it via pipeline, are also likely to be relatively modest enhancing the potential attractiveness of hydrogen as an option for long duration storage, although the round trip efficiency of hydrogen is lower than many alternative storage options.

24.              As well as potentially providing long duration storage to the electricity system, hydrogen can be used to support the decarbonisation of many hard to abate sectors of industry and transport. This creates the potential for a broader “hydrogen economy” or sector in which low carbon hydrogen is produced at scale to support a range of end uses, with accompanying network and storage assets. In this scenario hydrogen may prove to be the most competitive and flexible of long duration storage options.

25.              Today, the use of low carbon hydrogen as an energy carrier/vector is at an early stage of development and substantial support to the hydrogen sector will be needed over many years to drive uptake and deliver the economies of scale necessary to bring the costs of low carbon hydrogen production down to a level where it can realise its substantial potential.

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

26.              Electrolytic hydrogen produced from very low carbon generation sources is the lowest carbon and most net zero compliant form of hydrogen and EDF therefore considers that this form of hydrogen should become the dominant source of low carbon hydrogen over time.[9] There is no doubt that a significant hydrogen sector, supporting the decarbonisation of a range of sectors and based predominantly on electrolytic hydrogen, will require very substantial amounts of low carbon generation capacity to support it. Given this, EDF considers that:

• Government policies should continue to support the large-scale growth of renewable generation, including through frameworks which facilitate investment as well as reforms to speed up the roll out of network infrastructure and deliver faster planning decisions.

• New nuclear generation should also be similarly supported at scale, alongside renewables. New nuclear can play an important role in low carbon hydrogen production through the use of low carbon heat to improve the efficiency of electrolytic hydrogen production using solid oxide electrolysis.

• Policies to enhance energy efficiency and support the smart flexible management of demand should also be pursued in parallel with vigour

• Direct electrification should be pursued as the preferred decarbonisation option where technically possible and economically desirable, leaving hydrogen as the key fuel for harder to electrify sectors including some parts of industry and heavy transport.

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

27.              Assuming market and carbon pricing signals treat forms of thermal storage consistently with electricity storage options, thermal storage options could both compete with and complement electrical storage options in the future energy sector.

28.              Greater penetration of heat pumps could see some utilisation of buildings or heat batteries with Time-of-Use Tariffs as a form of thermal storage to help reduce peak demands (and network requirements) in the electricity sector (eg through pre-heating of well insulated buildings) – although these approaches would generally provide short-medium duration storage.

29.              Studies have also explored the concept of integrating thermal storage in nuclear power plants by filling a thermal store (a phase change material) using nuclear heat, then discharging the stored heat through a secondary steam turbine to generate electricity, when it is valuable to do so[10]. By storing nuclear heat directly, this concept is more efficient than other thermal electricity storage technologies, which require another conversion step, with associated costs and losses. There are theoretically also opportunities for using the heat for other nuclear energy hub concepts, as discussed above.

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

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

30.              At present the main policy interventions which support the deployment of storage technologies are:

• The carbon price arising from the UK Emissions Trading Scheme (UK ETS) and the additional £18/tonne top up to the power sector carbon price provided by Carbon Price Support. The carbon price supports lower carbon storage options by ensuring that fossil fuel options, which currently provide the majority of storage in the energy system, are charged appropriately for the emissions they create.

• The Capacity Market.

31.              In principle EDF considers both carbon pricing and the Capacity Market are suitable policy interventions for supporting storage as they are technology neutral mechanisms which give equal levels of support to a wide range of different lower carbon options, thus avoiding the market distortions that can arise from technology specific interventions. This is particularly important given the very wide range of options for providing storage and/or firm dispatchable capacity to the electricity system.

32.              However, reforms to both carbon pricing and the Capacity Market are needed to deliver stronger signals in favour of lower carbon options. With respect to the UK ETS, the price of allowances has fallen substantially over the past year, thus providing a much weaker signal in the wholesale electricity market, and one which is far below both what the UK government’s own economic guidance and that of almost all external analyses consider is the price of carbon required to stimulate a widescale switch to low carbon alternatives. EDF considers that either linkage with the EU ETS, or reforms to the UK ETS (such as adoption of a supply adjustment mechanism) are needed to address this issue.

33.              With respect to the Capacity Market, EDF would support changes to this scheme to provide more support for new low carbon capacity – there are a range of options for delivering this, including separate auctions or clearing prices for low carbon capacity. These reforms are being considered within the government’s Review of Electricity Market Arrangements (REMA) and EDF would like to see the government’s forthcoming consultation on REMA set out a clear path and timetable for progressing changes of this kind.

34.              Government is also considering a range of other design changes to the Capacity Market separate to the REMA process. Some of these changes could benefit medium and long-duration storage projects, including the potential introduction of a later first Delivery Year for projects with long build times (such as new build pumped storage hydro and other new storage technologies). EDF welcomes Government’s plan to develop these design changes further in 2024.

35.              The combination of a reformed Capacity Market and a much stronger UK carbon price have the potential to significantly improve the business case for a wide range of storage options. However, EDF recognises that, in addition to these policies, there may be a case for some time limited dedicated interventions, such as a cap and floor contract or dispatchable power agreement, for certain early projects in certain technology areas of strategic importance. The case for such technology specific interventions may be linked to the early-stage nature of the technology or the very large-scale of capital expenditure involved. However, in general EDF considers that government should seek to limit such interventions where possible - and should use strong carbon pricing and a reformed Capacity Market as fundamental aspects of its policy framework for ensuring there is sufficient low carbon capacity to deliver electricity system security of supply. Where technology specific interventions are deployed, the design of these should be considered carefully to minimise wider market distortions and avoid negative impacts on the business case for shorter duration storage.

How good is the economic case for long-duration energy storage? What policies and market structures need to be put in place to make the business case viable?

36.              The current economic case for long-duration storage can be challenging for many options at present due to a range of factors – including:

• Competition from a range of alternative dispatchable generation options, including in particular unabated natural gas generation. A clear and consistent policy direction, with associated policy measures, to gradually reduce the role of unabated gas in the electricity mix will be needed to drive uptake of alternative lower carbon options.
• Limitations on revenues due to low numbers of storage charge/discharge cycles.
• Technological immaturity of some options, with growth needed to deliver economies of scale, and help reduce the cost of capital associated with investment.
• High up-front capital expenditure requirements for many options.
• Insufficient valuation of low carbon benefits arising from the UK carbon price – see comments above.
• Uncertainty in the future design and thus revenues from the Capacity Market.
• Uncertainty in the future revenues from ancillary services used by National Grid as the Electricity System Operator (ESO). These services form part of the revenue stack for flexible assets, so their future design and potential revenues associated with them can influence the financial models and investment case for storage projects.

In summary, strengthening the UK carbon price, reforming the Capacity Market to provide more support for low carbon firm capacity and addressing current uncertainties relating to the ancillary system services which storage options can provide, all have the potential, in combination, to materially improve the business case for investment in medium and longer duration storage options. These approaches have the benefit of providing consistent, technology independent investment signals, in ways which should not distort markets or competition between different flexibility and storage options.

11 September 2023