Why Does Your Utility Charge a Power Factor Penalty?

A power factor penalty is a charge a utility adds when a plant draws more reactive power (kVAR) than its tariff allows. Reactive current magnetizes motors and ballasts but turns no shaft. It still takes up wire and transformer capacity and causes line losses, so tariffs recover the cost through kVA demand billing, a demand adjustment or a per-kVAR charge.

Which of those methods your utility uses matters more than the power factor reading itself. In the worked example below, one 1,000 kW plant running at 0.80 power factor pays about $160 a month under one tariff structure and about $3,754 a month under another. Before you get a quote for capacitors, read the rate schedule.

What the charge looks like on a bill

The University of Nebraska-Lincoln Extension publication Understanding Electricity Bills (G2312) walks through a sample manufacturing bill read on 08/04/2016. The plant ran at 89.83% power factor and drew 482.60 kVAR. The tariff allowed 394.56 kVAR, which left 88.04 kVAR of excess, and the excess cost $228.47 on a bill totaling $27,342.85. That works out to about $2.60 per excess kVAR. (That's our division. The publication doesn't state it.)

The authors say "kVar charges are usually only around 1 percent of the total electrical bill," and that many providers add a charge once power factor drops below 90%. That's a fair description of the per-kVAR tariffs they deal with. As the sections below show, it doesn't hold where low power factor raises the billed demand itself.

Why utilities bill for power they can't sell

Orange & Rockland's customer explanation says reactive power "is required for electric motors, fluorescent ballasts and other equipment to be magnetized and start up." That current moves back and forth between the grid and the load without doing work, so a kWh meter doesn't register it, and a kW meter doesn't either. The utility still has to size its conductors and transformers for the total current, and it still pays for the losses that current causes in the lines. Without a reactive charge, a plant with poor power factor would use more of the utility's equipment than its energy bill pays for.

This line item matters more for industrial accounts than the energy rate would suggest. The U.S. Energy Information Administration puts the 2025 average industrial electricity price at 8.62 cents per kWh. EIA notes that industrial customers can take service at higher voltages and that their price "is generally close to the wholesale price of electricity." Since the per-kWh energy price is already close to wholesale, demand charges and reactive charges make up much of what a plant can still reduce.

Three ways tariffs bill reactive power

Energy Tariff Experts describes three structures. Its examples come from utilities that have since been folded into Eversource and FirstEnergy, so read them as examples of how the methods work, not as current rates.

• kVA demand billing. In Connecticut Light & Power's territory, demand is billed in kVA rather than kW, so "PF is baked into the demand charge." Every point of power factor you lose raises billed demand.

• Demand adjustment. The former NStar/Boston Edison rate B7 "charges customers the greater of their demand in kW or 90% of their kVA demand." In the firm's example, a customer peaking at 850 kW and 1,000 kVA (85% power factor) "would pay for 900 kVA of demand." That's 50 more units than a customer at 90% or better would pay for.

• Per-kVAR or per-kVARh charges. West Penn Power charged $0.40 per kVAR of reactive demand above 35% of kW demand. Seattle City Light currently lists a power factor charge of $0.0015 per kVARh and says the charge "is only assessed if the power factor is less than 97%."

Thresholds also vary. Ed Kwiatkowski of Staco Energy Products, writing in Consulting-Specifying Engineer, says many utilities set a minimum of 0.85 to 0.95 and add a premium below it. Orange & Rockland charges large commercial customers below 95%, and Seattle's line is 97%.

Where low power factor comes from on the floor

Induction motors cause most of it, along with anything else that needs a magnetizing current. A plant full of across-the-line motors on pumps, fans, compressors and conveyors will run at a lagging power factor unless something offsets it. At the motor level, U.S. Motors (Nidec) says in its ProFacts sheet that "a properly sized capacitor will offset most of the lagging current of a motor and raise its power factor to about 95%."

Worked example: one plant, three tariffs

Take a plant that peaks at 1,000 kW at 0.80 power factor. The standard formulas are kVA = kW ÷ PF and kVAR = kW × tan(arccos PF), which give 1,250 kVA and 750 kVAR at peak. The plant and the rate combinations are illustrative. The dollar figures come from published rates and our own arithmetic.

Under an NStar-style rule (bill the greater of kW or 90% of kVA), billed demand is 90% × 1,250 = 1,125 kW. That's a 125 kW penalty every month the peak repeats. Its cost then depends on the $/kW rate:

The $30.03/kW figure is the monthly demand charge in OpenEI's listing of PG&E's B-19 Medium General Demand TOU (Primary), effective 10/01/2024. The listing also shows TOU demand components of $1.54 and $5.40 per kW. We use the B-19 rate only to show what a high $/kW level does to the penalty. PG&E's own power factor provision isn't modeled here. The $5.18/kW figure is Seattle City Light's peak demand rate for Large General Service (1,000-9,999 kW) inside the City of Seattle. The same class pays $11.05/kW in the Downtown Network.

For the per-kVAR case, 35% of 1,000 kW gives a 350 kVAR allowance. At 750 kVAR the plant is 400 over, and at $0.40 each that comes to $160 a month. The power factor and the plant are the same in every row, but the annual penalty ranges from about $1,920 to about $45,045.

Size the bank to the tariff threshold, not to unity

The capacitor needed to move from one power factor to another is kW × (tan θ1 − tan θ2). For the example plant:

• At 0.90 PF, the plant can carry about 484 kVAR, so it needs about 266 kVAR of correction. That ends the penalty under the 90%-of-kVA rule, because 90% of the new 1,111 kVA is 1,000 kW.

• At 0.95 PF, the plant can carry about 329 kVAR, so it needs about 421 kVAR of correction.

Under a 90% rule, going from 0.90 to 0.95 adds about 155 kVAR, which is roughly 58% more capacitor, and it saves nothing more on the penalty. Under a 95% threshold like Orange & Rockland's, or Seattle's 97%, the target moves up and so does the bank. The number to size against is the threshold in your tariff.

Correcting at individual motors has its own limit. EC&M's guidance on single induction motors says: "You should consider 95% correction as the upper limit, with 90% being the optimum target." The article warns that over-correction brings "high transient torques, overvoltages, and other problems," and it recommends installing the capacitor between the starter and the motor.

Does it pay back?

We couldn't verify installed capacitor costs from a primary source, so this section works backward from a budget instead of quoting a price. Payback in years equals installed cost divided by the annual penalty avoided. For a two-year payback:

Compare vendor quotes with these numbers. In the high-demand-rate case, a 266 kVAR bank has a lot of budget to work with. In the per-kVAR case, penalty savings alone make a bank hard to justify. Kwiatkowski also notes in Consulting-Specifying Engineer that small capacitors often cost proportionally more than large ones, mostly because of installation. Scattering many small units across a plant can therefore cost more per kVAR than one bank at the service entrance.

Drives change the math

Variable frequency drives complicate the picture. Writing for Design World's Motion Control Tips, Danielle Collins explains that VFDs "typically have very high" displacement power factor, because the DC bus capacitors supply the motor's reactive current. The drive's harmonic currents, though, end up "negating some of the power factor benefits of the VFD," which lowers true power factor. Current THD runs about 5% for active-front-end drives and up to about 45% for standard diode-rectifier drives. Line reactors and DC link chokes are the usual ways to reduce it.

Collins calls VFDs "often the best solution" for underloaded induction motors and also "not the panacea that some manufacturers suggest." In practice, a drive retrofit should be justified by energy savings on variable-torque loads such as fans and pumps, with the power factor improvement counted as a secondary gain. On motor-level capacitors, EC&M's rule is: "Never use this type of PF correction with a motor that's controlled with a solid-state device."

The resonance risk when capacitors meet drives

"Every system with a capacitor has a parallel resonant point," Daniel J. Carnovale wrote in EC&M. When drives inject harmonics close to that frequency, "harmonic resonance results in very high harmonic currents and voltages at the resonant frequency." In his example, a 1,500 kVA transformer with 5% impedance and a 250 kVAR bank resonates near the 11th harmonic. The warning signs he lists are blown capacitor fuses, failed capacitor cans and, in the worst case, a failed source transformer.

His remedies are "de-tuned harmonic filters or an appropriately sized capacitor," a check of each switched step of an automatic bank (each step moves the resonant point), and a frequency scan before installation. Consulting-Specifying Engineer gives similar cautions. On a plant with a meaningful drive load, budget for a detuned bank or a resonance study before deciding between capacitor sizes.

Operator checklist

• Find the power factor clause in your rate schedule. Identify the billing method (kVA demand, demand adjustment, or per-kVAR/kVARh) and the threshold.

• Pull 12 months of interval data for kW, kVA and kVAR. Look at power factor during the demand peak, not the monthly average, if the tariff bills on peak.

• Calculate the annual penalty at your actual $/kW or $/kVAR rate. That number sets your capex ceiling.

• Size correction to the tariff threshold using kW × (tan θ1 − tan θ2). Don't size to unity.

• List your drive loads and screen for harmonics. If drives make up a significant share of the load, specify detuned banks or require a frequency scan.

• Get vendor quotes and compare them with your breakeven budget. Compare one central bank with distributed motor capacitors, since small units carry higher installed cost per kVAR.

Related reading

• What Plant Data Does NVIDIA FOX Need Before Agents Can Help?

• How a sole-source rib kit stalled Boeing's 777 Freighter wing line

• Steel and Memory Keep Factory Prices Paid Above 70

• More Sustainability coverage

Sources

• Energy Tariff Experts: Power Factor and Demand Charge Penalties

• Seattle City Light: Business Rates

• Orange & Rockland: Reactive Power (rates & tariffs)

• Orange & Rockland: Reactive Power (your bill)

• University of Nebraska-Lincoln Extension G2312: Understanding Electricity Bills

• OpenEI Utility Rate Database: PG&E B-19 Medium General Demand TOU (Primary)

• U.S. EIA: Electricity prices and factors affecting prices

• Consulting-Specifying Engineer: The economics of improving power factor

• EC&M: Power Factor Correction and Harmonic Resonance: A Volatile Mix

• EC&M: The Basics of PF Correction on Single Induction Motors

• Motion Control Tips: The truth about VFDs and power factor

• U.S. Motors (Nidec) ProFacts: Power Factor Correction Capacitors