Long-duration energy storage: get on with it Contents

Chapter 3: Policy for long-duration energy storage

The economics of long-duration energy storage, support mechanisms and strategic reserves

36.Witnesses told us that the economics for long-duration energy storage projects can be challenging.59 The Royal Society noted that “current GB wholesale market arrangements, in which long-term investment decisions and short-term dispatch are largely governed by a single price signal, will not be able to meet [storage] needs.”60 Simon Virley, Head of Energy and Natural Resources at KPMG, set out the challenges for LDES projects to become commercially viable, as including “long lead-in times”, “high capital expenditure requirements” and “a very uncertain market arrangement”. Ongoing uncertainty about the new “policy and regulatory framework” meant companies were “not yet in a position to take a final investment decision.”61

37.Michael Liebreich said that there was “almost no investment going into” storage longer than 48 hours, and that “private companies can do all sorts of things, but they will not just go off and do it voluntarily when the returns are so variable and questionable, so long-distance”. Consequently, “energy strategy” and “public policy” clarity was needed.62 As discussed in chapter 2, Centrica closed its gas storage facility, Rough, because the costs to keep the storage facility open were not covered by the market.

38.There are some existing subsidies that energy storage providers can apply for. The Capacity Market offers all capacity providers a steady, predictable revenue stream, in exchange for which they must deliver energy at times of system stress and provide a fixed, reliable capacity.63 Caroline Still discussed some of these, including energy system services procured by the ESO such as for reactive power. She described how they support some storage assets, noting that “the Capacity Market can make up to 25%” of the revenue for some long-duration storage assets, but that storage assets “rely most heavily on value derived from energy trading—charging and dispatching in the wholesale market and balancing mechanism.”64 However, she noted that “the merchant behaviour in energy trading is not significant enough” to support investment into long-duration storage.65

39.David Surplus, co-founder of B9 Energy Storage Ltd, described the economics from the perspective of a developer as constructing a “revenue stack … you have to get revenues from lots of different people at different times for different purposes … The electricity sector has ancillary services that we can offer. Capacity market payments can come our way, as well as electricity sales … we look to the other support mechanisms, both CapEx and revenue support” that would come from new financial support mechanisms, such as “contracts for difference” or “the new hydrogen storage business model” the Government has said it will introduce.66

40.The Government has recognised additional financial support mechanisms are needed and has pledged to introduce a “policy framework by 2024 to enable investment … with a goal of deploying sufficient storage capacity to balance the overall system.”67 It set out some parameters of a proposed cap and floor scheme in a consultation in January 2024.68

Box 4: Economics and subsidy mechanisms for long-duration energy storage

There is a significant, up-front capital cost to constructing most storage technologies, and subsequent operating costs. To get a return on investment, the incentive is for storage facilities to charge and discharge (“cycle”) as often as they can, maximising their sales of electricity. Without subsidy, storage facilities depend on arbitrage—buying electricity at a low price during surplus and selling it on at a high price during supply shortages. This means storage facilities are incentivised to supply electricity when it is needed, but operators need to balance this against the desire to cycle frequently; storing energy for many weeks in hope of a better arbitrage opportunity may be less profitable than regularly selling electricity with a smaller arbitrage margin. Longer-duration storage is therefore less likely to be profitable, despite being necessary for the grid.

Revenue from arbitrage is difficult to predict and will fluctuate with supply and demand. For these reasons, long-duration energy storage projects can be a risky and uncertain investment, regardless of how important they are for the grid.

There are various proposed mechanisms for supporting long-duration energy storage:

  • Facilities could be operated as a regulated asset base, as is currently being implemented for nuclear power, where electricity users pay for the construction of an asset over time through a levy that suppliers add to consumers’ bills.
  • Contract for difference mechanisms have been used to support offshore wind and involve agreeing a long-term contract with a “strike price” for electricity usually set through a competitive auction. When the storage facility sells electricity into the wholesale market, the subsidy “tops up” the sale price to match the strike price; if the sale price exceeds the strike price, the storage owner pays the difference back. The revenue per MWh thereby becomes predictable.
  • A cap and floor subsidy works in a similar way. An overall revenue cap and floor are agreed in a contract between the storage facility and the Government. If revenues exceed the cap, the extra is returned to the Government. If revenues are less than the floor, the Government pays the difference to the storage facility. The cap and floor mechanism limits risk by ensuring a minimum revenue, while incentivising the storage facility to operate to reach the revenue cap. This has been used to support electricity interconnectors.

It has also been suggested that a component of long-duration storage could be operated as a strategic reserve, which the Government could support through direct ownership or through contracting out the provision of specific storage capacities.

Source: Written evidence from Flow Batteries Europe (LES0019). Royal Society, Large Scale electricity storage (September 2023): https://royalsociety.org/-/media/policy/projects/large-scale-electricity-storage/Large-scale-electricity-storage-report.pdf [accessed 10 January 2024] and Parliamentary Office of Science and Technology, Longer Duration Energy Storage, POSTnote 688, December 2022

41.Alex Campbell, director of Policy and Partnerships at the Long Duration Energy Storage Council, said that “a conventional CfD … is not necessarily the right way to do it”.69 Witnesses generally favoured a cap and floor mechanism. 70 Tim Lord, Head of Climate Change at HSBC, said that “A cap and floor regime, possibly combined with revisions to the capacity market to ensure availability, could potentially be successful”, while saying “I do not think that [CfDs] work for long-duration energy storage … [as] the incentive to deliver at the right time is critical in a way that is not quite the case for renewables.”71

42.Mr Campbell noted that a “further complication is that different types of technology will be better at delivering different types of services”, and that financial support mechanisms should consider ways of supporting storage across different durations.72 For contracts for difference which support renewable generation, the Government has introduced “different pots” of support that different technologies can apply for to support a range of technologies.73 A mechanism like this to support technologies at different readiness levels was proposed by DESNZ.74

43.Alongside the pledge to introduce “an appropriate policy framework by the end of 2024 to enable investment”,75 the Government has published a “minded-to” position for its support for hydrogen storage and transportation, which is to address the “demand risk” for storage and transportation facilities with a revenue floor mechanism. 76

44.It also published a consultation in January 2024 on introducing a separate cap and floor subsidy for LDES technologies.77 Graham Stuart explained: “The consultation seeks views on key design parameters, including what types of storage should be eligible, contract length, allocation process and mitigation of risks, as well as how the scheme should be delivered” in terms of funding and ownership of the scheme. He said the consultation would close in March, receive a response in Summer, and then the Government aimed to “complete the design of the scheme by the end of this year, opening to applications in 2025.” He further explained that the Government was “consulting on two application streams, one for mature technologies and one for more novel technologies.”78 Some of the questions left open in the consultation included the definition of long-duration energy storage (currently minded to be anything longer than 6 hours) and whether to open the scheme to “technologies … that would be eligible for multiple business model support”, such as hydrogen.79

45.However, DESNZ officials were unwilling to set out the scale of funding associated with its subsidies, with Emily Bourne saying it is “hard to talk about scale of funding absent the model design and questions on scope, eligibility, and so on.”80 The Minister agreed with this and noted that “for the interconnector cap and floor … subsidy payments were never made” because with revenue certainty, interconnectors were able to make a profit, although he conceded “that will not necessarily be the case in this instance.”81

46.The economics of long-duration energy storage projects are
challenging and they will require
additional financial support mechanisms. Our witnesses generally favoured a cap and floor mechanism, and we are pleased to see the Government is actively consulting on introducing one. The Government has also stated that it is “minded to” provide a revenue floor for hydrogen transportation and storage but how this will interact with the proposed long-duration energy storage cap and floor subsidy is unclear. Hydrogen and electricity policies should be considered and designed together.

47.The Government should, as a matter of urgency, finalise and set out the details of its business models to support commercial long-duration energy storage. We recommend that cap and floor support mechanisms are designed to support technologies that supply energy across different timescales, recognising the distinction between those that store energy for up to 24 hours and those that can store energy over days and weeks. The Government should clarify which technologies it considers to be eligible for the streams at different readiness levels, and whether the long-duration energy storage support mechanisms will be open to hydrogen. We recommend that hydrogen facilities intended for long-duration storage should be eligible for support and that the Government should resolve any overlaps between its policies.

48.The funding allocated to this business model must be sufficient to support deployment at scale, in line with its aim to balance the overall system, and the Government should outline the scale of funding that will be associated with its support schemes. We recommend that minimum targets for the overall long-duration energy storage capacity the model should support will help ensure support mechanisms are set appropriately to bring forward the necessary scale and range of projects.

49.As discussed in box 3, the economics of storage projects, which aim to maximise their energy sales, may not align with ensuring stored energy is available to produce electricity when it is most needed—for example, keeping a large amount of energy stored and unsold in case of extended periods of low generation. Professor Sir Peter Bruce described “periods with virtually no wind” and “three consecutive years where demand would significantly outstrip the average supply” in their modelling, which looked at 37 years of weather data.82

50.Witnesses told us that it is not clear that markets will deliver every type of storage the grid might need. Michael Liebreich said that: “the private sector will not spontaneously decide that it needs to deliver one or two weeks’ storage. It will invest in things that it can cycle frequently enough, where there is a market, such as arbitrage … or where there are capacity payments.”83 Witnesses, including Daniel Murrant, suggested that there is a “need for some kind of strategic reserve” of energy storage.84 This could insulate the UK against energy supply shocks: David Gray CBE, former Chair of the Gas and Electricity Markets Authority, said that “Ukraine has demonstrated the need for strategic storage”85 and the Royal Society identified one-in-thirty-year low wind events as showing a need for a strategic reserve.86

51.The National Infrastructure Commission made a specific recommendation of a strategic reserve of 25 TWh of electricity generation by 2040.87 Nick Winser, National Infrastructure Commissioner, explained that their report proposed “a long-term, flexible generation resource using hydrogen and gas with CCS [of] 30 TWh … [or] 12 gigawatts of electricity generation”, but also “a strategic energy reserve, distinct from the long-term flexibility” of 25 TWh. He suggested that by 2040 this would be “mainly by hydrogen in store” and supported by “8 TWh of hydrogen storage delivered by 2035.”88 He explained that “you might need a different financial mechanism for securing” a strategic reserve. As the reserve will only be needed infrequently, “remunerating it on its use would not be much use”; instead it would require “a capacity-payment type of product”, distinct from the “[commercial] hydrogen storage for electricity generation … under a cap-and-collar type of arrangement.”89

52.Witnesses suggested different mechanisms to support a strategic reserve. Mr Gray said that one could “combine commercial arrangements to cover the predictable stuff with some sort of mandated requirement for the strategic element of storage”, analogous to how the EU/EEA gas market now mandates winter storage.90 Caroline Still suggested that strategic reserve capacity could be provided through a separate contracting process with storage companies: “a sort of capacity market, except one for strategic reserve.”91 Michael Liebreich suggested several options should be studied, including a “resilience levy” on electricity prices that funded Government procurement of strategic storage, “in the same way that the strategic petroleum reserve is procured.”92 He explained that “there is a role for government because it is related to security and resilience.”93

Figure 3: Level of stored hydrogen across 37 years (Royal Society modelling)

A graph showing level of stored hydrogen across 37 years

Level of stored hydrogen in a 123 TWh store, filled by 89 GW of electrolysers, according to the Royal Society’s modelling of 37 years where hydrogen storage, wind and solar provide the UK’s electricity needs. This illustrates the variability of use of the store and shows that analysing weather patterns over an extended period of time substantially changes the amount of storage needed in the model.
Source: Royal Society, Large Scale electricity storage (September 2023), p 31: https://royalsociety.org/-/media/policy/projects/large-scale-electricity-storage/Large-scale-electricity-storage-report.pdf [accessed 10 January 2024].

53.The Government has not made a clear commitment to a strategic reserve. Stef Murphy stated that “the current business model is not designed to deliver hydrogen strategic storage reserves specifically”, but that “the mechanism could be adapted to do that in future if a decision is taken that we want hydrogen to play that role.”94 Professor Monks said of options for strategic energy storage that “they have to include unabated gas” alongside low-carbon options, but was unable to set out the timing of a decision around the strategic reserve.95 In supplementary written evidence, DESNZ said that it “acknowledged that there could be merit in exploring how a strategic reserve could be used.”96

54.On whether a strategic reserve was needed, the Minister initially said that “the review of electricity market arrangements … is considering how we will maintain capacity adequacy in future … that includes the option of a strategic reserve.” He further agreed that “under a merchant model” hydrogen might be sold in “short cycles, shorter than would be required for a national strategic reserve”, necessitating “Government intervention”. However, he said that “no decision has yet been made on that, but … [we] should come forward to explain whether we will have it or, if not, why we do not think that we need it.”97

55.However, at times during his evidence, he was more sceptical, saying “We do not provide reserves on most of the things in the British economy… we look at whether there is a strategic risk that needs government intervention. Nearly always, the answer is no.” He noted that “we have not created a strategic reserve for gas, even though we are terribly dependent on it”, because “we produce nearly half of it ourselves and have huge LNG capacity, as well as huge imports”, but concluded “if we need [a strategic reserve], we will bring one forward.”98

56.When asked who would be responsible for responding to energy supply shocks, the Minister said that “I would expect my department or its successors to be in the lead.”99 However, he also noted that “different emergencies have different rules and different people with specific responsibility.”100

57.The National Infrastructure Commission has recommended a strategic reserve of 25 TWh of electricity storage by 2040. Since the economic incentive is to cycle storage often, there is a concern over how to ensure commercially operated storage is available when it is needed most. Maintaining reserve storage will likely not be profitable even with a cap and floor subsidy. The Government has not made a clear commitment to developing a strategic reserve or explained whether it thinks green hydrogen or natural gas will fulfil that role. It has not explained how it will respond to generation shortfalls without a strategic reserve, or how it will replace the storage capacity provided by Rough.

58.The Government should commit to, and develop plans for, a strategic reserve of energy storage alongside commercially operated storage on the scale suggested by the National Infrastructure Commission. This could be in the form of facilities owned and operated by the Government or strategic reserve storage capacity could be contracted out. If the Government intends to procure strategic reserve energy storage, it needs to work with industry to set out procurement terms and a scale of funding that will ensure a stable reserve and security of supply.

59.If unabated natural gas is to play a role, the Government must explain how this is compatible with climate change targets, in particular the Sixth Carbon budget and a decarbonised electricity system by 2035. If it will not pursue a strategic reserve, it must explain how the energy system will respond to shortfalls of renewable generation such as those highlighted by the Royal Society.

The role of hydrogen

No-regrets investments for hydrogen

60.Witnesses generally agreed that hydrogen would play a key role in longer-duration energy storage. Daniel Murrant said that “when you get to … seasonal storage, the options become limited” and the requirement for a low-carbon gaseous fuel meant that “hydrogen appears to be the front-runner.”101

61.The Royal Society recommended in its report on large-scale electricity storage that “construction of a large green hydrogen production and storage facility would appear to be a no-regrets option.”102 While explaining that the individual components of electrolysis, storage and conversion to electricity are “well-established technology”,103 Professor Bruce said that “I would want to build a demonstrator … to learn what we need to do when we come to scale it.”104 A single large hydrogen storage cavern would store around 200 GWh.105

62.Daniel Murrant told us that “one of the barriers is getting that first large-scale plant up and running”106, while Timothy Armitage, Hydrogen Systems Consultant at Arup, said “we need demonstrator projects for depleted gas fields and for salt caverns to effectively show the perceived safety case, de-risk this investment and show that it can be scaled up.”107 The Climate Change Committee in its electricity system report urged the Government to “identify a set of low-regret electricity and hydrogen investments that can proceed now.”108

63.Officials from DESNZ did not directly commit to supporting the construction of such a facility, although they did say that they were “keen to identify hydrogen storage projects that will provide the most strategic value.”109 They told us that “at the moment, we do not have a ‘this is the no regrets’ level.”110

64.The Minister told us that the Hydrogen Transport and Storage Networks Pathway “announced an ambition to support up to two storage projects at scale”, and that the aim was that “successful projects will become operational between 2028 and 2032.”111 Stef Murphy said that they expect “our first allocation round … to be for salt caverns” and that they chose to prioritise putting the business model in place “rather than try to run pilots or pick early no-regrets projects to support.” However, she was unable to set out how much storage these initial projects would provide, saying that “we want it to be at scale” but that “I do not have a figure that I can give you … we are trying to … go out to the market and see what projects are out there.”112

65.Although many of the components of a facility used to generate, store and convert hydrogen back into electricity are technologically mature, there are no facilities that do all three at scale in the UK. A large-scale demonstrator could help to “de-risk” investment by serving as a successful model for later projects to follow. The Committee welcomes the announcement that two projects will be supported under the hydrogen transportation and business model, but the scale of these projects is unclear.

66.The Government should, as soon as possible, identify a portfolio of “no-regrets” investments into long-duration energy storage projects. This should include commissioning a pilot project that combines onsite electrolysis, hydrogen storage in salt caverns (on the scale of hundreds of GWh) and electricity generation from hydrogen. Ideally, this should be a part of, or close to, the existing hydrogen clusters. Lessons learned from this project, in terms of what is required in skills, planning and capital/operational costs should be published as the project progresses to develop policy and de-risk future projects. The Government should set out the scale of storage of the projects it intends to support with its hydrogen transportation and storage business model.

Repurposing gas storage for hydrogen

67.We heard evidence from Centrica regarding their ambition to repurpose the Rough gas storage facility to be the world’s largest hydrogen storage facility. Martin Scargill said that construction could be started “within
12–18 months” once a final decision is made.113 As well as being in operation for 35 years as a gas facility, Rough “is adjacent to the largest industrial cluster in the UK—the east coast cluster. When you combine Humberside and Teesside’s industrial emissions today, that is 50% of the UK’s industrial emissions that need to decarbonise.”114

68.Mr Scargill told us that “the upfront costs per unit storage for converting Rough could be as low as half the same amount of long-duration energy storage in salt caverns.”115 sked what policy action would support this repurposing, Mr Scargill said that certainty over the business model was the most important obstacle: “We see that as the main barrier to long-duration energy storage investments, given the high upfront cost and the uncertainty, particularly in the nascent hydrogen market, about where revenues will come from for such a facility.”116 DESNZ officials told us that “Centrica is certainly one of the key stakeholders that we have been talking to.”117

69.We heard that there could be some scope for repurposing gas storage facilities to store hydrogen in the future. This is at a lower technology readiness level than purpose-built salt caverns for storing hydrogen, which have been deployed before, but may be faster to develop. The Government should work with Centrica to understand its proposed project to repurpose the Rough gas storage facility for hydrogen, with a view to determining, by the end of 2024, whether it will support this project.

Box 5: Green, blue and grey hydrogen

Hydrogen is often labelled by the method used in its production.

  • Grey hydrogen is produced by steam methane reforming (SMR), splitting natural gas (CH4)—through heating—into CO2 and hydrogen. This releases greenhouse gases, and so must be phased out for net zero.
  • Blue hydrogen production involves capturing the majority of the CO2 that is produced in the SMR process or autothermal reforming (ATR), a combination of SMR with partial oxidation, and burying it underground, so theoretically would entail a substantial reduction in CO2 emissions relative to grey hydrogen.
  • Green hydrogen production takes a different approach, splitting water with electrolysis into hydrogen and oxygen. If the electricity used to power the electrolysers is derived from a renewable source, then green hydrogen production can be carbon neutral.

Currently almost all global hydrogen production is grey, with low-carbon production accounting for less than 1% as of 2022.118 In net zero forecasts, hydrogen is usually produced through a mix of blue and green methods. The UK currently produces 27 TWh of hydrogen each year, 96% of which is grey hydrogen, with small pilot projects in blue and green production accounting for the rest.119

Source: National Engineering Policy Centre, The role of hydrogen in a net zero energy system (September 2022): https://raeng.org.uk/media/tkphxfwy/the-role-of-hydrogen-in-the-net-zero-energy-system.pdf [accessed 10 January 2024]

Demand and use cases for hydrogen

70.The Government has a target for 10 GW (around 64 TWh)120 of low-carbon hydrogen production by 2030 set out in the 2022 British Energy Security Strategy, with at least half of this green hydrogen.121 This target was described as “both stretching and credible” by Stef Murphy.122

Figure 4: Daily average hydrogen demand over a year in 2035
(CCC modelling)

Figure showing Daily average hydrogen demand over a year in 2035

Variation across the year in daily average hydrogen demand in 2035, according to CCC/AFRY modelling and central scenario. Note that daily average demands for hydrogen for power are volatile while requirements for industry and shipping are more steady. CHP refers to Combined Heat and Power, while CCGT/GT refers to ordinary power generation.
Source: Climate Change Committee, Delivering a reliable decarbonised power system (9 March 2023), figure 5: https://www.theccc.org.uk/wp-content/uploads/2023/03/Delivering-a-reliable-decarbonised-power-system.pdf [accessed 10 January 2024].

71.We heard that hydrogen storage projects are struggling to find private investors because of “demand risk” and “demand uncertainty”; demand for hydrogen is hard to forecast.123 Michael Liebreich explained that for “hydrogen … there are still far too many uncertainties that could be shut down” in terms of what it will be used for, which would help to “focus a lot of minds and resources.”124

72.Mr Liebreich told us that “all sorts of use cases are being proposed [for hydrogen], most of which will not happen.” He set out his “hydrogen ladder” which ranked use cases for hydrogen and emphasised that priority should be given to decarbonising the “700,000 tonnes”125 of hydrogen currently used industrially. Beyond this “there are things that are very difficult to decarbonise without hydrogen, such as aviation fuel, maybe shipping fuels, steel, and long-duration storage.” However, he expressed more scepticism around hydrogen’s use in heating and transport, suggesting the “use cases … will all happen in industrial hubs … [not] in homes.”126 He said that we should “rule out the use cases that do not make sense.”127 The National Infrastructure Commission also stated that hydrogen should be ruled out for domestic heating and kept for strategic energy reserve and decarbonising industry.128

73.Rachel Hay, Head of Energy Supply Decarbonisation and Resilience, Climate Change Committee, said that we need to “identify strategic needs [for hydrogen] … We cannot wait until 2026 for decisions on the role of hydrogen in heating.”129 Claire Dykta, Head of Markets at the Electricity System Operator, told us that delayed decisions lead to uncertainty because there would be “very different outcomes in infrastructure build … from purely a spine for hydrogen through to an extensive hydrogen ecosystem … those options need to be narrowed down”.130

74.We welcome the Government’s ambitious target for 10 GW of clean hydrogen by 2030. However, clarity over the role of hydrogen is needed to decide on key details of storage and transportation infrastructure. Credible forecasts of demand for hydrogen would help investors to commit. We heard that decarbonising hydrogen-using industries and long-duration energy storage are good uses for low-carbon hydrogen, while domestic heating and light transport may be a distraction.

75.The Government needs to clarify the role it sees for hydrogen on the future energy system assuming its target is met, with an indication of how the clean hydrogen produced in 2030 will be used. It should bring forward the decision on whether hydrogen will be used in domestic heating from 2026—we advise against it. Hydrogen use should also be ruled out in locations and for applications that would be prohibitively expensive or without supporting infrastructure.

Availability of electrolysers for green hydrogen

76.Producing at least 5 GW of hydrogen will require substantial additional electrolyser capacity.131 We heard from witnesses that a “key concern” was “procuring electrolysers at scale”, as there is only one manufacturer which produces a large of volume of electrolysers (around 200 MW a year) in the UK. Statera Energy, who are developing a GW-scale electrolyser project, told us that the “US’s Inflation Reduction Act and the EU’s Green Deal” subsidise their domestic electrolyser industries, making it harder for UK companies to compete. Meanwhile “manufacturers outside the UK have already sold most of their capacity for the coming years, largely to their domestic markets.”132 Professor Bruce explained that, while electrolyser technologies can be made more efficient, “scaling up of the supply chain is the more significant challenge”.133

77.Stef Murphy said that the Government was “aware that developers are facing scheduling difficulties caused by lead times for electrolysers and some other key equipment, and we are working with industry on that issue.”134 We also heard about the importance of research into more efficient types of electrolysers such as the “solid oxide electrolysis cell” which could provide a next generation technology.135

78.Meeting hydrogen targets will require substantial additional electrolyser capacity, which could become a serious production bottleneck for hydrogen if not addressed. We heard that there is strong international competition for such capacity, notably from the EU and US which have significant hydrogen subsidies. The Government should set out in its response to this report how it intends to obtain sufficient electrolyser capacity to meet its hydrogen production targets and ensure its approach supports domestic manufacture and research and development.


79.We raised the issue of safety concerns with many witnesses. Industry has significant experience with using hydrogen as an industrial gas and there do not appear to be major safety concerns. Professor Bruce told us that “all energy has some safety risks, but the safety risks for hydrogen used in this sort of scenario [i.e. storage in salt caverns] are relatively small.”136 Martin Scargill told us that:

“The industry needs to deal with safety regardless of where it is stored. The facilities above ground, the pipework and everything else are the same. You are just looking at certainty around the integrity of the structure. We are very confident. Salt caverns are typically built in salt strata about a kilometre down. Rough field is three kilometres down. Part of the overburden structure is an 800-metre layer of salt, so it will not leak, but we have to prove it.”137

80.The actual degree of safety of hydrogen for long-duration energy storage has to be distinguished from the public perception of this safety.138 As Timothy Armitage put it to us, “We cannot just say to people, ‘We’re going to build all of these hundreds of salt caverns under Chester’ … We need to bring them on board and we need clear stakeholder engagement as part of that.”139 He suggested that one way of doing so would be with “demonstrator projects for depleted gas fields and for salt caverns to effectively show the perceived safety case”.140

81.Nick Winser also told us that “the planning process will be eased by having much better discussion with communities, being much more open and more respectful and having much better political, economic and engineering context laid out to communities.”141

82.When raised with DESNZ officials, they told us that they did “not know what public opinion work has been done.”142 Professor Monks said that the Government “will do hydrogen tests in given areas with the consent of the public. Public opinion and working with the public in areas are an important feature of all the parts of the energy transition”.143

83.On public engagement, Graham Stuart said that “it is incumbent on us to get out and tell that story as much as we can … we need to do it in a way that allows us to move at the pace required and yet genuinely engages with people and listens to them.”144 However, he conceded that “I do not think I would claim that we were ahead of the curve in explaining and sharing this with everyone. Typically for a project, it is not government that goes out and does this. It is the developer that has the duty to engage … and some do that better than others.”145

84.Both Martin Scargill and Arnaud Réveillère, Head of Green Storage, Net-Zero Solutions at Geostock, discussed the risk of microbes producing unwanted hydrogen sulphide through chemical activity when hydrogen is stored. This could result in problems such as “embrittlement” for steel and would require treatment at the surface because of its toxicity.146 Mr Scargill told us that “it is very hard to assess its impacts at industrial scale. We know that it will happen, but whether it will impact and by how much is very difficult to say.”147 Mr Réveillère agreed that it “is difficult is to assess the scale of those reactions”.148

85.We heard no evidence to suggest that hydrogen is unsafe, especially when used as an industrial gas. However, the public perception of safety is vital, as negative perceptions of hydrogen projects could prove to be an obstacle in the planning process. We were disappointed that the Government does not seem to recognise this distinction or its crucial role in securing public support, and the Government has work to do to explain the role of hydrogen and its safety profile to the public.

86.DESNZ should commission research in the next six months into the public acceptability of hydrogen storage, in particular in the local communities which are most likely to host it. A public information and dialogue campaign that explains the envisaged role for hydrogen, as well as its safety aspects, is essential and must be a priority for the Government—it cannot be left to developers. The campaign should emphasise the importance and benefits of these energy infrastructure projects for national and economic security, as well as the industry experience with producing and using large volumes of hydrogen today.

87.Some uncertainties remain around some of the operating and safety parameters for hydrogen storage—for example, the potential for microbial production of hydrogen sulphide.

88.The Government should work with UKRI to commission research into the safety aspects of hydrogen storage and transportation, as well as the public acceptability of hydrogen transport and storage facilities.

Medium-duration energy storage technologies

89.As discussed in box 2, there is a wide range of energy storage technologies which can play different roles across different timescales in balancing the grid. This section focuses on technologies best suited to medium-duration storage.

Pumped-storage hydropower

90.Pumped-storage hydropower is a proven technology that currently provides the majority of medium-duration (6–24-hour) storage in the UK—however the 2.8 GW (27 GWh) of storage was “state funded over 60 years ago.”149 We received evidence from pumped-storage developers which suggested a significant pipeline of projects remain at various stages of planning—”7.8 GW across a pipeline of 6 projects with 135 GWh of storage.”150

91.We heard that pumped-hydro “takes about five to seven years to build”,151 but as “the capacity market allows for bids to deliver up to four years in advance”, they cannot receive any subsidy under this mechanism.152 Witnesses explained that due to “high capital costs, long lead times, and lack of revenue certainty”, the policy support was insufficient for more projects to be developed without a cap and floor scheme and that “likely delays in promised policy decisions are jeopardising investment in PSH.”153

92.Pumped-storage hydropower could play a valuable role in partially fulfilling medium-duration storage needs. We heard from the pumped-storage hydropower industry that a pipeline of projects is at various stages of development but will require additional support mechanisms to proceed. Projects could take seven or more years to construct, so final investment decisions are urgent if they are to be ready by 2035.

93.The Government should consult with the pumped-storage hydropower industry to determine the levels of the cap and floor support mechanism that might be needed to support projects that already have planning permission. Projects that can demonstrate their cost-effectiveness should be supported by the long-duration energy storage business model.

Compressed-air energy storage

94.We heard from witnesses that CAES and ACAES can be a valuable medium-duration storage technology (200–500 MW, 6–12 hours). Jim Isherwood, Study Manager at io consulting, told us that there are “well-progressed projects … in California and in New South Wales, Australia” as well as China.154 The Royal Society’s report found that adding CAES to their storage model reduced the average cost of electricity under certain cost and efficiency assumptions: Professor Sir Peter Bruce said that “we would see it as part of the mix, particularly as part of … medium-generation … timescales of perhaps several hours.”.155 We heard that it would play a “complementary” role rather than being in competition with hydrogen;156 Michael Liebreich explained that it is “at a higher cost point because of its complexity … if it is going to serve a role, it will have to cycle multiple times a year.”157

95.As with other long-duration energy storage projects, witnesses expressed a clear sense of urgency. Mr Isherwood said “for us to be able to put ACAES facilities on the grid in time for 2035, next year [2024] would be nice to get this sorted out.”158

96.Advanced compressed air energy storage (ACAES) could store energy on the timescale of 4–24 hours and help to manage medium-term variations in demand. However, as a relatively new technology, cost estimates vary widely. The Royal Society found that the availability of some CAES could reduce overall costs for the energy system under some circumstances if it can cycle quickly. The Government should investigate the costs and efficiencies of large ACAES, for example through researching comparable systems that have been operated in other countries, with a view to supporting them through the long-duration energy storage business model in 2024.

Longer-duration battery chemistries

97.This report has discussed the focus on lithium-ion batteries and their potential usefulness for short-duration storage. The Committee heard evidence around other battery chemistries, such as iron air batteries.159 Professor Pam Thomas, CEO of the Faraday Institution, highlighted “flow batteries, which go into the days to weeks element of storage”, as well as “lithium-air batteries, which are still being researched. Those would be up to hundreds of hours of storage” as having a role to play in medium-duration storage.160

98.There is a significant pilot-scale redox flow battery project of 5 MWh in the UK at the Energy Superhub Oxford, and some flow battery companies based in the UK.161 Matt Harper, Chief Commercial Officer of Invinity Energy Systems, described the project that had been supported “under the longer-duration energy storage programme is one where we will take a 30 megawatt hour vanadium flow battery manufactured in the UK” and provide “regulation and energy-trading services directly on to the electric grid.” This project was described as being in “the development phase” with construction in 2024.162 However, industry witnesses, such as Flow Batteries Europe, raised concerns that “the UK is lacking in manufacturing capacity” compared to countries with large-scale flow battery factories.163

99.Professor Thomas told us “there is no concerted programme on battery storage for the grid”, although some individual research projects were highlighted. She described grid storage as “part of our remit” but there was no “hypothecated funding”, as most of the funding for research comes from the automotive sector.164 The industry has suggested that “more funding of flow battery pilots and demonstration projects is needed.”165 The Government’s recently published battery strategy mentions flow battery projects that were funded under its Long Duration Energy Storage demonstrator scheme, but does not make any new commitments specific to flow batteries.166

100.Lithium-ion batteries have been a central focus of battery development in the UK because of their uses in the automotive sector, but alternative chemistries such as flow batteries or iron-air batteries will be more suitable for medium-duration grid-scale storage across multiple days. The UK has some pilot projects for flow batteries which could be expanded.

101.The Government’s industrial battery policy should outline a clearer role for flow batteries and iron-air batteries that might have grid-scale applications. The Faraday Institution and related battery R&D funding initiatives should be expanded to enable dedicated funding to chemistries that can be useful for grid-scale storage.

102.Early-stage technologies like ACAES, flow batteries, and large-scale thermal storage would benefit from the commission of large-scale demonstration projects and the Government should consider co-funding some large-scale pilot projects with industry.

Incentivising the right mix of technologies for the grid

103.As discussed, there was a consensus among witnesses that “we will use a wide variety of storage technologies, from shorter duration technologies such as … batteries … through to hydrogen storage” to fulfil different roles on the grid.167

104.Owen Bellamy, Head of Power Sector, Climate Change Committee, made a distinction between how technologies should be supported at different phases of the energy transition. There was a difference between those that are ready now and those that “are not commercially available in the marketplace” where the Government needs to “take strategic decisions about supporting these technologies, ensuring they become commercially viable”. Once they are ready, then you can adopt a “technology neutral approach.”168

105.Long-duration energy storage developers suggested that capacity markets and CfDs “do not recognise the significant … ancillary benefits” of long duration storage such as reducing curtailment and that “system requirements should be the priority focus” for policy interventions.169 We were told that these benefits are “not recognised by Power Purchase Agreements” which are negotiated directly between electricity generators and customers. These services are instead “procured separately by National Grid ESO, in a fragmented, ad hoc and piecemeal” manner.170 DESNZ itself told us that long-duration energy storage was limited by “a lack of forecastable revenue streams” in the current market. The Renewable Energy Association told us that a “competitive tender processes for system needs” could support a range of technologies.171

106.Other witnesses pointed out that “in the detail of energy systems, as soon as you specify what you need, it tends to tilt it towards one technology outcome”,172 thus ensuring that the best technologies at providing a given service are incentivised. Caroline Still explained that once you have a “[revenue] floor to de-risk debt … other mechanisms could help to provide an additional upside to attract [investment]” in the necessary technologies, such as “longer-term certain price forecast[s]” for ancillary services such as reactive power and inertia.173

107.Mr Bellamy told us that “the key thing is that the Government need to set out … which standards they expect to be needed in the future and to design a policy framework that enables that to be met. You would not expect the market by itself to deliver that, because security of supply is a property of everything that is happening.”174

108.There is agreement that a mix of technologies is likely to be needed for long-duration energy storage. Hydrogen is likely to be the best solution for storage across multiple weeks and months, but there is a range of competing technologies for storage across hours and days, which can also provide different services to the grid. Long-duration energy storage developers argue that the overall value they provide to the grid in terms of electricity system services is not yet properly incentivised, meaning the revenue stack for projects does not always add up. More information about how the Future System Operator will procure energy system services would encourage investment and healthy competition. Financial support mechanisms and market arrangements should be designed support a mix of storage technologies that provide the services the grid needs.

109.The Government, supported by the Future System Operator and as part of its planning, should incentivise the right mix of technologies by specifying in detail which energy system services it wants to procure, including storage capacity and duration, in line with the Assessment of Likely Need. This should include suggested levels of payment and published modelling should project the likely levels of demand so that revenue streams can be forecast. Energy storage projects that can provide additional services to the grid should be incentivised to do so by receiving additional payments above the “revenue floor” if they are eligible for the commercial long-duration energy storage cap and floor mechanism.

59 Q 37 (Matt Harper, Jim Isherwood and David Surplus)—each of the LODES competition winners made clear that current market arrangements would not support scale-up of their technologies and that the revenue stacks from combining support from existing mechanisms and the arbitrage markets they could access would not make them profitable.

60 Written evidence from Royal Society (LES0014)

61 Q 46 (Simon Virley)

62 Q 71 (Michael Liebreich)

63 NationalgridESO, ‘Capacity Market Overview’: https://www.emrdeliverybody.com/CM/overview.aspx [accessed 10 January 2024]

64 Q 5 (Caroline Still) The balancing mechanism refers to the auctions run by the Electricity System Operator to balance supply and demand on the GB electricity network. See ESO, ‘What is the Balancing Mechanism?: https://www.nationalgrideso.com/what-we-do/electricity-national-control-centre/what-balancing-mechanism [accessed 10 January 2024]

65 Q 5 (Caroline Still)

66 Q 37 (David Surplus)

67 Written evidence from Department for Energy Security and Net Zero (LES0015)

68 Department for Energy Security and Net Zero, Long duration electricity storage consultation: Designing a policy framework to enable investment in long duration electricity storage (January 2024): https://assets.publishing.service.gov.uk/media/659bde4dd7737c000ef3351a/long-duration-electricity-storage-policy-framework-consultation.pdf [accessed 10 January 2024]

69 Q 48 (Alex Campbell)

70 Q 91 (Emily Bourne), written evidence from The Quarry Battery Company (LES0005), Rt Hon Brian Wilson CBE (LES0008), Drax Group plc (LES0013), Association for Renewable Energy and Clean Technology (REA) (LES0021), Scottish Renewables (LES0022) and Foresight Group (LES0039). DESNZ also said it was the most favoured model by respondents to its consultation.

71 Q 48 (Tim Lord)

72 Q 48 (Alex Campbell)

73 Brodies, ‘The Contracts for Difference Scheme: Proposed Pot Restructure’ (22 May 2020): https://brodies.com/insights/renewable-energy/the-contracts-for-difference-scheme-proposed-pot-restructure/ [accessed 10 January 2024]

74 Department for Energy Security and Net Zero, Long duration electricity storage consultation: Designing a policy framework to enable investment in long duration electricity storage (January 2024): https://assets.publishing.service.gov.uk/media/659bde4dd7737c000ef3351a/long-duration-electricity-storage-policy-framework-consultation.pdf [accessed 10 January 2024]

75 Q 83 (Emily Bourne)

76 Q 91 (Stef Murphy) and Department for Energy Security and Net Zero, Hydrogen transport and storage infrastructure: minded to positions (August 2023): https://assets.publishing.service.gov.uk/media/64ca0e6c5c2e6f0013e8d92a/hydrogen-transport-storage-minded-to-positions.pdf [accessed 10 January 2024]

78 Q 115 (Graham Stuart MP)

80 Q 93 (Emily Bourne)

81 Q 115 (Graham Stuart MP)

82 Q 9 and Q 10 (Professor Sir Peter Bruce)

83 Q 75 (Michael Liebreich)

84 Q 5 (Daniel Murrant)

85 Q 39 (David Gray CBE)

86 Royal Society, Large Scale electricity storage (September 2023): https://royalsociety.org/-/media/policy/projects/large-scale-electricity-storage/Large-scale-electricity-storage-report.pdf [accessed 10 January 2024]

87 Strategic energy reserve in National Infrastructure Commission, Energy and Net Zero (December 2024), recommendation 6: https://nic.org.uk/themes/energy-netzero/#tab-headline-recommendations [accessed 10 January 2024]

88 Q 53 (Nick Winser CBE)

89 Q 58 (Nick Winser CBE)

90 Q 42 (David Gray CBE) Storage of gas is mandated by Regulation (EU) 2022/1032 of the European Parliament and of the Council of 29 June 2022 amending Regulations (EU) 2017/1938 and (EC) No 715/2009 with regard to gas storage, OJ L 173/17, 30 June 2022

91 Q 5 (Caroline Still)

92 Q 71 (Michael Liebreich)

93 Ibid.

94 Q 94 (Stef Murphy)

95 Q 94 (Paul Monks)

96 Written evidence from Energy Security and Net Zero (LES0046)

97 Q 109 (Graham Stuart MP)

98 Q 116 (Graham Stuart MP)

99 Q 108 (Graham Stuart MP)

100 Q 122 (Graham Stuart MP)

101 Q 4 (Daniel Murrant)

102 Royal Society, Large Scale electricity storage, p 83

103 Q 12 (Professor Sir Peter Bruce)

104 Q 18 (Professor Sir Peter Bruce)

105 Royal Society, Large Scale electricity storage, p 61

106 Q 7 (Daniel Murrant)

107 Q 30 (Timothy Armitage)

108 Climate Change Committee, Delivering a reliable decarbonate power system (9 March 2023), chapter 2, section 3 (a): https://www.theccc.org.uk/wp-content/uploads/2023/03/Delivering-a-reliable-decarbonised-power-system.pdf [accessed 10 January]

109 Q 90 (Stef Murphy)

110 Q 86 (Stef Murphy)

111 Q 112 (Graham Stuart MP)

112 Q 113 (Stef Murphy)

113 Q 61 (Martin Scargill)

114 Ibid.

115 Q 62 (Martin Scargill)

116 Q 61 (Martin Scargill)

117 Q 90 (Stef Murphy)

118 International Energy Agency, ‘Hydrogen’: https://www.iea.org/energy-system/low-emission-fuels/hydrogen [accessed 10 January 2024]

119 National Engineering Policy Centre, The role of hydrogen in a net zero energy system (September 2022): https://raeng.org.uk/media/tkphxfwy/the-role-of-hydrogen-in-the-net-zero-energy-system.pdf [accessed 10 January 2024]

120 DESNZ explain in supplementary evidence how this figure is arrived at. It depends on assumptions such as how much of the hydrogen is blue (produced with CCS and natural gas) and green (electrolytic production.), as well as the capacity factors for the production of blue and green hydrogen. The assumption here is based on a 50/50 split between electrolytic and CCUS hydrogen, with a 95% capacity factor for blue hydrogen and a 50% capacity factor for the electrolysers, based on the assumption that they are operated flexibly. Written evidence from Department for Energy Security and Net Zero (LES0046)

121 HM Government, British Energy Security Strategy (April 2022): https://assets.publishing.service.gov.uk/media/626112c0e90e07168e3fdba3/british-energy-security-strategy-web-accessible.pdf [accessed 10 January 2024]

122 87 (Stef Murphy)

123 Q 90 (Stef Murphy)

124 76 (Michael Liebreich)

125 700,000 tonnes of hydrogen is approximately 23.1 TWh according to the conversion factor at Carbon Commentary, ‘Some rules of thumb of the hydrogen economy’: https://www.carboncommentary.com/blog/2021/6/11/some-rules-of-thumb-of-the-hydrogen-economy [accessed 10 January 2024]and Hydrogen Insight, ‘Hydrogen Ladder’ (23 October 2023): https://www.hydrogeninsight.com/policy/hydrogen-ladder-seven-h2-applications-relegated-in-updated-use-case-analysis-but-three-promoted/2-1-1540086 [accessed 10 January 2024]

126 Q 68 (Michael Liebreich)

127 Q 79 and Q 80 (Michael Liebreich)

128 Edie, ‘National Infrastructure Commission: UK should rule out hydrogen for some heating’ (18 October 2023): https://www.edie.net/national-infrastructure-commission-uk-should-rule-out-hydrogen-for-home-heating/ [accessed 10 January 2024] and National Infrastructure Commission, ‘Technical annex—Hydrogen heating’ (20 October 2023): https://nic.org.uk/studies-reports/national-infrastructure-assessment/second-nia/hydrogen-for-heat-annex/ [accessed 10 January 2024]

129 Q 101 (Rachel Hay)

130 Q 58 (Claire Dykta)

131 According to RenewableUK, just 4.2 MW of green hydrogen electrolyser capacity has been installed in the UK as of 2023. Around 1.4 GW of capacity is at an “early stage of development” with 69 MW under construction, approved, or in the planning system. See Renewable UK, ‘Planning system needs overhauling to enable green hydrogen projects to go ahead’ (29 March 2023): https://www.renewableuk.com/news/636005/Planning-system-needs-overhauling-to-enable-green-hydrogen-projects-to-go-ahead-.htm [accessed 10 January 2024]

132 Written evidence from Statera Energy (LES0023)

133 Q 14 (Professor Sir Peter Bruce)

134 Q 89 (Stef Murphy)

135 Q 36 (David Surplus)

136 Q 14 (Professor Sir Peter Bruce)

137 Q 62 (Martin Scargill)

138 It is also important to distinguish between hydrogen stored in salt caverns and processes at industrial sites and hydrogen for heating homes: our focus is on the former.

139 Q 27 (Timothy Armitage)

140 Q 30 (Timothy Armitage)

141 Q 53 (Nick Winser)

142 Q 96 (Stef Murphy)

143 Q 96 (Professor Paul Monks)

144 Q 113 (Graham Stuart MP)

145 Q 121 (Graham Stuart MP)

146 Q 67 (Arnaud Réveillère). Potential harms caused by unwanted hydrogen sulphide production are set out in Christina Hemme and Wolfgang van Berk, ‘Potential risk of H2S generation and release in salt cavern gas storage’ Journal of Natural Gas Science and Engineering, vol 47 (2017): pp 114–23: https://doi.org/10.1016/j.jngse.2017.09.007

147 Q 65 (Martin Scargill)

148 Q 67 (Arnaud Réveillère)

149 Written evidence from the British Hydropower Association (LES0038)

150 Written evidence from the British Hydropower Association (LES0038) and Scottish Renewables (LES0022) gave estimates from a range of developers. Individual projects were cited by SSE (LES0003), Quarry Battery Company Ltd (LES0005), Drax Group plc (LES0013), RheEnergise Limited (LES0025) for novel PSH, and Foresight Group LLP (LES0039)

151 Q 84 (Emily Bourne)

152 Q 41 (Ita Kettleborough)

153 Written evidence from SSE (LES0003) and Scottish Renewables (LES0022)

154 Q 32 (Jim Isherwood)

155 Royal Society, Large Scale electricity storage, chapter 8.4

156 Q 63 (Arnaud Réveillère)

157 Q 74 (Michael Liebreich)

158 Q 38 (Jim Isherwood)

159 Written evidence from Form Energy (LES0018)

160 Q 20 (Professor Pam Thomas)

161 Q 32 (Matt Harper)

162 Q 31 (Matt Harper)

163 Written evidence from Flow Batteries Europe (LES0019)

164 Q 24 (Professor Pam Thomas)

165 Written evidence from Flow Batteries Europe (LES0019)

166 Department for Business and Trade, UK Battery Strategy (November 2023): https://assets.publishing.service.gov.uk/media/656ef4871104cf000dfa74f3/uk-battery-strategy.pdf [accessed 27 February 2024]

167 Q 83 (Professor Paul Monks)

168 Q 106 (Owen Bellamy)

169 Written evidence from Drax Group plc (LES0013)

170 Written evidence from the Renewable Energy Association (LES0021)

171 Ibid.

172 Q 75 (Michael Liebreich)

173 Q 5 (Caroline Still)

174 Q 106 (Owen Bellamy)

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