Power Factor Correction Calculator

Parameters

Seven fields are always on the form, and fourteen more sit in collapsed sections for staging, capacitor hardware, harmonic resonance, feeder losses, tariff and light load. Every optional field is blank by default, and leaving them all blank gives exactly the basic bank sizing. Each one, once entered, changes a result, a check, a warning or a step in the working.

Active power

The real power the installation draws, in kilowatts. Form range 1 to 10000, default 100. Every kilovolt-ampere reactive figure scales directly with it, so it is the single most important input on the page. Take it from a demand meter, a power quality logger or the sum of connected loads with diversity applied. Gotcha. Use the kilowatts that coincide with the power factor you enter, ideally a peak demand interval. A yearly average kilowatt figure paired with a worst case power factor will size a bank that overcorrects for most of the year.

Current power factor

The measured, uncorrected power factor. Dimensionless, form range 0.1 to 0.99, default 0.75. Typical uncorrected values are 0.65 to 0.80 for a motor-heavy factory, 0.80 to 0.90 for a commercial building with chillers and air handling, and above 0.95 where loads are largely resistive. Gotcha. Use a measured value, not a nameplate one. Also be aware whether your meter reports displacement power factor or true power factor. On a site with drives and switching supplies the two differ, and capacitors correct only the displacement component. Correcting to a true power factor target with capacitors alone will not work.

Target power factor

The power factor you want after correction. Dimensionless, form range 0.9 to 0.99, default 0.95. Most Australian distributors set 0.90 as the threshold below which demand penalties apply, so 0.95 is a common target because it leaves margin. Gotcha. Do not chase unity. The kilovolt-ampere reactive required climbs steeply above about 0.97 for very little further reduction in apparent power, and a fixed bank sized to unity at peak will push the site leading at light load, which raises voltage and can be penalised in its own right. Entering a target below the current power factor produces a negative requirement, which the tool clamps to zero.

Supply voltage

Selectable as 230, 400, 415 or 11000 V. Gotcha. The required kilovolt-amperes reactive is independent of voltage, so it is the same at 400 V as at 11 kV. Voltage matters to the hardware: once you choose a capacitor connection it sets the capacitance in microfarads, the bank rated current and the AS/NZS 3000 discharge period, and with a feeder resistance it sets the line current and losses.

Supply phase

Single phase or three phase. Gotcha. The total kilovolt-amperes reactive required is a whole-of-supply figure either way. Phase matters for the rated current (divided by root 3 times the line voltage on three phase, by the voltage on single phase), for the capacitance per phase and for feeder losses, which count three conductors on three phase and two on single phase.

Frequency

Selectable as 50 Hz or 60 Hz. Gotcha. Frequency sets the detuning frequency, the supply frequency divided by the square root of the reactor fraction. A 7 per cent reactor tunes to 189 Hz on 50 Hz and 227 Hz on 60 Hz. Earlier versions of this tool reported 189 Hz on both, which was wrong on 60 Hz and is now corrected. Frequency also sets the capacitance in microfarads and the resonance frequency in hertz.

Significant harmonics

A checkbox for sites with variable speed drives, rectifiers or large switching power supplies. Ticking it turns on a detuning recommendation when the required compensation exceeds 20 kilovolt-amperes reactive. Gotcha. On its own it is a yes or no flag, not a harmonic study. Enter a fault level or transformer details below to get an actual resonance order. A resonance close to a characteristic harmonic turns the detuning recommendation on whether or not this box is ticked.

Step size and number of steps

Optional, in kilovolt-amperes reactive and a whole number of 1 to 24. Enter a step size and the tool uses enough steps to cover the requirement, or the number you give. Enter only a number of steps and the standard bank is split equally. The result shows the power factor with each step switched in, models an automatic controller that switches in the fewest steps that reach your target without going leading, and adds a staged capacity check and a full-load power factor check. Gotcha. The controller model is simple. A real relay has a response band (C/k setting), switching delays and step rotation, so treat the step chosen as indicative.

Capacitor connection

Optional, delta or star. Choosing one gives the capacitance per phase in microfarads (delta: Q divided by 3 times 2 pi f times V squared; star: Q divided by 2 pi f times V squared, three times the delta value), the rated current of the bank and of each step, and the AS/NZS 3000 Clause 4.15 requirements: conductors rated not less than 135 per cent of the capacitor rated current (Clause 4.15.2.3), contactor and fuse control permitted only for capacitors of not more than 100 kVAr and otherwise a circuit-breaker with an overcurrent release (Clause 4.15.3.3), and discharge to 50 V within 1 minute up to 650 V or 5 minutes above (Clause 4.15.3.1). Gotcha. On a fixed bank the tool applies the 100 kVAr test to the whole bank. A bank built from smaller units may qualify unit by unit, so check the actual make-up. The conductor figure must also be not less than the circuit-breaker setting where one is used.

Fault level, transformer rating and impedance

Optional. Enter the fault level at the bank in MVA, or a transformer rating in kVA with its impedance in per cent (1 to 20), which estimates the fault level as kVA divided by the impedance fraction. The tool then gives the parallel resonance order h, the square root of fault level over bank kvar, for the full bank and for every switching stage, and checks that the worst stage is at least 10 per cent (indicative) away from the 5th, 7th, 11th and 13th harmonics. Gotcha. The transformer estimate assumes an infinite source upstream, so it overstates the fault level and the resonance order. Running on a generator or with an alternate supply lowers the fault level and moves the resonance down.

Detuning reactor

Optional, per cent of capacitor reactance (1 to 20), for example 7. It sets the detuning frequency, gives the tuning order 1 divided by the square root of the reactor fraction, checks that it sits below the 5th harmonic, and gives the capacitor voltage raised by the reactor, the supply voltage divided by one minus the fraction. Entering it replaces the undetuned resonance check. Gotcha. A 7 per cent reactor on 400 V raises the capacitor voltage to about 430 V before harmonics, so the capacitors need a higher voltage rating than the supply.

Feeder resistance, operating hours and energy price

Optional. The resistance of one active conductor of the feeder in ohms gives the line current before and after correction and the I squared R loss saving. Operating hours turn that into kilowatt hours a year, and the energy price turns it into dollars. Gotcha. This is the only part of the energy bill that correction reduces, and it is usually small. Hours and price do nothing without a resistance, and the tool says so.

Demand charge and bank cost

Optional. A demand charge in dollars per kVA per month gives the monthly and yearly saving from the reduced kVA demand at full load with the bank as installed. A bank cost gives a simple payback against the demand and energy savings. Gotcha. Network tariffs differ. Some bill the peak kVA in a rolling window, some bill kW with a power factor penalty, and some do not bill demand at all. Check yours before trusting the payback.

Minimum load and its power factor

Optional. The light-load kW (nights, weekends, shutdowns) and its lagging power factor, which defaults to the current power factor. The tool works out the reactive demand at that load and the power factor with the bank in: a fixed bank stays fully in, a stepped bank switches out to the fewest steps that reach your target. A check fails if the site is driven leading. Gotcha. Light-load power factor is often worse than full load because motors run unloaded, so enter a measured value if you have one.

Assumptions and limits

What the tool assumes

• Two operating points at most. A full-load point and, if you enter it, a minimum-load point. There is no full load profile. A stepped bank is modelled as an automatic panel that switches in the fewest steps reaching the target without going leading; a bank without steps is treated as fixed.
• Purely displacement power factor. The maths is the standard trigonometric relationship, required kilovolt-amperes reactive equals active power multiplied by the difference between the tangent of the present phase angle and the tangent of the target phase angle. That relationship only holds for the fundamental. Harmonic distortion is not modelled anywhere in the numbers.
• Lagging power factor throughout. Both power factors are treated as lagging and correction is always assumed to be capacitive. A site already leading is not handled.
• The bank rounds up to a standard size. The selection comes from the series 5, 10, 15, 20, 25, 30, 40, 50, 60, 75, 100, 125, 150, 200, 250, 300, 400 and 500 kilovolt-amperes reactive, always choosing the first entry at or above the requirement. That deliberately overcorrects, sometimes by a lot on small requirements. Enter a minimum load to see whether the bank drives the site leading at light load.
• The current saving figure is a current reduction, not money. It is one minus the ratio of the two power factors, expressed as a percentage. It is the percentage reduction in apparent power and therefore in line current. It is not a reduction in your energy bill, because kilowatt hours do not change. Enter a demand charge, and a feeder resistance with hours and an energy price, to get dollar figures.
• Hardware is sized, not designed. With a connection chosen you get capacitance, rated current, the Clause 4.15.2.3 minimum conductor rating and the Clause 4.15.3.3 control device. There is no cable selection, no protection setting, no thyristor switching, no enclosure or ventilation design and no harmonic filter design.
• Resonance is a screening estimate. The order h equals the square root of fault level over bank kvar, the classic parallel resonance between the bank and the supply inductance. It ignores load damping, other capacitance on the network and cable capacitance. The 10 per cent margin is an indicative screening value, not a figure from a standard.

What the compliance checks actually check

Two checks always run. The first confirms your target power factor is at least 0.90, which is a check on what you typed rather than on the installation. The second confirms the standard bank is at least the required kilovolt-amperes reactive, which passes by construction unless the requirement exceeds 500 kilovolt-amperes reactive. The optional inputs add up to five more: staged bank capacity, full-load power factor reached with the steps switched in, resonance clear of the 5th, 7th, 11th and 13th harmonics (or, with a reactor, tuning below the 5th), and no over-correction at minimum load. None of them is a harmonic study.

What this must not be used for

• Final capacitor bank design, including step sizing, switching scheme, controller settings, protection or the bank subcircuit.
• Any decision about detuned reactors or harmonic filters. That requires a measured harmonic spectrum and a resonance study against the actual supply impedance.
• Sites with significant harmonic distortion where true power factor rather than displacement power factor is the problem. Capacitors do not correct distortion power factor and can make it worse.
• Estimating a financial payback. The current saving percentage is not a bill saving.
• Correcting individual motors at the starter, which needs the motor's magnetising current so the capacitor does not self-excite the machine on coast down.
• Evidence of compliance. This calculator is a design aid, not a certification. Check every result against the current edition of AS/NZS 61000.3.100, your distributor's connection requirements and a site harmonic assessment, and have it signed off by the person responsible for the installation.

Worked examples

Five examples. The first three use only the basic fields. The last two use the optional inputs: a staged bank with hardware, losses, tariff and light load, and a resonance screen with and without a detuned reactor. The tangent values below are the tangent of the arc cosine of each power factor, which is what the calculator computes internally.

Power Factor Correction Guide for AS/NZS 61000.3.100

Power factor correction is the process of adding capacitors (or other reactive compensation equipment) to an electrical installation to reduce the reactive power drawn from the supply network. In Australia, supply authorities penalise sites that operate with a power factor below 0.90 through demand charges on the excess kVA. For industrial and commercial sites with significant motor loads, power factor correction is one of the most cost-effective electrical upgrades available, often paying for itself within 12 to 18 months through reduced electricity bills.

This calculator determines the capacitor bank size (in kVAR) needed to raise an existing power factor to a target value. Enter your site's real power consumption, current power factor, and desired target. The calculator computes the required reactive compensation and shows the reduction in apparent power (kVA) and line current that results from the correction.

Key concepts

• Real, reactive, and apparent power. Real power (kW) does useful work. Reactive power (kVAR) sustains the magnetic fields in motors and transformers but performs no useful work. Apparent power (kVA) is the vector sum of real and reactive power, and it is what the supply network must deliver. Power factor is the ratio of kW to kVA. A power factor of 0.80 means only 80% of the apparent power is doing useful work.
• Why low power factor costs money. The supply authority sizes transformers, cables, and switchgear based on kVA, not kW. A site drawing 200 kW at 0.70 power factor requires 286 kVA from the network, while the same 200 kW at 0.95 power factor only requires 211 kVA. The extra 75 kVA wastes network capacity and increases I squared R losses in cables. Most Australian tariffs charge a demand penalty when power factor falls below 0.90.
• Capacitor correction principle. Capacitors generate leading reactive power that cancels the lagging reactive power drawn by inductive loads. The net reactive power seen by the supply decreases, which reduces apparent power and improves the power factor. Capacitors can be installed at the main switchboard (bulk correction) or at individual motor starters (point-of-load correction).
• Harmonic resonance risk. A capacitor bank and the supply transformer inductance form a parallel resonant circuit. If the resonant frequency aligns with a harmonic present on the network (commonly the 5th harmonic at 250 Hz), harmonic currents can amplify and damage equipment. Detuned reactors, rated at 7% or 12.5% impedance, are installed in series with capacitors to shift the resonant frequency below the lowest significant harmonic.

Common scenarios

• Manufacturing facility with motor loads. A factory running multiple induction motors typically has a natural power factor between 0.65 and 0.80. Installing a bulk capacitor bank at the main switchboard to correct to 0.95 reduces the site's kVA demand, lowers the electricity bill, and frees up capacity on the existing transformer for future loads. An automatic power factor correction (APFC) panel is preferred because the motor load varies throughout the day.
• Commercial building HVAC systems. Large air-handling units and chiller compressors are inductive loads that pull the building's power factor down during peak cooling periods. Seasonal load variation makes fixed capacitor banks unsuitable because they can overcorrect during light-load periods (leading to a leading power factor, which can cause voltage rise). An APFC system with multiple switched stages is the standard solution for these installations.
• Transformer capacity recovery. A site with a fully loaded 1000 kVA transformer at 0.80 power factor is drawing 800 kW. Correcting to 0.95 reduces the apparent demand to 842 kVA, freeing approximately 158 kVA of transformer capacity. This can defer or eliminate the need for an expensive transformer upgrade when adding new loads to the site.