What EV Charging Peak Demand Actually Costs Fleet Operators

When a mid-size logistics operator in the Amsterdam area added its first 18 electric vans to a diesel fleet in late 2024, the team budgeted carefully. They knew the cost per kWh, they knew the approximate daily energy consumption per vehicle, and they ran the numbers against diesel. The math looked reasonable. Then the first electricity invoice arrived and it was nearly three times what they expected.

The culprit was not the energy consumption figure. That part of the calculation was accurate. The problem was the demand charge, a line item on Dutch commercial electricity contracts that most fleet managers have never had reason to think about before electrifying their depot.

How commercial electricity billing works in the Netherlands

A standard Dutch commercial electricity contract typically has three main cost components. The energy charge covers the actual kWh consumed and is the figure most people focus on. The network transport tariff covers grid infrastructure fees and is fairly fixed. The capacity or demand charge is where the surprises happen for fleet operators.

Dutch network operators, following the regulatory framework set by ACM and the Energiewet, apply a tariff based on your peak power draw during each billing period. For many contracts, this peak is measured in 15-minute intervals. The highest average kW reading across any 15-minute window in the billing month becomes the basis for the demand charge calculation. Rates vary by network operator and contract size, but commercial fleet depots typically see demand tariff components in the range of €8 to €14 per kW per month.

This billing structure exists because the grid operator has to provision enough capacity to serve your peak load. If your peak is 400 kW, they need to have 400 kW available for you, even if you only actually draw that much for one 15-minute window each month.

The unmanaged depot: what actually happens at 18:30

Consider a depot with 40 electric delivery vans. Drivers return between 17:30 and 19:00 after their routes. It has been a warm day, the vehicles have all been running air conditioning and covering 120 to 160 km. Most arrive with state of charge between 15% and 35%. The standard behavior, without any charging management in place, is simple: the driver parks, plugs in, and walks home. The charger starts drawing power immediately.

If the depot has 22 kW AC chargers, and 30 vehicles plug in within the same 30-minute window, the depot's instantaneous demand can spike to 660 kW or more. Even if vehicles start drawing at slightly different times, the 15-minute average power draw might reach 500 to 580 kW during that first wave.

At a demand tariff of €10 per kW per month, a 550 kW peak translates to €5,500 per month in demand charges alone, every month, regardless of how much energy you actually consumed. That number compounds across a full year to €66,000, and it tracks directly with the highest single spike of the year, not the average.

For context: a diesel depot of the same size running a diesel heating system and a few office HVAC units might have a peak demand of 80 to 100 kW. The step change when EVs arrive, under unmanaged conditions, is severe.

Why the invoice surprises operators

Fleet managers who have done thorough pre-electrification budgeting usually get the kWh cost right. They run consumption per vehicle per day, multiply by the tariff rate, and arrive at a credible energy cost estimate. What they rarely model is the demand charge because it requires knowing what the peak draw profile will look like under real operational conditions, and that is genuinely hard to estimate without either measurement or simulation.

There is also a structural problem with how the cost appears on the invoice. The demand charge is often buried in the network tariff section, listed in kW terms rather than kWh. A fleet manager reviewing an electricity bill for the first time often misreads it as a flat infrastructure fee rather than a variable cost tied to their charging behavior.

The third issue is timing. Commercial electricity contracts in the Netherlands typically have annual or quarterly reconciliation cycles. Some operators receive a monthly estimate based on historical data, then a settlement invoice later. By the time the real cost is visible, three months of high-demand charging may have already happened.

What demand charge reduction actually looks like

Smart charging schedules do not reduce the total energy consumed. The vans still need the same number of kWh to reach their target state of charge for the morning departure. What changes is the shape of the power draw over time.

Instead of 30 vehicles drawing 22 kW simultaneously from 18:30 to 19:15, a managed schedule distributes the charging load across the available overnight window, typically 22:00 to 06:00 when tariff rates are lower and the depot is otherwise idle. The peak demand during that window might be 120 to 180 kW, spread deliberately across the available charger capacity with each vehicle being allocated power in sequence based on its departure time and current state of charge.

The same 40-van depot that saw a 550 kW demand peak under unmanaged charging might have a managed peak of 160 kW during the overnight window. At €10 per kW per month, the demand charge component drops from €5,500 to €1,600. The energy cost changes too, shifting from partial peak-hour consumption to predominantly off-peak rates, but the demand charge reduction is typically the larger financial lever for mid-size fleets.

In our early-access pilots with Dutch logistics operators, the demand charge reduction component has been more significant than the tariff arbitrage component for depots with return windows concentrated in the evening peak hours (17:00 to 21:00).

The grid connection constraint is a separate problem

It is worth being clear about what demand charge optimization does not solve. If a depot does not have sufficient grid connection capacity to charge all vehicles within the overnight window at reasonable power levels, shifting the load later does not help. A depot with a 150 kW connection limit and 40 vehicles each needing 40 kWh of charging has a physical constraint: 150 kW over 8 hours delivers 1,200 kWh total, which is enough for 30 fully drained vehicles, not 40.

Smart scheduling can maximize utilization of available connection capacity and prioritize vehicles by departure order, but it cannot conjure power that is not contracted. Operators in this situation need to either upgrade their grid connection, add on-site battery storage to supplement the connection during peak charging hours, or reduce their fleet charging needs. These are infrastructure decisions that precede the scheduling question.

We are not saying demand charge management is the complete answer to depot electrification economics. It is the most immediately accessible lever for operators whose grid connection is adequate but whose charging behavior is creating unnecessary cost spikes.

Reading your own contract

If you manage a depot in the Netherlands and you are not certain how your current electricity contract handles demand or capacity charges, the place to start is the transport tariff section of your bill. Look for a line item denominated in euros per kW per month, or any reference to capaciteitstarief or piekverbruik. If you see a kW value anywhere near your charger count multiplied by 22, you almost certainly have an unmanaged demand problem.

Your energy supplier or broker can also request a half-hourly or 15-minute load profile from your metering data. This profile, plotted over a typical month, will show the spike pattern clearly. For most depots with unmanaged EV charging, the spike will appear as a sharp vertical line every evening between 17:30 and 20:00, in stark contrast to the relatively flat profile of the rest of the day.

Understanding the shape of your current demand profile is the starting point for knowing how much scheduling can help and whether your grid connection is already the binding constraint.