Fleet electrification is becoming an energy problem.
Electrifying a fleet looks like a vehicle procurement decision. Then the vehicles arrive, and it quietly turns into an energy decision, about cost, grid capacity, and whether the fleet is ready to roll each morning.
Fleet electrification usually starts with vehicles. Which models exist? What range do they offer? How does the cost compare with diesel? Reasonable questions, and the easy ones.
The harder question shows up later: can this fleet electrify without creating avoidable energy cost, grid constraint or operational risk? Diesel was simple, refuel, dispatch, repeat. Electric fleets are not. Charging time, site power, electricity price, battery state, route schedules and driver behaviour all decide whether the fleet works the next day. Energy stops being a purchase and becomes a live operational variable.
The cost problem is not pence per kilowatt-hour
The headline number on an electricity bill is the unit rate. The number that actually moves the cost of running an electric fleet is when it charges.
Commercial tariffs swing hard between peak and overnight rates. A fleet that charges on arrival, all at once, pays peak prices and spikes its own demand charges. A fleet that spreads and shifts charging into cheap windows pays far less for the same energy. Get this wrong and a fleet manufactures cost that was never necessary. Get it right and the same fleet frees up budget, and prepares itself for revenue that diesel never offered.
The swings are getting wider, not narrower. Britain now sees regular periods of very cheap (occasionally negative) wholesale power when renewable output is high. In 2025 the country curtailed a record 10 TWh of renewable generation it could not move to where the demand was. Turning that output down cost £363m in payments to generators, and replacing it with other plant, mostly gas, cost over £1bn. A fleet that can soak up energy in those windows is not just saving money; it is doing something useful with power that would otherwise be thrown away.
Source: NESO balancing mechanism data for 2025, as reported in industry analysis, January 2026.
Grid capacity changes the commercial model
Most depots were not designed for large-scale charging. Plug in fifty vehicles at once and the constraint is no longer the charger, it is the connection. That exposes upgrade costs and long connection timelines that can stall an electrification plan entirely. Reinforcing the network is slow and expensive; using the capacity a site already has, intelligently, is neither.
There is a deeper problem, and it is largely invisible. Distribution network operators cannot see most commercial depot charging. The large majority of depot load is estimated from historical billing rather than measured in real time, which means the people responsible for keeping the local grid stable are forecasting in the dark. As fleets electrify, that blind spot widens, and the cost of getting the forecast wrong lands on everyone connected to that part of the network.
This is where the commercial model and the public interest line up. Britain is short of flexibility, and the scale of the shortfall is not marginal: NESO’s Clean Power 2030 advice calls for up to five times more demand-side flexibility by 2030 than the system has today. Distribution operators already pay for load that can move on demand, and the rates on offer are set locally rather than nationally, so the value of an hour of deferred charging depends on where the depot sits. A depot full of parked, plugged-in vehicles is precisely the kind of asset that can supply it.
Source: NESO, Clean Power 2030 advice, November 2024.
From cost centre to grid asset
The shift, then, is from buying fuel to managing energy, and from a cost centre to a potential revenue line. A well-orchestrated depot can stack several benefits at once:
- Charging cost savings
- 42%
- Demand charge reduction
- 28%
- Flexibility revenue
- 30%
Proportional split of modelled per-vehicle value. Illustrative and subject to TOGL modelling. The mix moves with tariff structure, site constraints and flexibility market access, which is the reason no single source is relied on.
Energy arbitrage: Charging when power is cheap, not when vehicles happen to arrive.
Demand-charge reduction: Spreading load so the site never spikes.
Flexibility revenue: Selling controllable load into balancing and local network markets.
Renewable absorption: Acting as a demand sponge for power that would otherwise be curtailed.
TOGL puts the modelled annual value of those streams together at £1,000–£3,000 per vehicle per year for a van and light commercial fleet, which is a five-figure annual total for a mid-size depot and more for a large one. That is what turns a fleet from a passive load into a fleet-as-virtual-power-plant.
Modelled against unmanaged charging. Around 40% of the modelled value is charging cost savings available through smart charging today; the remainder depends on demand charge reduction (in development) and flexibility revenue (planned). Indicative ranges only, subject to TOGL modelling. Actual value depends on duty cycle, battery size, tariff structure, site constraints, charging windows, integration availability, and flexibility market access.
The decision is no longer simply “charge now” or “charge later.” It is:
Where TOGL fits
TOGL is built to fold vehicle data, charging needs, operational constraints and energy signals into a single decision, through supported integrations built on open protocols. It does not replace charging infrastructure; it orchestrates it, sitting on top of what a fleet already runs.
The piece that makes the energy problem tractable is foresight, and it is what the platform is designed around: using telematics to know state of charge, location and arrival time before a vehicle reaches the depot. That is what would let a depot pre-position charging against tariffs and grid conditions, and hand the local network an ahead-of-time demand forecast in place of an estimate derived from historical billing. Solving the operator’s cost problem and the grid’s visibility problem turns out to be the same piece of work.
Vehicle tells the depot early
Telematics give state of charge, location and arrival time before the vehicle reaches the gate.
Depot pre-positions charging
Charging is planned against tariffs, site limits and departure times rather than reacting on plug-in.
Network gets a forecast
The local network operator receives an ahead-of-time demand forecast instead of discovering the load.
“The shift is from buying fuel to managing energy, and from a cost centre to a potential revenue line.”
Key takeaways
- Fleet electrification is an energy control problem, not just an infrastructure one.
- Charging cost is driven by when a fleet charges, not just by the unit rate. Peak avoidance can cut bills materially.
- A well-orchestrated depot can stack energy savings, demand charge reduction, flexibility revenue, and renewable absorption.
- TOGL models £1,000–£3,000 per vehicle per year across those stacked streams for a van and light commercial fleet, as an indicative range subject to modelling.
- Departure readiness must always come first, flexibility is what's scheduled around it.
The point
Fleet electrification is not just a switch from diesel vehicles to electric ones. It is a switch from fuel buying to energy management, and the operators who treat it that way will run cheaper, more reliable fleets, and earn from assets that used to just sit there overnight.
That is why TOGL exists.