A battery installed to hold charge as backup does nothing while it waits. A battery managed as a market participant earns from three separate income streams simultaneously.
Most commercial property owners encounter battery storage in one context: power resilience. Diesel generators fail, grid outages cause disruption, a battery holds charge and releases it when the grid drops. This frame of reference — battery as insurance — is accurate for a small class of backup-only systems. It is not the right frame for a behind-the-meter battery managed as a trading asset.
The distinction is not a technicality. A backup battery earns nothing. An actively managed battery generates from three revenue streams simultaneously, all from the same hardware.
Commercial electricity contracts in the UK and Sweden include a demand charge component — a tariff based on the property's peak power draw during a measurement period, typically the highest 30-minute peak in a billing month. This charge can represent 20–40% of a large commercial property's electricity costs, and it is charged on a single peak event that may be unrepresentative of normal consumption.
An AI-managed battery anticipates the property's demand profile. Before a predicted peak draw — a production run starting, a large HVAC system cycling on, tenant arrival creating a consumption spike — the battery pre-charges and discharges to cover the peak. The grid meter sees a flatter demand profile. The demand charge falls. This benefit applies to the property's current electricity cost regardless of any other revenue stream, and it requires no changes to the property's operations.
Day-ahead electricity prices vary by hour across every market in Europe. In Nordic spot markets and in GB, the spread between the cheapest and most expensive hours of a day routinely exceeds 100%. The overnight price in Sweden frequently trades below 10 €/MWh; the evening peak can exceed 100 €/MWh on the same day.
A battery managed against the day-ahead price forecast charges from the grid when prices are at their lowest — or from on-site wind or solar generation — and discharges when grid prices are highest, either supplying the building's load or exporting to the grid. The margin between buy-low and use-at-high is the arbitrage return. On-site generation from wind or solar makes this more valuable: every kWh of self-generated electricity consumed at a high-price hour displaces grid electricity at that price, maximising the effective value of the generation.
Grid operators — Svenska Kraftnät (SVK) in Sweden, NESO in Great Britain — are legally required to maintain grid frequency within defined bounds. They procure the capacity needed to do this from battery operators through competitive daily and weekly tenders, paying a capacity fee (per MW available per year) regardless of how much energy the battery actually dispatches.
This is not the same as selling electricity. It is a payment for being available — for holding battery capacity reserved for frequency-stabilisation obligations. For a commercial property battery, participation in these markets is handled through an aggregator who bids the asset's capacity into the TSO's procurement process. The property owner does not interact with the market directly. The revenue flows as part of the operating agreement.
In Sweden, the primary frequency-services products are FCR-N, FCR-D, aFRR, and mFRR — described in detail in the related article on grid frequency markets. In GB, the equivalents are Dynamic Containment, Dynamic Moderation, and Balancing Mechanism positions. The product architecture differs; the revenue logic is the same.
Each of the three revenue streams involves a real-time optimisation decision. Peak shaving requires knowing when peaks will occur and pre-charging accordingly. Arbitrage requires knowing the day-ahead price curve and the generation forecast. Grid-services participation requires reserving the right proportion of battery capacity for frequency-response obligations without sacrificing the other two revenue streams.
A battery on a fixed charge-discharge schedule captures one of these axes at best. It misses the others entirely — or cannibalises them. Reserving the whole battery for backup, for instance, means no arbitrage and no frequency-response participation on the days the backup is not needed, which is almost every day.
The AI energy management system resolves all four inputs simultaneously — day-ahead price, generation forecast, frequency signal, and tenant demand profile — and produces a continuous dispatch plan that captures value from all three revenue streams without conflicting them. This is why HNordic's income projections are not replicable by a property owner purchasing a battery from a hardware vendor and managing it manually.
A battery managed for revenue does not forfeit all resilience capability. The distinction is between a battery configured as a backup-only device — grid disconnected, waiting — and a battery that is revenue-optimised but retains a defined state of charge reserve for grid outage scenarios.
An islanding configuration — where the battery can supply critical building circuits when the grid is absent — requires specific engineering design, additional equipment (a transfer switch and an inverter with islanding capability), and regulatory sign-off. This is an optional addition to the standard installation, not a default. It is assessed at the site assessment stage if resilience is a requirement.
See also: What are FCR-D, FCR-N, aFRR, and mFRR? · What does the AI energy management system optimise against? · Full FAQ