MV power factor correction is the installation of capacitor banks (or, for dynamic loads, static var/harmonic-filtered compensation) on a medium-voltage bus — typically the incoming supply of a distribution substation — to reduce reactive power drawn from the grid and raise the displacement power factor of a plant closer to unity. Where an industrial site has a very large aggregate reactive demand upstream of many low-voltage boards, correcting at the MV bus is often more economical than correcting each LV panel individually, because a single MV bank offsets the reactive current seen by the incoming transformer and the utility metering point simultaneously. This guide walks through the underlying formula, a fully worked kVAr sizing example, a step-by-step MV-vs-LV decision table, common sizing pitfalls, and the governing IEC standards, and is written for engineers across the Middle East and Gulf region (including Egypt and Saudi Arabia), North Africa, CIS countries, and Sub-Saharan Africa who are specifying compensation equipment for MV substations.
Why power factor correction matters
A low power factor forces the source — the utility grid or an on-site generator/transformer — to supply more apparent power (kVA) than the active power (kW) actually consumed by the load. This has three direct engineering and commercial consequences:
- Utility penalties: many tariffs bill a low-power-factor penalty or charge separately for reactive energy (kVArh).
- Extra losses and voltage drop: reactive current flowing through cables, transformers, and busbars produces resistive (I²R) losses without doing useful work, and depresses the voltage at the load.
- Reduced usable capacity: a transformer or feeder loaded with uncorrected reactive current has less real-power headroom before it reaches its thermal/apparent-power limit.
Correcting the power factor closer to unity reduces the reactive component of current, freeing up transformer and cable capacity, cutting losses, and — where the tariff structure includes reactive energy charges — lowering the electricity bill.
The method / formula
Power factor correction sizing is derived from the reactive power triangle. For an active load P (kW) operating at an existing (uncorrected) power factor cos φ₁, and a target power factor cos φ₂:
Q_required (kVAr) = P × (tan φ₁ − tan φ₂)
where: – φ₁ = arccos(cos φ₁) — the phase angle at the existing power factor – φ₂ = arccos(cos φ₂) — the phase angle at the target power factor – Q_required is the capacitive reactive power (kVAr) that must be added
The apparent power before and after correction is found from:
S = P / cos φ
and the line current from:
I = S / (√3 × V) for a three-phase system, where V is the line-to-line voltage.
This same formula set applies whether the correction is applied at LV terminals or at an MV bus — the difference is where in the network the compensating reactive power is injected, and therefore how much upstream equipment benefits from the reduced reactive current.
Worked example: sizing a capacitor bank
Consider a plant with an active demand of P = 2000 kW, presently operating at an existing power factor of cos φ₁ = 0.75, supplied through an 11 kV MV bus. The target is to raise the power factor to cos φ₂ = 0.95.
Step 1 — find the phase angles
φ₁ = arccos(0.75) ≈ 41.4°, so tan φ₁ ≈ 0.882 φ₂ = arccos(0.95) ≈ 18.2°, so tan φ₂ ≈ 0.329
Step 2 — required capacitive kVAr
Q_required = P × (tan φ₁ − tan φ₂) = 2000 × (0.882 − 0.329) ≈ 2000 × 0.553 ≈ 1106 kVAr
So an MV capacitor bank of approximately 1100 kVAr, connected at the 11 kV bus, would raise the plant’s power factor from 0.75 to 0.95.
Step 3 — apparent power and current before/after correction
Before correction: S₁ = P / cos φ₁ = 2000 / 0.75 ≈ 2667 kVA Line current at 11 kV: I₁ = S₁ / (√3 × 11) = 2667 / (1.732 × 11) ≈ 2667 / 19.05 ≈ 140 A
After correction: S₂ = P / cos φ₂ = 2000 / 0.95 ≈ 2105 kVA Line current at 11 kV: I₂ = S₂ / (1.732 × 11) ≈ 2105 / 19.05 ≈ 110.5 A
The correction reduces the current drawn from the supply by roughly 30 A on this 11 kV feeder for the same 2000 kW of real load — this is current that no longer has to be carried by the incoming transformer, cable, and MV switchgear, freeing up thermal and short-circuit-current margin.
(All numbers in this worked example are illustrative first-principles calculations for teaching the method, not ratings of any specific product.)
MV vs LV correction — comparison and selection table
| Aspect | MV (bus-level) correction | LV (panel/load) correction |
|---|---|---|
| Point of connection | Medium-voltage incoming bus / substation busbar | Individual LV distribution board or at the load |
| Reactive current offset | Reduces reactive current upstream of the MV/LV transformer, freeing transformer and MV cable capacity | Reduces reactive current only downstream of the point of connection; transformer/MV feeder still see the uncorrected component |
| Typical use case | Large aggregate industrial/utility loads with many LV feeders, or where the utility penalises reactive demand at the MV metering point | Individual large motors, drives, or a single LV board with a poor local power factor |
| Switching equipment | MV contactor/circuit-breaker with capacitor-duty rating, or MV static var compensation for dynamic loads | LV contactor or thyristor-switched module, typically with automatic power factor controller |
| Harmonic considerations | Bank often combined with detuned/tuned reactors where the network has significant harmonic content | Same principle, scaled to LV; more common on VFD-heavy boards |
| Economic logic | One bank corrects the whole site’s reflected reactive demand at the utility interface | Correction is local; multiple smaller banks may be needed across several boards for the same site-wide benefit |
| Impact on transformer loading | Frees up transformer kVA headroom seen from the primary side | Frees up only the LV side; the transformer still supplies the pre-correction reactive current from the MV side unless MV correction is also applied |
Selection criteria and common sizing pitfalls
When choosing between MV and LV correction — or specifying capacitor banks at either level — consider:
- Where the reactive demand is measured for billing. If the utility’s reactive-energy penalty is metered at the MV point of common coupling, correction must be applied on the MV side (or upstream of that meter) to have any billing effect.
- Number and dispersion of loads. A site with many scattered LV boards, each with a moderate power factor, is often more economically corrected with one MV bank than with many small LV units — provided the transformer and MV switchgear can be verified for the resulting reactive current change.
- Load dynamics. Motors, VFDs, and welding loads produce rapidly changing reactive demand; a fixed capacitor bank sized from average demand may over- or under-correct at times, causing over-voltage or continued penalty. Automatic power factor controllers that switch capacitor steps in and out are commonly used to track load variation.
- Harmonic content. Capacitor banks can resonate with harmonic-producing loads (VFDs, rectifiers, UPS front-ends). Where significant harmonic distortion is present, detuned or tuned reactor-capacitor combinations are used instead of plain capacitor banks — sizing this is a separate calculation from the basic kVAr formula above.
- Switching transients. Capacitor bank energisation produces an inrush current transient; the switching device (MV contactor/circuit-breaker or LV contactor) must be rated for capacitor-switching duty, and pre-insertion resistors or reactors are sometimes used to limit inrush on larger MV banks.
- Over-correction risk. Pushing the power factor too close to or above unity under light-load conditions can cause leading power factor and voltage rise; step control avoids this by disconnecting capacitor steps as demand falls.
- Coordination with protection. MV capacitor banks are protected and switched through dedicated MV switchgear or ring main unit extension bays; the protection relay settings must account for capacitor-switching inrush and out-of-balance detection on multi-can banks. See our MV switchgear and protection relay hub pages for related equipment selection guidance, and the transformer hub page for how correction interacts with transformer loading.
Standards
Capacitor units and capacitor banks for power factor correction are covered by the IEC 60871 series (shunt capacitors for AC power systems, rated voltage above 1000 V), which defines general requirements, testing, and safety provisions for MV capacitors. Series reactors used with capacitor banks for harmonic detuning are addressed under IEC 60289. Where correction equipment is housed within MV switchgear, the switchgear enclosure and switching devices themselves remain subject to the general MV switchgear standards (e.g., IEC 62271 series) applicable to that equipment type — but the capacitor unit performance itself is governed by IEC 60871. Site engineers should always confirm the applicable edition and any local grid-code requirements for reactive power compensation before finalising a design.
Related guides
See also our guides on medium voltage switchgear, gas-insulated switchgear and metal-clad switchgear.
What is the difference between MV and LV power factor correction?
MV correction connects capacitor banks at the medium-voltage bus, offsetting reactive current seen by the incoming transformer, MV cables, and the utility metering point. LV correction connects capacitors at a low-voltage board or individual load, improving power factor only downstream of that connection point — the transformer and MV feeder still carry the uncorrected reactive current unless MV-side correction is also applied.
How do I calculate the required kVAr for power factor correction?
Use Q_required = P × (tan φ₁ − tan φ₂), where P is the active load in kW, φ₁ is the phase angle at the existing power factor, and φ₂ is the phase angle at the target power factor. See the worked example above for a full numerical walkthrough.
Why would a plant choose MV correction instead of correcting every LV panel?
When a site has many LV boards and the utility penalises reactive demand at the MV point of common coupling, a single MV bank corrects the aggregate reactive demand more economically than installing and maintaining multiple smaller LV banks, and it also frees up transformer and MV cable capacity.
Can power factor correction cause problems with harmonics?
Yes. Plain capacitor banks can resonate with harmonic currents produced by VFDs, rectifiers, or other nonlinear loads. Where significant harmonic distortion exists, detuned or tuned reactor-capacitor combinations are used instead of plain capacitors to avoid resonance.
What happens if a capacitor bank is oversized?
Oversizing can push the power factor to leading (above unity) under light-load conditions, causing voltage rise on the bus. Automatic power factor controllers with switched capacitor steps are used to track load and avoid sustained over-correction.
Which IEC standard governs MV capacitor banks for power factor correction?
Shunt capacitors for AC power systems above 1000 V are covered by the IEC 60871 series; associated series reactors for harmonic detuning are addressed under IEC 60289. The switchgear housing the capacitor switching device follows the relevant MV switchgear standards for that equipment type.
Does correcting power factor reduce transformer loading?
Yes — reducing the reactive current component reduces the apparent power (kVA) the transformer must supply for the same real power (kW) load, as shown in the worked example where the line current dropped from approximately 140 A to 110.5 A after correction, freeing transformer and feeder headroom for additional real-power capacity.
Looking for power factor correction and capacitor banks?
Looking for high-quality power factor correction and capacitor banks? We provide expert engineering support and reliable products for all your medium voltage needs.
For quotations and requests: info@electricistanbul.com
WhatsApp: +90 501 076 69 91