What we build, what we assess, what we watch.

Lithium iron phosphate (LFP)

What we build. The reason is not technical enthusiasm but bankability: LFP systems have documented degradation curves, established warranty terms, available spare parts and test procedures that assessors and lending banks know.

In safety terms LFP behaves differently from nickel-cobalt chemistries: higher thermal stability, slower propagation in a fault. That makes fire safety concepts and coordination with fire services considerably easier.

The economic lever today lies less in cell price than in design: C-rate, cycle count and marketing strategy determine the return.

Sodium-ion

Sodium is abundant and more widely distributed geographically than lithium; cold-weather behaviour is better. First commercial large systems have been announced, and the announcements are becoming more concrete.

We assess the technology for projects with high cycle counts and modest energy density requirements — in stationary storage, footprint matters less than in vehicles.

• A reference system operating in Europe at megawatt-hour scale with at least twelve months of documented operation
• A manufacturer warranty with evidenced cycle life over the project term, not merely a datasheet figure
• System cost per kilowatt hour of usable capacity at or below LFP over the lifetime, not at purchase
• Certifiability under VDE-AR-N 4110 by an accredited certifier
• Spare part availability and a service commitment within the EU

Zinc

Water-based electrolytes have a fundamentally different risk profile from lithium-ion systems: no thermal runaway in the classic sense. For safety-critical environments and long discharge durations that is a real argument.

Cost is higher today and energy density lower. For open-field projects with spare land and high fire safety requirements the calculation can still work.

• Safety properties demonstrated by independent testing, not by manufacturer statement
• A European project in operation whose performance data can be inspected
• Evidenced service life in the region of twenty years under project-typical operation
• Whole-life cost within the range of an LFP alternative for the same task

Hydrogen and long-duration storage

Batteries solve hours, not weeks. For seasonal balancing and for sectors that are hard to electrify, hydrogen remains the most promising option — and the existing gas infrastructure a considerable advantage.

For our projects it currently has no relevance. In the hourly range the cost gap to batteries is too wide, and the electrolysis ramp-up is slower than planned.

Mechanical and thermal long-duration storage

Gravity, compressed air and heat storage solve tasks batteries handle poorly: very long discharge durations, very many cycles, very low cost per kilowatt hour at scale.

They are strongly site-bound — caverns, mines, existing power plant sites. We watch them as system components, not as an alternative on a greenfield plot.

Thorium molten salt reactors

The experimental TMSR-LF1 reactor at Wuwei, Gansu province, rated 2 MW thermal, first reached criticality on 11 October 2023, was the world's first molten salt reactor loaded with thorium in October 2024, and reported the conversion of thorium into fissile fuel on 1 November 2025.¹

Two clarifications, because they are frequently misreported. The freeze-plug principle makes the reactor passively safe against a meltdown — on overheating a plug melts and the liquid fuel drains into a catch tank. That is not the same as saying a meltdown is impossible. And the frequently quoted 300 years are not a half-life but the period after which the radiotoxicity of the waste has fallen to ambient levels.

For battery storage projects this has no relevance. We list it because an available, dispatchable baseload block would change the price structure our revenue models rest on — at the earliest in the 2040s.