Power Factor Correction: Is a Low Power Factor Costing Your Minnesota Business?

Reviewed by John Ihle, MN Master Electrician (AM005101) · NABCEP-credentialed · iSolar, Saint Paul Park, MN · Last reviewed October 2026

What power factor is, and why your utility cares

Before you price power factor correction, it helps to know what you're correcting. Every motor, compressor and transformer in your building draws two kinds of current. One kind does work: it spins the shaft or runs the compressor. The other kind, reactive current, just builds the magnetic fields those machines need and sloshes back and forth on the wires. Power factor is the ratio between the two: real power (kW) divided by apparent power (kVA). A power factor of 1.0 means every amp on the wire is doing work. A power factor of 0.70 means you're moving a lot of current to get 70% of it as useful power.

Correction adds equipment, usually capacitors, that supplies that reactive current locally so the utility doesn't have to. The U.S. Department of Energy's motor fact sheet lists the usual culprits: inductive loads such as electric motors, transformers and high-intensity discharge lighting, plus lightly loaded or idling motors. Utilities care because they have to size wires, transformers and generators for the full current, not just the part you're billed for in kWh.

How a low power factor shows up on a Minnesota commercial bill

On Xcel Energy's Minnesota General Service rate (rate code A14, the schedule most mid-size businesses land on once demand reaches 25 kW), the power factor penalty is built into demand, not listed as its own line item. The tariff says billed demand is your actual maximum 15-minute demand divided by your power factor, "but not more than a 90% power factor," then multiplied by 90%.

In plain terms: at 90% or better, nothing changes. Below 90%, your billed kW is inflated by 0.90 ÷ your power factor. Two details from the same tariff sheet matter:

• Who actually gets measured. Power factor is metered for three-phase customers with services above 200 amps or above 480 volts. Single-phase customers and three-phase services of 200 amps or less are assumed to be at 90%, so they don't see a penalty.
• The ratchet. Billed demand can't be less than 50% of your greatest adjusted demand in the prior 11 months, so one bad summer month echoes into winter bills.

Other Minnesota utilities do it similarly. Minnesota Power, for example, explains that it starts adjusting at 90% and gives an example where a 100 kW peak at a 70% power factor is billed as about 129 kW. Co-ops set their own rules, so check your tariff or ask your account rep. If your bill shows a billed or adjusted demand higher than your metered demand, power factor (or the ratchet) is the usual reason.

A worked example: what a 0.78 power factor costs

Take a shop on Xcel's General Service rate with a 200 kW peak and an average power factor of 0.78. Xcel's posted demand charges at secondary voltage are $16.49 per kW in June through September and $11.90 per kW in October through May (check the current rate book; they change with rate cases, including the 2026 order in Docket 24-320).

That's before riders and taxes, which are applied on top. How much correction does that take? The reactive power you need to cancel is kW × (tan φ before − tan φ after). For 200 kW going from 0.78 to 0.90, that's about 64 kVAR; going all the way to 0.95 takes about 95 kVAR. Engineers size the bank from logged data, not one bill, because power factor swings with what's running.

Capacitor banks vs. VFDs: two different tools

People often lump these together. They solve different problems.

Capacitor banks

Capacitors supply reactive power right where it's needed. DOE's example shows a plant at 100 kW and 142 kVA (0.70 power factor) adding capacitors to reach 0.95, cutting apparent power to 105 kVA and current by 26%. Options include:

• Fixed capacitors at large motors. They switch on and off with the motor. Placing correction near the load also cuts current (and I²R losses) in your own feeders, which a bank at the service entrance can't do.
• An automatic (stepped) bank at the main switchgear. A controller adds or drops capacitor steps as load changes. It fixes the bill, but not the current inside your building.
• Detuned filter banks. Capacitors paired with reactors, designed so the system's resonant point sits below expected harmonics. These are the safe choice when drives are present.

Variable frequency drives

A VFD's main job is energy savings: slowing fans and pumps that don't need to run flat out. VFDs change the power factor picture in two ways. Drives are nonlinear loads that generate harmonic currents, and adding plain capacitors to a system with harmonics can create a resonance that blows fuses and cooks equipment. Trade guidance in EC&M is direct about it: you "can't indiscriminately add power factor correction capacitors to a system." On the other hand, some modern drives are designed for it; ABB, for example, says its ultra-low-harmonic drives achieve a unity power factor. If you're replacing old across-the-line motor starters with drives anyway, the power factor fix may come with the project.

Pairing power factor correction with a commercial energy audit

A low power factor is rarely the only issue in a building that has one. Oversized, lightly loaded motors cause poor power factor and waste energy. That's why power factor work fits naturally inside a commercial energy audit. A useful audit includes:

1. Twelve months of bills to compare metered vs. billed demand and spot ratchet months.
2. A power-quality logger on the service for at least a week of normal operation, recording kW, kVAR, power factor and harmonic distortion.
3. A motor inventory: nameplate horsepower vs. measured load, so you fix oversized motors instead of just compensating for them.
4. Lighting review. Old HID fixtures are inductive loads; a commercial LED lighting retrofit can trim both kW and reactive load.
5. A solar check. Solar lowers the kW you buy, but not the reactive power your motors draw, so measured power factor can drop after a PV system goes in. We look at this on every commercial solar project, alongside the demand-charge effects we cover in how solar cuts Xcel demand charges.

Payback on correction can be quick. EC&M notes capacitor projects paying back in as little as four to six months in some facilities. But the real number depends entirely on your penalty, your load profile and whether harmonics force a filtered design.

Is power factor correction worth it for your building?

Quick screen before you spend anything:

• Is your service three-phase and above 200 amps or 480 volts? If not, Xcel's General Service rate assumes 90% and there's no penalty to remove.
• Is billed demand consistently higher than metered demand? Divide the two; that ratio is roughly 0.90 ÷ your power factor.
• Do you have drives, welders or large electronic loads? Then plan on a harmonic study before any capacitors go in.

Get your demand and power factor looked at

iSolar's electrical team works on commercial services across the Twin Cities and greater Minnesota. Send us a year of bills and we'll tell you whether power factor is costing you money, and whether correction, drives or solar makes the bigger dent. You can contact us directly or run your numbers through the commercial solar ROI calculator first.

Sources

• Xcel Energy — Minnesota Electric Rate Book, Section 5, General Service (A14), Sheets 5-26 to 5-27
• Minnesota Power — Commercial Power Factor Billing Impact
• U.S. Department of Energy — Motor Challenge fact sheet on power factor (DOE/GO-10096-286)
• EC&M — Power Factor Correction and Harmonic Resonance: A Volatile Mix
• Consulting-Specifying Engineer — Power Factor Correction Capacitors: Part 2
• ABB — Basics of the harmonics (low-harmonic drives)