In short. A transformer in a generator system does more than change voltage. Its magnetising inrush is a load step the generator must survive, its impedance sets the fault current and voltage drop downstream, its vector group fixes the earthing and phase relationship, and its protection must distinguish inrush from a fault. A 415 V set energising an unloaded step-up transformer can see a current many times the transformer rating for several cycles, so the energisation strategy is part of the design.
When generators and transformers meet
Three situations bring a transformer into a generator project. A 415 V set is stepped up to 11 kV so its power can cross a campus or join an MV plant, as described under MV generator switchgear. An 11 kV plant is stepped down to feed 415 V distribution through the PCC and MCCs. Or a rental set must supply a site at a different voltage, common in temporary power for construction and events. In each case the transformer is a passive device with an active effect on the generator, and sizing it by kVA alone, which the transformer sizing guide covers, is only the first step.
The variables that decide behaviour
| Variable | Typical value for distribution transformers | Why it matters to the generator |
|---|---|---|
| Rating (kVA) | Matched to downstream load, not to the generator | Oversized transformer means larger inrush and higher no-load loss |
| Percentage impedance | 4 to 6 percent up to about 2,500 kVA | Sets fault current and regulation under motor starting |
| Vector group | Dyn11 for most 11 kV / 415 V units | Provides the LV neutral; delta blocks triplen harmonics |
| Magnetising inrush | 8 to 12 times rated current peak, decaying over cycles | Voltage dip, AVR response, protection ride-through |
| Neutral earthing | Solid on the LV star point | Defines the earth-fault return path for LV protection |
| Cooling and location | ONAN oil-filled outdoors, dry-type indoors | Ambient derating at 45 °C, clearances, fire separation |
Energisation: the inrush problem
When a transformer is switched onto a live supply, the core may saturate on the first half cycle and draw a magnetising current that bears no relation to the load. The peak depends on the point on the voltage wave at closing and on the residual flux left in the core, which is why the same transformer gives a different inrush every time. From a stiff grid this is a nuisance for protection. From a generator it is a real event: the current is highly reactive and distorted, the alternator terminal voltage dips, the AVR drives excitation to recover, and if the dip is deep enough the generator’s own undervoltage protection or the loads already connected can trip.
Inrush peak ≈ k × Irated
Here Irated is the transformer rated current on the energising side and k a multiplier typically between 8 and 12 for the first peak, falling to a few times rated within ten to twenty cycles. Worked example (illustrative): a 1,000 kVA, 415 V / 11 kV step-up transformer has an LV rated current of about 1,391 A, so a first-peak inrush of around 11,000 to 16,000 A is possible. A 1,250 kVA generator on the same bus would see that as a load far outside its normal transient envelope. In practice the generator’s own subtransient reactance limits the current, and the resulting voltage dip, not the theoretical peak, is what the study must determine. A transient study, described in transformer energisation studies, gives the answer where the ratio is large.
Strategies that work
- Soft energisation: close the generator breaker onto the transformer while the set is at low excitation, then ramp voltage. Many AVRs offer a soft-start ramp precisely for this. The transformer never sees a step and there is no inrush.
- Energise before load: bring the transformer in while the generator is otherwise unloaded, so the full transient margin is available, then add load.
- Sequence multiple transformers one at a time rather than together.
- Size the generator with the energisation case included, not only the running load. Where the transformer rating is close to or above the generator rating, a study is needed before anyone presses the button.
Impedance, fault current and voltage drop
Transformer impedance works in two directions. A lower impedance gives stiffer voltage under motor starting on the far side but a higher fault current, which raises the duty on downstream breakers and busbars. A higher impedance limits fault current but increases the voltage drop under load. When a generator is on the primary side, the fault current available on the secondary is limited by the generator reactance and the transformer impedance in series, and can be far lower than the same transformer fed from the grid. Protection downstream, set up for utility fault levels, may then operate slowly or not at all. This interaction is worked through in transformer impedance and fault contribution and must be fed into the protection coordination for both source modes.
Protection that tells inrush from a fault
Transformer protection on a generator-fed system needs three things. The instantaneous overcurrent element on the energising side must be set above the inrush peak or be restrained by second-harmonic content, otherwise every energisation trips. A differential relay, used on larger units, needs the same second-harmonic restraint and a correct vector-group compensation. And the earth-fault protection on the LV star point must be coordinated with the generator’s own neutral earthing when both the generator neutral and the transformer neutral exist on the same system, a topic covered under earthing and neutral architecture. Mechanical protections on oil-filled units, the Buchholz relay, winding and oil temperature and pressure relief, trip the generator breaker as well as the transformer breaker where the generator is the only source.
Paralleling two transformers on generator supply
Where two transformers share a bus, they must have the same voltage ratio, the same vector group, impedances within about ten percent of each other and compatible tap positions. Unequal impedances share load unequally and the lower-impedance unit overloads first; unequal ratios circulate current between the units even with no load connected. Paralleling also roughly doubles the fault current on the common bus. On generator supply the extra consideration is that the generator must be able to energise both, and the circulating current from a ratio mismatch is a reactive load the alternator carries for nothing.
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Common mistakes
- Sizing the generator for running load and discovering the step-up transformer at commissioning. The first energisation trips the set on undervoltage or reverse power.
- Leaving instantaneous overcurrent at the utility setting. The transformer cannot be energised from the generator without a trip.
- Choosing an oversized transformer for future growth. No-load losses are paid every hour and inrush grows with the core, not the load.
- Paralleling transformers with different tap positions. Circulating current heats both units while the plant runs at part load.
What to send us
Send the transformer nameplate photograph showing kVA, voltages, vector group, impedance and tap positions, the generator rating and alternator data sheet if available, the single-line diagram, and a description of how the transformer is to be energised and what load sits behind it. For rental applications tell us the site voltage and the largest motor. Use the application engineering enquiry page.
Questions engineers ask
How large a transformer can a generator energise?
There is no single ratio. With direct closing, a generator can often energise a transformer of similar kVA with a noticeable but tolerable dip, and smaller transformers comfortably. With a soft-start excitation ramp the limit disappears because inrush never develops. Above roughly equal ratings, or where sensitive loads are already connected, a transient study should be done.
Why does the transformer trip on energisation from the generator but not from the mains?
Usually because the instantaneous overcurrent or differential element sees the inrush as a fault. On mains the inrush is identical, but the relay may have been set with margin against it. From the generator the voltage dips during inrush, the waveform is more distorted, and marginal settings fail. Enabling second-harmonic restraint or raising the instantaneous pickup with a short delay corrects it.
Does the vector group matter if the generator only feeds one transformer?
Yes, for earthing. A Dyn11 unit supplies a star point on the LV side which becomes the system neutral for that side, and the delta primary isolates the generator neutral from the LV network. If the LV side needs a neutral and the transformer has none, an earthing transformer is required.
Can a rental generator feed a site through a step-down transformer?
Yes, and it is common when a 415 V set supplies equipment at other voltages or when an 11 kV rental plant feeds a 415 V site. The transformer must be rated for the site load, the generator sized to energise it, and the earthing of the new LV system designed, since the transformer creates a separately derived source.
Technical content reviewed by Srinivas Reddy, Managing Partner, Reddy Generators. Last updated 19 October 2026.