Demand charges explained
The part of your electric bill most facilities never manage, and the reason ecoSEMS pays back faster than solar alone.
What a demand charge is
Your utility bills two things: energy (kWh, what you used) and demand (kW, how fast you used it). The demand charge is based on the single highest average power draw in any 15- or 30-minute interval during the billing month. It does not matter whether that peak lasted one interval or fifty. On most commercial and industrial tariffs in the Midwest and Northeast it is 30–60% of the total bill.
Every utility, cooperative and municipal system bills demand differently. Choose your state, then your utility, and we show the rate cases, demand charges, capacity costs, ratchets and peak windows that apply. Utilities we have not covered yet are researched on the spot.
Why it is getting worse at DTE Electric (Michigan)
- Rate cases. Case U-21860 was approved February 19, 2026 for +$242.4 million a year, with new rates effective March 5, 2026. DTE immediately filed Case U-22046 requesting +$474.3 million plus an infrastructure recovery mechanism that adds $154 million in 2028, $228 million in 2029 and $318 million in 2030 if approved. Michigan's commercial rate was 16.63 cents per kWh in June 2026, up 11.3% in a year and the highest in the Midwest.
- Demand charges. D11 Primary: capacity demand $9.23/kW plus non-capacity demand $7.86/kW on on-peak billing demand, plus distribution $7.15/kW of maximum demand, about $24/kW in total. D4 Large General Service (secondary): capacity $9.18/kW plus non-capacity $7.48/kW plus distribution $27.10/kW, roughly $44/kW of billing demand. Power-factor penalty below 85%.
- Capacity markets. MISO's planning resource auction cleared a record $666.50/MW-day for summer 2025/26 and $424.30/MW-day for 2026/27. DTE is vertically integrated, so the cost reaches you through the power supply cost recovery (PSCR) factor and rate cases rather than a separate line item.
- Ratchets. On D11, on-peak billing demand is never less than 65% of the highest June–October on-peak demand in the prior 11 months, and maximum demand is the highest 30-minute demand in the previous 12 months (not less than 50% of contract capacity). One summer afternoon sets the distribution demand charge for a year.
- Time-of-use windows. On-peak is 11 am to 7 pm Monday through Friday. On-peak energy on D11 is 4.30 cents versus 3.30 cents off-peak, and the capacity and non-capacity demand components apply only to on-peak demand, so shifting load past 7 pm removes it from the demand bill entirely.
Why solar alone does not fix it
Solar output peaks at solar noon and falls through the afternoon; utility and grid-operator peaks fall between 4 pm and 7 pm. A cloud passing at 3 pm on the hottest day of the year can set your annual demand ratchet while your array is exporting. Solar cuts the energy line; it needs a control strategy to cut the demand line.
What actually works
- Know your peak. Interval data shows which equipment, in which hour, sets the bill. Most facilities find two or three loads that coincide.
- Prevent coincidence. Stagger compressor and chiller starts, pre-cool ahead of the window, sequence production-support loads. This is ecoDMT™ inside ecoSEMS, and it needs no capital.
- Store into the peak. A battery sized from the interval data discharges into the forecasted peak and defeats the ratchet.
- Get paid for flexibility. Enroll the same controllable load in PJM, MISO, NYISO, ISO-NE or utility demand-response programs, which pay per kW of committed reduction.
- Then add solar. With demand controlled, solar’s energy savings arrive on a bill that is already smaller and more predictable.
Questions
How is billing demand measured?
Most utilities average your power draw over each 15-minute (sometimes 30-minute) interval and bill the highest interval in the month, sometimes only within the on-peak window. Some tariffs also apply a ratchet to prior months.
What is a peak load contribution (PLC)?
In PJM, each customer's capacity charge for the coming year is set by its average load during the five highest system-peak hours of the previous summer. ISO-New England uses a single peak hour (the ICAP tag). Reducing load in those hours reduces next year's capacity cost, which is why grid-operator peak forecasting is built into ecoSEMS.
How much can demand management save?
Customers with existing solar have added 15–30% to annual savings with ecoDMT alone; full ecoSEMS deployments show 25–32% total energy cost reduction. The free energy model quantifies it for your tariff and load.
