Your electricity bill changed when you added EV charging to the depot. You probably noticed. The total was higher, the structure looked unfamiliar, and somewhere on that statement was a line labeled something like "demand charge" that you may not have encountered in your previous facility or fleet work. For most fleet managers coming from a diesel background, commercial electricity tariffs are a new domain. This walkthrough covers what you need to know to read a time-of-use tariff and understand where your charging dollars actually go.
The two main cost components on a commercial electricity bill
Commercial electricity bills in most US markets include at least two distinct cost categories: energy charges and demand charges. Some tariffs also include fixed customer charges or ratchet clauses, but energy and demand are the two you can influence through charging decisions.
Energy charges are straightforward. You pay a rate per kilowatt-hour (kWh) for the electricity you actually consume. If your tariff is a flat-rate structure, you pay the same per-kWh rate around the clock. If it is a time-of-use (TOU) structure, the per-kWh rate varies by time period.
Demand charges are based on peak power draw, measured in kilowatts (kW). The utility records the maximum power demand during any 15-minute or 30-minute interval across the billing period, and multiplies that single peak measurement by the demand charge rate. That rate typically runs between $8 and $22 per kW per month in commercial tariffs across the US, though it varies significantly by utility and service class.
The key thing to understand: one bad 15-minute window of simultaneous charging can set your demand charge for the entire month. You cannot average it down after the fact.
What "time-of-use" means in practice
A TOU tariff divides the 24-hour clock into rate periods with different per-kWh prices. The most common structure has three tiers: on-peak, mid-peak, and off-peak. Some utilities use just two tiers (on-peak and off-peak), and some have seasonal variations where the rate schedule changes between summer and winter.
Typical on-peak windows for commercial customers in the Midwest and Mid-Atlantic fall between roughly 11:00 AM and 8:00 PM on weekdays. Off-peak windows cover evenings (8:00 PM or 9:00 PM onward), nights, and most of the weekend. The price spread varies by utility, but a 2x to 3x ratio between on-peak and off-peak kWh rates is common. A tariff might charge $0.16 to $0.19 per kWh during on-peak hours and $0.06 to $0.09 per kWh during off-peak.
For a fleet consuming 1,000 kWh per night, the difference between charging everything during on-peak versus off-peak hours is roughly $70 to $110 per billing period in energy costs alone. That number is real but not dramatic. The demand charge exposure from poorly timed charging is usually a larger dollar amount, which is why TOU optimization should always be paired with demand management rather than treated as the primary savings lever.
Where to find the rate schedule details
Your utility's tariff schedules are public documents. They are published on your utility's website, typically under a "rates" or "tariffs" section, and filed with your state's public utilities commission (PUC). When looking for your specific rate schedule, you need your rate class or tariff code, which is usually printed on your bill. Common commercial rate class labels include "General Service Medium" (GSM), "Commercial Time-of-Use" (CTOU), "Large Power Service" (LPS), or utility-specific names like "Rate GS" or "Schedule C."
Once you find the right tariff document, look for four things:
The on-peak, mid-peak, and off-peak windows and the days they apply (weekdays only? or weekends too?). The energy charge rate for each period in cents or dollars per kWh. The demand charge rate in dollars per kW, and whether it applies to on-peak demand only or to any-period peak demand. Whether the tariff includes a ratchet clause, which is a provision that sets a minimum demand charge based on a percentage of your highest demand in the past 11 or 12 months.
The ratchet clause is worth flagging specifically. If your tariff includes a ratchet at 80 percent, and you had a 200 kW peak in August, your minimum demand charge through July of next year is based on 160 kW, even if your actual usage drops below that. One summer peak can cascade into 12 months of elevated bills.
Seasonal rate variations and when they hit fleets hardest
Many commercial TOU tariffs have seasonal variants with higher on-peak rates in summer (typically June through September) and lower rates in winter. This matters for fleet charging because summer is often when EV battery thermal management systems draw more power to keep packs cool, and when depot facility loads from cooling systems are higher, pushing up the demand charge baseline.
Summer on-peak rate periods are also typically the windows that coincide most directly with vehicle return times for a midday or afternoon shift structure. A fleet that returns vehicles at 3:00 PM to 5:00 PM is returning right into the on-peak window on most summer TOU schedules. Without scheduling that explicitly delays charging start times, those vehicles will begin drawing power at the worst possible time from both an energy rate and demand charge perspective.
Winter rate structures are usually more forgiving for fleets with overnight off-peak charging availability, though cold weather adds consumption variance that makes energy prediction harder. The tariff savings opportunity is larger in winter, but the range margin tightens.
How a TOU rate structure feeds into charging schedule decisions
Once you understand your tariff's rate windows and demand charge structure, you can frame the charging schedule problem clearly. The goal is to complete all charging before morning dispatch while minimizing both peak demand (which drives the demand charge) and energy consumed during on-peak windows (which drives the TOU energy charge).
Those two goals are usually compatible but not identical in their optimal solutions. Minimizing demand peak might mean spreading charging more evenly across a six-hour window. Minimizing on-peak energy consumption means concentrating charging after the on-peak window ends, typically after 8:00 PM or 9:00 PM. When the TOU off-peak window starts at 9:00 PM and all vehicles need to start charging at 9:01 PM to meet both goals, you have a conflict: that simultaneous start creates exactly the demand peak you were trying to avoid.
The resolution is to pre-charge the vehicles with the lowest SOC and highest urgency during the late mid-peak window at modest rate cost, so that when the off-peak window opens, not all vehicles need to start simultaneously. This is a scheduling tradeoff, not a purely rules-based decision, and it requires knowing each vehicle's SOC, charge rate capability, and latest acceptable ready time.
The tariff knowledge gap in most fleet transitions
We are not suggesting that fleet managers need to become electricity tariff specialists. The point is narrower: understanding the basic structure of your commercial tariff, specifically the on-peak window timing, the demand charge rate, and whether a ratchet applies, gives you the context to evaluate whether your charging software is actually optimizing for cost or just scheduling for convenience.
We have seen cases where a fleet added charging management software but no one had loaded the correct tariff schedule into it. The system was optimizing against a flat rate assumption while the fleet was actually on a TOU schedule with a substantial demand charge. The scheduling decisions looked reasonable on paper but were producing suboptimal bills because the optimizer was missing most of the cost signal.
Pulling your tariff rate schedule and entering it accurately into your charging management system is a 30-minute task that determines whether the system's cost calculations bear any relationship to reality. It is worth doing before assuming the software is working as intended.