RheEnergise Ltd – Written evidence (LES0025)


Company - RheEnergise is a UK clean-technology company. Our HD Hydro storage system is low-cost, energy efficient and fast to develop and construct. Rather than using water, it uses an environmentally benign fluid which is 2½ times denser than water, and which can provide 2½ times the power when compared to a conventional low-density hydro-power system. It means that HD Hydro can be deployed beneath the surface of hills rather than mountains, so opening up massive opportunities in the UK and around the world. Our work to date has received grant support from the UK Government and from private investors.


We would welcome the opportunity to give oral evidence to the Committee.


Q1: 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?


At least 30GW of Low Carbon Energy Storage (LDES) is sited by the UK Government as the minimum required. Jacobs gives a figure of 40GW and 5TWh, Aurora estimates 46GW, with a minimum of 24GW of LDES. National Grid ESO’s future energy scenarios predict a minimum need of >33GW and up to 52GW.


DeltaNPD’s analysis indicates that ~15% of total energy storage capacity is required in the short duration (0-4 hours) category, 70% in the medium duration category (4-24 hours) and 15% for >24 hours or inter-seasonal storage. The medium duration category is required to undertake the daily shifting of large volumes of solar generation or the twice weekly volumes of wind generation. The medium duration is the volume market, meaning efforts by government are required to ensure that this duration of storage is low-cost and provides long-term assets, or consumers and industry bills will suffer.


Regardless of the generation mix, Jacobs believe there is a compelling case for developing at least 10GW of long-term deep energy storage by 2030, with a further similar development by 2035.


The need to act is urgent, there is a compelling case to create the mechanisms to enable the deployment. The principal challenge is to encourage the emerging UK innovative solutions, so that these solutions can be deployed before 2030 and throughout the following decade.


Beyond traditional pumped hydro storage, medium and long duration technologies available globally are all at TRL5-7. The UK Government has provided some generous grant support to promising UK technologies at this stage (including RheEnergise) but there is still a gap in financial support (as these solutions are capital intensive) to get these technologies from TRL7 to full commercialisation.


A critical challenge, with this timescale is the state of the grid, especially for GW scale remote Pumped Hydro Storage (PHS) projects, that need new transmission infrastructure not only to connect the projects, but also new transmission capacity at the Scotland / England border (and elsewhere).


Due to grid capacity constraints, depending where new assets are deployed (both generation and storage) it will affect the total amount storage that is needed. The less efficient the grid is, in its ability to move large volumes of energy between centres of supply and centres of demand, the greater the energy storage need will become (or the greater the need to both curtail generation and to maintain gas peaking plant facilities).


By 2040 the UK may have >110GW of intermittent generation (predominantly wind), gas peaking plants will be progressively retired, and with peak demand perhaps at 65GW (largely depending on EVs uptake over this time). Beyond 2040, further growth in average and peak electricity demand is likely due to increasing uptake of heat pumps.


Q2: How sensitive is the amount of storage needed to assumptions about the future balance of supply and demand on the grid?


In the timescales under discussion new nuclear is likely to at best (once retirement of older nuclear facilities occurs) maintain the level of nuclear generated energy in the UK. Even if in the unlikely event lots of new nuclear was built, it could add to the need for energy storage; do not forget that the existing UK PHS facilities were built to absorb excess nuclear night time generation for dispatch during the day.


In our view, fossil-fuels with Carbon Capture & Storage (CCS) is wishful thinking in the timescales to 2040, as there are some huge barriers technically, environmentally, with regulation (none exists yet) and market structures to pay for it all.


Other technical solutions provide some potential, such as tidal lagoons and tidal stream, but these are not necessarily cheap solutions, and not in a significant way before 2040.


Landfill gas is declining as increased recycling and incineration takes place. Anaerobic Digestion has limits on feedstock.


There is potential for some Geothermal, but realistically 2040 is the earliest for this solution.


Vehicle to grid (V2G) appears to make very little economic sense for the vehicle owner (other than perhaps vehicle fleet owners), as the value of the battery and the potential for shortened battery life appears to exceed the potential for income generation.


Interconnectors also have some drawbacks, and their usefulness will depend on the generation mix of the counterparty country and the weather at the time. Interconnections to countries dominated by wind power and which are in the same weather systems will be less beneficial than a connection to say Iceland’s potential for geothermal generation or Morocco’s solar potential. Short interconnectors to near countries will have a lesser beneficial impact than longer (more expensive, greater technical risks) interconnectors to countries further afield.


Demand side response is a very useful tool, but it will always have limits in what it is able to deliver at a system level at a given time.


Modelling on the need for energy storage is very sensitive to the assumptions used. Too many models look at whole system need, but fail to capture the fact that the grid, designed for fossil fuels, will be inefficient at dispatch for a grid dominated by renewables. During the transition, grid infrastructure will need to evolve which in turn implies a greater need for storage to manage system inefficiencies. However, there is one crucial advantage that exists: the locations of supply and demand are clear. Wind will be placed where there is good wind resource, solar where there are good irradiance levels. The principal locations of energy demand are not going to move.


An issue that is rarely, if ever considered within the context of energy infrastructure, is how much of the existing grid and generation infrastructure is at risk of sea level rise, particularly along the south coats and around the Humber and Seven Estuaries.


The electrification of initially mobility and later heat will have a significant impact on the need for additional generation, additional distribution, and additional storage. The potential for a doubling of overall energy demand is real by 2050, however the impact on the absolute peak may be less significant. This implies that efficient distribution of energy across the grid will become even more essential and that the need for energy storage, of different types and different scales, to balance the cycles of wind and solar will also be essential. There are no conceivable scenarios where significant amounts of energy storage is not essential to both balance supply and demand, but also lower costs to consumers.


Policy makers should encourage thinking that there are three types of energy storage needed: short-term balancing solutions; long duration / inter-seasonal storage; and medium duration solution, that will undertake much of the energy shifting at low cost.


As the grid becomes more distributed, with generation at different scales and capacities, it is also essential that energy storage solutions are also deployed at many scales from a few MW’s connected to distribution (or co-located) through to hundreds of MW’s connected to new transmission infrastructure. Policy developed should enable all scales and encourage multiple solutions. A smaller scale solution suits parts of Cornwall, while a larger one is needed between Scotland and England.


Q3: Which technologies can scale up to play a major role in storage?


The challenge for all LDES technologies is one of timescale to deploy at scale. Large scale projects by their nature take longer than smaller ones.


PHS takes 7+ years to consent and the same again to construct. There are 2-3 projects in the UK through the first part consenting process, but they are on effective hold until an effective market mechanism is developed.


Compressed Air Energy Storage (CAES) in caverns, has only two operational projects in the world, and although a potential solution, the speed of CAES deployment is in question. There are other solutions in development that compress other gases, ie. CO2.


Liquid Air Energy Storage (LAES) has projects in demonstration, but for economic reasons works best if both electricity and heat can be used to create value; this limits the good locations for deployment.


Hydrogen storage has the challenge of scaling manufacturing to produce enough hydrogen electrolysers. There is also the use of water that could be an issue depending on location. The second issue is that round trip efficiencies for electricity to hydrogen and back to electricity are very poor (35% at best), making it a high-cost solution for daily use, but a good solution for less frequent inter-seasonal storage needs.


Flow batteries continue to struggle with costs, and round-trip efficiencies.


Gravity solutions fall into several sub-categories with some of them probably un-economic (where they must build the elevation to create the solution). With other solutions needing specific existing features, the question for these solutions is whether there are sufficient accessible and usable sites.


Thermal storage solutions are also challenged by having low round trip efficiencies when going from electricity to heat and back.


To summarise, all LDES solutions have their individual challenges, with different solutions being best at a particular location, dependent on the application, market need, geography, grid access, etc. A wide variety of solutions will be necessary, and all need support in terms of commercial deployment readiness and LDES long term market signals.


Q4: What policy support is currently in place to support deployment of storage technologies? Is it sufficient to support deployment at scale?


The long-term outlook for a good economic case for LDES is strong. However, the different solutions are generally immature, and they are yet to be considered “bankable” by institutions. Therefore, there is a clear and urgent need for support mechanisms across different scales (MW and MWh) and solution types, to create a new dynamic market. The various markets (wholesale, Capacity, CfDs, Balancing and Ancillary) do not support the deployment of LDES but could be amended so that support was available. It is essential to underpin all these markets with an effective carbon market (price escalating) with real-time proof of origin of energy. This is needed to determine whether energy within the store is zero, low or high carbon, and to enable high benefit to the store operators when carbon intensity is low.


A CfD mechanism (e.g. as used for offshore wind) or a cap-and-floor mechanism (e.g. as used for interconnectors) will not necessarily suit LDES solutions, as their scale, especially in early deployment years may not justify the overhead of bidding into these types of market mechanisms.


Stakeholders during the consultation process should be as the Committee has highlighted but there is also a need for “System Design” role, that provides the clarity on transition from the energy system that we have today to the one of the future. This system design role should analyse the need both from a national perspective, but also at a region or nodal constraint level.


From the perspective of a company developing an emerging, and highly viable LDES solution, our impression is that the voice of incumbent industry is much more present in discussions than those with emerging solutions. A key concern is that market mechanisms will favour mega-projects, that these projects will take significant time to deploy, which in turn will slow the deployment of new and additional renewable energy systems.


A market mechanism, that not only supports large projects but also supports smaller projects, and emerging technologies, that can be deployed faster and at a pace commensurate with the evolving grid. The need for multiple scales and multiple solutions is clear; a good solution (whether scale or performance) may not be the best solution at a different location on the UK grid.


As well as the need for clear market signals that favour LDES (e.g. cap and floor, CM reform, long term contracts for balancing services) government intervention is needed to incentivise and support technologies from TRL7 to TRL9+, together with scale up.


Q5: How well developed is the UK industry across different storage technologies, such as hydrogen or redox flow batteries? How does the UK compare to global competitors in these industries?


RheEnergise’s High-Density Hydro has significant export potential for the UK. The export potential from RheEnergise has the potential to be greater than that of traditional PHS, Flow-batteries and hydrogen electrolysers combined, especially as the UK now has only one hydrogen electrolyser company ranked in the top 20. The UK has already missed out on these opportunities as the centres of these solutions are already outside the UK.


The UK has both the research capacity and industrial know-how to develop RheEnergise’s HD Hydro into a solution deployed at scale globally. RheEnergise sees strong market pull from Spain, Ireland, Chile, the USA, Australia and interest from India, South Africa and elsewhere.


For traditional PHS the dominant players are outside the UK. Flow-batteries consistently fail to achieve the potential for cost reduction and performance improvement. The UK is well placed on the innovation of hydrogen electrolysers, and to take part of that market, but much less so on the skills, management expertise and support to actually scale this industry to the full benefit of UK PLC.


The UK is falling behind other countries, in initiatives to support the energy transition and emerging solutions, for example the US Inflation Reduction Act, the EU’s response and in Canada and Australia initiatives to utilise a small part of pension fund capital to take higher risk, higher return decisions.


In Europe, SMEs are eligible for a €2.5m grant to support scale up for technologies at TRL7, together with €15m equity finance and/or a blended approach. With the recent UK association confirmed with Horizon Europe, UK SMEs are now eligible to apply for the €2.5m grant, but still remain ineligible for the €15m blended finance option putting UK SMEs at a distinct disadvantage to their European counterparts. We ask that the government addresses this gap.


Q6: Beyond the cost of deploying long-duration energy storage, what major barriers exist to its successful scale up (e.g. the availability of a skilled workforce, the ability to construct the necessary infrastructure on time, or safety concerns around new technologies)?


The initial barriers are about clear market mechanisms and market access, support mechanisms to de-risk emerging technologies, new business-models, and delays in grid connections (which LDES could help solve). A longer-term plan – a system designer – would be of substantial benefit. Behind the initial barriers, one very quickly hits the next barrier of the lack of sufficient technical skills in the market.


As a growing SME business, we do not seek new types of skills, but rather a far larger pool of technical, managerial, operational, and commercial skills in the market that we can draw upon. As an emerging SME, we see benefits in different types of support mechanisms; however, our key concern is that whatever mechanism is chosen to support LDES, it must not have a cost or administrative burden, or restrictions on scale, that effectively precludes emerging solutions. A poor solution / market design that favours incumbents will clearly lead to the demise of the aspirations highlighted in Q5.


With support for commercial readiness, RheEnergise’s HD Hydro solution could be consented and built in timescales similar to Li-ion batteries i.e. consented in 9 to 12 months and built within 18 months for a base case of 20MW, 8hr solution. To grasp HD Hydro’s capacity to scale, RheEnergise has identified 6600 suitable sites in the UK through Geo Information System (GIS) analysis and could build out medium duration energy storage assets at 5% of those sites to get to 10GW of storage (by 2040), equivalent to 25% of Aurora’s UK 2040 medium duration target. Our business model allows us to scale exports in tandem to UK opportunities and address a noticeable part of what is predicted to be a $4 trillion by 2040.


Q7: What steps should the Government take now to ensure this storage can come online later in the current decade?


The steps the Government should take are multiple:

  1. Ensure that whatever the proposals and market mechanisms developed have consensus across Parliament, to ensure that UK political risk is largely removed from industry decisions.
  2. Provide effective scaling-up support for emerging technical solutions.
  3. Create the market mechanisms that work at multiple scales and for multiple technical solutions – be both scale and technology agnostic when market solutions are being developed, ensuring long term signals enable these technologies to be bankable at investment stage.
  4. Ensure the carbon market is effective at retiring fossil fuel generation and fossil fuel-based flexibility.
  5. Ensure that low-carbon solutions are given preferential treatment in merit order markets and other energy markets.
  6. The government should consider how it may take on some risk for emerging solutions, to enable them to overcome the investment “valley-of-death”.
  7. Equity / ventures markets are not well adapted to take on more long-term patient capital risk, especially where there are high initial capital costs to prove out large-scale energy solutions.
  8. Extensions of EIS / VCT type policies, for a number of early projects (e.g. 10), should be considered as a good low-cost mechanism to enable UK-based new industry. These types of incentivisation policies could be extended to the very deep capital pools to the likes of pension funds.
  9. Learning from other countries is always important. This can be facilitated by non-profit organisations e.g. The LDES Council


11 September 2023