On the outskirts of Plymouth, a china-clay mine is hosting an energy experiment that sounds almost too modest for the UK’s net-zero ambitions.
There is no dam wall. No Alpine reservoir. Instead, there are underground tanks, buried pipework, and a mineral-rich fluid designed to be heavier than water. When electricity is cheap, the system pumps the fluid uphill. When power is needed, it lets the liquid run back down through a turbine. That is pumped hydro — the oldest grid-scale storage technology — shrunk and tweaked for gentler terrain.
This week, the developer, RheEnergise, said its Cornwood demonstrator has reached full output, producing 500 kilowatts at peak. That is not a grid-transforming number on its own. But the concept behind it has bigger implications: if you can get pumped hydro to work on lower hills, you expand the map of where “water batteries” can be built — and you may be able to build them faster, with less drama than megaprojects.
The question is whether this is a clever engineering shortcut, or the start of a serious new category of long-duration storage.
Why long-duration storage suddenly matters (again)
Electricity systems are learning a new lesson: adding renewables is not the hard part; making them behave like a dependable power system is.
Wind and solar are cheap, but they arrive on nature’s timetable. When supply outruns demand — or the grid cannot move power from where it is generated to where it is needed — the system pays generators to turn down, fires up backup plant, and buys balancing services to keep frequency and voltage stable. These costs are no longer rounding errors. In Great Britain, the system operator’s annual balancing costs totalled £2.7bn in FY2024/25, with thermal constraints a major driver — a technical phrase that, in plain English, often means “the wires are congested and the wind is blowing in the wrong place.” Those constraint costs can be eye-watering, and the operator expects balancing costs could peak around 2030 unless critical network projects arrive on time.
That is why long-duration energy storage (LDES) is back in fashion — not as a nice-to-have, but as infrastructure.
The UK government’s Clean Power 2030 Action Plan talks about a system built around large volumes of wind, solar and flexible capacity, including 23–27 GW of battery storage and 4–6 GW of long-duration storage by 2030. It is also why Ofgem has been building a “cap and floor” regime intended to make long-duration projects financeable, with decisions on early projects expected around 2026.
This policy push is not nostalgia. It is a recognition that “four-hour batteries everywhere” is not a complete grid strategy.
Pumped hydro is the incumbent — but geography is its prison
Globally, pumped storage hydropower remains the workhorse of electricity storage. The International Energy Agency calls it the largest form of electricity storage worldwide, with far more capacity than battery fleets. The International Hydropower Association (IHA) puts global pumped storage capacity at about 189 GW at the end of 2024, after a surge of new installations, and estimates a development pipeline of roughly 600 GW.
The appeal is obvious: pumped hydro is proven, long-lived, and built from familiar components — civil works, tunnels, turbines, pumps. The basic physics is also clean and comforting: lift mass against gravity, then get most of that energy back later.
The problem is that pumped hydro is picky.
Classic schemes need a significant “head” — the vertical drop between upper and lower reservoirs — and enough room to store water at scale. That pushes projects into mountainous regions or deep valleys, and into long planning battles. They can also demand huge upfront capital and years of construction risk, the kind that makes investors nervous and local communities loud.
So engineers have been searching for ways to loosen pumped hydro’s geographical constraints without losing its core strengths.
The twist: make the water heavier
RheEnergise’s proposition is simple: the energy stored in a pumped-hydro system depends on three levers — how much liquid you move, how high you lift it, and how dense that liquid is.
If you increase density, you can reduce the height (or the volume) required to store the same energy. In other words, a smaller hill can behave like a bigger one.
The company says its system uses a “specially formulated” fluid about 2.5 times denser than water, designed to remain low-viscosity (so it flows easily) and to avoid excessive abrasion in pipes and machinery. Earlier descriptions of the fluid (known as R-19) suggest a fine-milled suspended solid in water, using base materials that are common in industrial supply chains.
This is not a minor detail. Pumped hydro’s economics depend heavily on civil works: building reservoirs, digging tunnels, moving earth. If density lets you shrink the reservoirs or lower the required elevation difference, the project’s physical footprint can shrink too.
A quick way to see the physics: for each cubic metre of water dropped through 100 metres, you store about 0.27 kWh of potential energy (before losses). Make the liquid 2.5 times denser and you get roughly 2.5 times the energy per cubic metre for the same height — or the same energy for less than half the height.
That is why, in Devon, RheEnergise can point to something that would normally sound contradictory: pumped hydro on gentle slopes.
The Devon pilot: small, but real
The Cornwood demonstrator is built at Sibelco’s kaolin mine. It is meant to be underground and industrial in feel, more like an energy appliance than a landscape-defining dam. Government documents originally described the funded demonstrator as 250 kW / 1 MWh (four hours), supported by an £8.24m award under the Longer Duration Energy Storage programme. This week, the company said the project is now producing full power at its predicted output, with peak power of 500 kW, supporting Sibelco’s operations at times of high demand.
A 500 kW system is not designed to move national markets. It is designed to answer awkward questions that PowerPoint cannot.
Does the fluid behave predictably over hundreds of cycles?
Can the pumps and turbine handle it without unusual wear?
Is the system controllable and responsive enough for real grid services?
And does it achieve the kind of efficiency that investors and operators expect from pumped storage?
On that last point, pumped storage has historically been competitive: US data has put average monthly round-trip efficiencies for pumped-storage facilities around the high-70% range (with batteries in the low-80s). If a high-density fluid materially worsens efficiency, the “more sites” story starts to weaken. If it can match incumbent performance while shrinking geography requirements, the argument strengthens.
Scaling is not a physics problem — it is a construction and finance problem
If the Devon pilot proves robust, the next challenge is scale.
RheEnergise says it is already discussing sites with developers in the UK and overseas, and has talked publicly about future commercial projects in the 10–100 MW range with storage durations of roughly 6–20 hours. That begins to look like the middle layer of a modern grid: bigger than a battery farm, smaller than a mega pumped-storage project, long-duration enough to cover the evening ramp or a wind lull that lasts through the night.
But “could” is doing a lot of work here.
Pumped storage projects, even smaller ones, are still civil engineering. They need permitting, grid connections, land rights, construction teams, and bankable revenue models. The UK is trying to address the finance piece through the cap-and-floor regime. Yet history suggests the other bottleneck is time: it has been decades since the last new long-duration storage asset was built on the GB grid, a fact the government itself has pointed to as evidence of a market failure.
There is also a tricky political dynamic. A storage technology that promises “no dam, no reservoir” sounds politically easier — until a community hears “industrial tanks and buried pipes on a hillside” and asks what happens in a leak, what traffic construction brings, and who gets paid.
This is where RheEnergise’s choice of fluid matters again. If regulators and local stakeholders believe the fluid is environmentally benign and controllable, the planning fight is easier. If they do not, the technology’s headline advantage — more sites — becomes less relevant, because every additional site becomes another planning battle.
The competitive landscape is getting crowded
Long-duration storage is no longer a niche club with pumped hydro as the sole veteran.
Thermal storage companies promise grid services using heat instead of height. Flow batteries promise duration without lithium constraints. Hydrogen advocates point to multi-day and seasonal storage, albeit with efficiency penalties and infrastructure needs. And lithium-ion batteries keep dropping in cost and are being deployed at speed — which can make investors impatient with slower, heavier options.
So where might high-density pumped hydro fit?
Its most plausible niche is the gap between short-duration batteries and extremely long-duration fuels: storage that can run for a workday, a night, or a full day of calm weather; that can be built near industrial loads; and that can cycle frequently without rapid degradation.
Pumped hydro’s strengths — longevity, familiarity, and scale — are still valuable in that layer. If a dense fluid can expand the buildable map without compromising those strengths, it becomes a meaningful addition to the toolkit.
A quiet test with an uncomfortable implication
The Devon project’s most interesting feature is not the 500 kW headline number. It is the uncomfortable implication for energy planners: the bottleneck for long-duration storage is not always technology. It is often siting, permitting, and the willingness to build physical infrastructure on time.
High-density pumped hydro is, at heart, an attempt to make that bottleneck less binding — by relaxing the geography requirement that has constrained classic pumped storage for decades.
Whether it succeeds will depend on the unglamorous details: fluid behaviour, equipment wear, real-world efficiency, and whether projects can be standardised enough to become repeatable rather than bespoke.
If those details go wrong, Devon will be remembered as a clever pilot.
If they go right, it may mark the moment pumped hydro stopped being a mountain technology — and started to behave like a product.
