The principal advantages are:  

Agile: very large number of eligible sites; ability to deploy rapidly and scale dramatically; reduced timescales to consent and construct means projects are deployed before markets change, making for improved revenue security (e.g. contrast to pumped-hydro storage [PHS]); ability to locate close to source of clean power and/or demand.  

Impact: dramatically reduced footprint; no flooding of valleys (as with traditional PHS); planning consents therefore much quicker to obtain.

Cost: broadly similar storage costs ($/MWh) to traditional PHS (i.e. better than any other storage solution for medium or long-term storage; even lithium-based batteries expensive for storage durations >4 hours) but without the disadvantages of conventional PHS.

Clean: minimal recyclability and supply chain concerns (no rare earth metals); fluid certified as ‘environmentally benign’.

Risk: building on a century of established industrial experience, capacity and supply chain knowledge of traditional PHS with incremental improvements and modifications means minimal risk and rapid progress in technology (i.e., unlike compressed air, flow batteries, lifting weights and other new, unproven technologies)

The raw materials are both common and available, including in the UK. The Li-ion battery industry is already experiencing severe supply chain bottlenecks and price increases). There are a lot of potential suppliers.

R19 has been certified by an independent laboratory as non-toxic. Obviously, projects would be designed so that they did not leak and if they did it would be quickly detected and contained.

Levelised costs of storage (LCOS) use a constant price for both the buying and sale of electricity. Lazard use $33.00/MWh. This means you get the cost of storage rather than the profitability of a project. In an energy storage project, much of the revenue may come from ancillary services rather than arbitrage. 

Below is a list of Levelised storage costs for various tech (Lazard's methodology):

Lithium-Ion Battery project range:  $204 to $206 / MWh 

Flow Battery range:  $257 to $467 / MWh 

Pumped Hydro range:  $152 to $206 / MWh 

CAES (Compressed Air Energy Storage):  $116 to $140 / MWh 

Rheenergise (2024) range:  $118 to $199 / MWh 

Analysis using Jacob's methodology strongly suggests that, after about 3 hours of storage capacity, pumped-hydro always provides the lowest Unit Cost of Firm Generation, by a significant margin. It implies that if pumped hydro is an option, it should be the long-term storage option of choice. RheEnergise is confident that early projects will deliver performance and costs comparable to traditional pumped-hydro, with significant opportunities for costs savings through commoditisation and learning. 

CAES is a cost-competitive technology but is limited in its deployment as it requires very specific sites (salt caverns) which are not found in many areas. It is a mature technology but there are only 2 projects operational globally.

The market is enormous: the LDES Council/McKinsey predict a global need of 85-140 TWh of long-duration energy storage by 2040, with a market potential of USD 1.5 to 4 trillion. Batteries have their place in the market, and they tend to dominate now because there is a lot of demand for relatively short-term storage and frequency response services. As the market shifts, longer term storage will be needed too, which batteries will struggle to deliver. Ultimately, we will need a huge amount of storage, and that storage needs to include some short duration (1-3 hours), lots of medium duration (4-16 hours), some long duration (>16 hours).

Our aim is to develop a solution that can be placed in many locations and achieve scale faster by deploying many multiples of projects in tandem. We are targeting projects from ~5MW up to ~50MW. This is not a hard envelope but rather one that we see as the most likely. 

We see HD Hydro as a distributed energy store providing flexibility to an increasingly distributed generation system. When we looked at the scale of gas peaking plant projects (currently used to bridge gap between supply and demand) and battery storage projects, the vast majority fall within the 10MW to 50MW scale.

Canada, US, Australia are obvious first steps but also the Middle East and many parts of Europe. We are already talking to developers who want a better/ different storage solution to batteries. The challenge has been site availability and consenting timescales, which we plan to address.

The projects we propose are significant in size; it takes time to achieve the 3 main requirements:

*Lease / land ownership

* Planning permission

* Grid connection.

These three elements will typically take 18-24 months after the site has been identified and a feasibility study undertaken. There is unfortunately a long lead time to developing infrastructure projects at the 20+ MW scale. We are actively seeking to sign contracts for commercial installations where construction could start in 2026. Commercial revenues are anticipated in advance of project construction.

Yes! We are looking to partner with developers, financers, OEMs and EPCs to deliver High-Density Hydro projects. We are currently building out our commercial pipeline for projects to be commissioned in 2027 and onwards.

(1) Energy Developers: Our customers are companies who develop energy projects in general. We would expect those customers to have a strong view on how they want to operate the plant to earn the best revenues for that specific location. We would expect that there would be multiple facilities spread across the grid, providing support (or value) where it is most needed.
(2) Commercial and Industrial customers who are aiming to decarbonise their operations, and have suitable elevation drops on their site e.g. quarries, mining operations etc

There are 3 types of installations which we anticipate will make up the majority of sites:  

• Connected directly to the grid to provide ancillary services and energy trading.  

• Co-located with renewable energy systems, providing arbitrage services (increasing the value of the energy sold). This could be on the same grid connection or even on the same radial feeder.  

• To develop behind the meter projects at large industrial energy user sites, co-located with renewables to provide genuine 24/7 clean power eg. 10 to 50MW, 15 hr system, co-located with wind and solar to provide 24/7 clean power to a mine site. This could be on or off grid.

Our High-Density Hydro solution is a closed loop system and therefore both highly predictable and manageable. It means that we can be incredibly accurate with our O&M costs/provisions and warranties. We will be able to predict, potentially within days, when something needs to be replaced or serviced. Our R&D facility in Montreal includes a pressurised test loop, which imitates real-world conditions and allows our engineers to test and iterate component parts such as the HD turbine. Pumped-hydro equipment suppliers use an analogous setup to test equipment before issue.

We will have tested all of the materials we plan to use in an abrasion test rig. The abrasion test rig is to confirm the theoretical work to date and will inform exact specification of materials. If the specification of any material has not previously been tested, we can put that through the test rig too. It will mean that we will have very predictable knowledge of wear rates and in turn maintenance or replacement intervals. It also means we could choose to design for 5-, 10- or 20-year replacements (different, but predictable, levels of capital or operational costs). The component designs will include our own specifications of materials - one area where we will be closely monitoring specification, application and quality is the surfaces that may wear.

Viscosity has been one of the focuses of our work on fluid rheology. R19 has a viscosity of ~20cP, comparable to milk. High viscosity increases friction and therefore contributes to energy losses. The losses mainly occur in the penstocks (pipes between top and bottom tanks), but can be countered by using slightly larger pipes.

These are the figures we would use. Please note different manufacturers claim different figures.  

Battery types (all batteries have parasitic cooling loads which tend not to be included in the figures. These cooling loads are higher in hot climates):  

• Lithium-Ion: 85%-90%, with annual degradation of performance of 0.5% - 1.0%  

• CAES: 50%-60%, with annual degradation of performance of 0%  

• Flywheel: 85%-90%, with annual degradation of performance of 0% - 0.2%  

• Green Hydrogen: 35%, with annual degradation of performance of 0.0% (The efficiency of electrolysis to gas is ~70% and gas to electricity 50% at best)  

• Combustion turbine (obviously not an energy storage technology, but used for flexibility services): 32%-45%, with annual degradation of performance of 0.0%

Our modelling shows that for peak efficiency, a pump turbine with our fluid needs to be over 5MW. We would always plan to put them in pairs to allow for maintenance etc and continuous operations. At this scale the ~83% grid to grid efficiencies is achievable. This is the reasoning behind a minimum 5MW project. If a customer was happy to have lower efficiencies, there is no fundamental reason why projects of a few kW would not be possible. However, this isn’t our target size. If customers demand projects of say 500kW and there is a clear case for hundreds of site opportunities, we will certainly consider developing solutions at this scale. The grid-to-grid efficiencies might be ~65% (we have not modelled this scale, so it’s a best guess). With pumped energy projects the head (vertical elevation difference) is also an important factor - if one doubles the head, the fluid/tank volume required halves.

Power infrastructure is often quite close to the bottom of hills at the edge of towns. We think true urban sites are possible but are also probably rare. We think edge of urban are more likely. There are a fair few towns and cities that are surrounded by hills. Man-made hills are a distinct possibility as are man-made holes like quarries.

• Project sites require an elevation (or ‘head’) ranging from 100m to 300m.

• Gradient of at least 10%, ideally steeper.

• At least 1 hectare available space at the top and bottom (ideally flat) for storage tanks.

• Good road access

• Brownfield sites are preferable, as they are quicker to secure planning consents and therefore develop.

An ideal site has a hill with 75-300m of elevation (ideally >150m) and flat areas at the top and bottom to site the storage tanks and a gradient of >10%. Ideally, there would be good road access, local grid infrastructure, the project site would be situated nearby local energy demand and the landowner engaged with the project. Co-location with wind or solar or a large industrial energy user is very attractive.

We would anticipate that the environmental impact assessments, for any specific site, will be those that are required by the local authority. It would certainly include an assessment of any wildlife you could affect, how the project protects that wildlife and how wildlife could be improved over the term of the project.

It is really any solution that provides flexibility to the grid or a generation asset. There is some overlap in competition with both batteries and with PHS but probably not that much. Developers increasingly recognise that for more than ~3 hours of storage, batteries are not the solution for both capital cost and operational cost reasons. There are also predicted supply challenges within 3-4 years. 

PHS is only likely to be developed where there are good sites and a government backed contract (or revenues) to proceed. 

The scale of the opportunity for energy storage is so vast that we all need to work together in solving the climate and energy crises.