Last year, for the first time in history, renewable energy produced more of the world's electricity than coal.

In the first half of 2025, solar and wind energy outstripped growth in global electricity demand and led to a small but significant reduction in the use of fossil fuels compared to the year before.

But some renewable energy has a timing problem: the sun doesn't shine at night, and the wind doesn't always blow when we need electricity.

In this short video, Albane Poulin, Head of Private Credit & Fixed Income Fund Manager at Gravis, tells us about long duration battery storage. She explains, what it is, why we need it and why it is making the headlines at the moment.

The transcript is below.

LDES or Long Duration Energy Storage is defined as any storage technology that can charge and discharge for eight hours or more.

Renewable power is great for decarbonisation but it has a timing problem. The sun doesn't shine at night, and the wind doesn't always blow when we need electricity. Batteries solve part of that problem, but most of the batteries installed today - the lithium-ion ones - only store power for two to four hours. That's enough to shift solar power from midday into the evening peak, but not enough to get you through a week with no sunshine or no wind.

There are several technologies competing in this space, but we will focus on the main two technologies.

Pumped hydro is the oldest and still the largest form of storage. It works with physics: when electricity generation is high and power is cheap, you use it to pump water uphill into a reservoir. When power is needed, you let that water flow back down through turbines.

However you need the right geography - a mountain, a height difference and access to water - so it's not something you can simply build anywhere. In the UK, most of the existing projects are in Scotland and Wales and all the proposed projects are actually in Scotland.

Lithium-ion batteries built their reputation on short-duration jobs of two to four hours, because that's where they've historically been cheapest and most efficient. But the technology is now pushing into long-duration territory.

The trade-off is that, adding duration to a lithium system means physically adding more battery cells, so costs scale up in a way that pumped hydro doesn't. But lithium's big advantage is speed and flexibility: you can build a lithium project in a year or two, anywhere, whereas a new pumped hydro scheme can take 7 years to build and 3 to 4 years to fill the reservoir.

Both short duration and long duration [energy storage] have similar revenue drivers but are weighted very differently.

Revenues come from energy arbitrage, balancing, the capacity market, and ancillary services.

Short-duration batteries rely heavily on ancillary services and fast balancing actions with response times from seconds to minutes, because they can cycle multiple times a day, but that revenue is thin and compresses quickly as more batteries enter the same market.

Long duration energy storage can't cycle as often, so it relies more on day-ahead arbitrage across wider peak/off-peak spreads and on capacity payments. The day-ahead is a forward auction, so you commit to charge/discharge volumes the day before delivery at a price that's fixed at auction close.

Long duration energy storage projects also receive payments for being available to deliver electricity during peak demand periods or emergencies. These contracts can last up to 15 years and provide secure, index-linked revenues.

More importantly long duration energy storage benefits from the cap and floor: The regulator - Ofgem, in this case - sets a floor, which is a minimum level of revenue the project is guaranteed to receive each year, and a cap, which is the maximum revenue it's allowed to keep. If the project earns more than the cap in the open market, the excess gets returned to consumers. If it earns less than the floor, the project gets a top-up. Everything between the cap and floor is the revenue for the project.

It's the same regulatory model that's been used for years to fund electricity interconnectors between the UK and Ireland and also with Germany.

People assume long duration storage simply replaces short duration, when actually the grid needs both, as they do different jobs.

Short duration storage is built for speed. Long duration storage is built for endurance. The two are complementary, not competing.

A grid with only short-duration storage still gets caught out by a prolonged lack of wind and sun. A grid with only long duration storage would be expensive for something that just needs to shave an evening peak.

The most efficient system uses lots of cheap, fast, short duration batteries for the daily requirement, and long duration assets to cover the tail risk. That's exactly why Ofgem's own shortlist spans multiple technologies and durations rather than picking one winner.

The UK regulator, Ofgem, has provisionally selected 16 long duration energy storage projects under the cap and floor support scheme, representing 7.6GW of storage capacity. While the announcement is a positive step for the sector, the real question is which of these projects can actually hit their delivery targets, and do it in a way that's cost-efficient both to build and to run.

Two things: cost and time. Pumped hydro is the most extreme case - we're talking billions of pounds for a single scheme, and construction can take 7 years before the asset generates a single pound of revenue. Even long duration lithium projects, while much faster to build, still carry meaningfully more capital cost and construction risk than the two-hour batteries the market is used to financing.

That combination - huge upfront spend, long construction timeline, and revenue that depends on wholesale power prices - is exactly the kind of risk that's very hard to finance on a pure merchant basis. Lenders don't like too many uncertainties at the same time.

The floor gives lenders and investors a guaranteed revenue base to underwrite against, and the cap protects consumers from paying over the odds if the project turns out to be a huge commercial success - so it's a risk-sharing arrangement, not simply a subsidy.

We like this sector for the same reasons we like infrastructure generally: these are assets with long useful lives, contracted or policy-backed revenue, and cash flows that don't move with the economic cycle.

We can get into the project early, at ‘ready-to-build’ (once planning consent, grid connection, and the EPC contract are all in place), and it is where we can capture the best risk-adjusted return in our view.

From a private credit angle specifically, this is exactly the territory the cap-and-floor regime was designed to unlock. We'd expect to see construction-phase financing first and then refinancing with lower cost of capital once the asset is operating and de-risked.

The direction of travel is positive with these 16 projects selected. But here's the catch - if all 16 projects move forward at the same time, they're all competing for the same civil contractors and the same pool of capital.

So it's realistic to expect some of them to slip - on cost, on timing, or both. So underwriting needs to stay disciplined about which technology and which counterparty you're backing, and the final cap and floor levels aren't confirmed until Ofgem's decision later this year.

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