This article is about what really happens at the interface between a PV inverter and a transformer, when DC from the modules turns into AC, and then still has to get along with the grid. A practical look.

You see a PV farm.

Rows of modules like a well-ordered army.

Inverters working quietly, smokelessly, without any theatrics.

And somewhere nearby stands a transformer.

The same type of device that in other projects can be a boring backdrop.

But in photovoltaic installations, a transformer can have its most intense life precisely when everything looks calm.

Because an inverter isn't an ordinary energy source.

It's fast power electronics that can perform wonders with current, but at the same time can introduce phenomena into the system that aren't visible at first glance: harmonics, rapid changes, reactive power control, sometimes minor unwanted components.

And all of this lands at the interface with the transformer.

In PV, one thing is particularly clear: most problems don't arise because the equipment is bad. They arise because the interfaces between equipment are often poorly coordinated.

This article is for designers, contractors, investors, and maintenance people who want the inverter-plus-transformer system to operate stably for years, without nervous adjustments after commissioning.

After reading, you will be able to recognize typical friction points and select solutions that genuinely improve power quality, operating temperatures, and reliability.

First, we'll establish a common language: what actually happens at the interface between the inverter and the transformer.

Then, we'll go through typical problems: harmonics, overheating, reactive power control, overvoltages, and resonances.

We'll discuss the most important tools, breaking them down into their basic elements.

At the end, you'll get five solutions to the most critical problems in transformer-inverter cooperation—including simple 'rule of thumb' methods that improve stability—and you'll receive answers to frequently asked questions on the topic, in a ready-reference cheat sheet.

Worth reading.

Reading time: about 15 minutes

What really happens at the interface between a PV inverter and a transformer

In a textbook, it looks simple: modules produce DC, the inverter turns it into AC, the transformer steps up the voltage, and the grid accepts the energy.

In practice, this interface is where two worlds meet.

The first world is power electronics.

An inverter doesn't generate a sine wave the way a generator does. It synthesizes it by switching transistors at high frequency and controlling modulation. This gives excellent control over active and reactive power, but leaves behind side effects: harmonics, high-frequency disturbances, steep voltage and current rise times.

The second world is the transformer, an electromagnetic device that likes predictability.

It is designed for a specific voltage shape, specific losses, specific temperatures, and specific load dynamics. When it receives a waveform with more content than a pure sine wave, things start to get interesting.

The most important thing to remember is this: a transformer in a PV system isn't just a voltage pass-through. It's the component where the side effects of inverter control and grid parameters materialize.

What language to use to understand each other

Remember the story of the Tower of Babel?

Everyone was supposedly building the same thing, yet each spoke a different language. In a project, it works the same way: if designers, contractors, automation engineers, and service personnel use different words for the same phenomena, diagnosis takes longer than the repair itself.

Harmonics are current or voltage components with frequencies that are multiples of the fundamental. In a 50 Hz grid, the 5th harmonic is 250 Hz, the 7th is 350 Hz, and so on.

For a transformer, this means additional losses and additional heating.

THD (Total Harmonic Distortion) is a measure of the total waveform distortion.

In practice, it's worth separating voltage THD from current THD.

An inverter most often introduces current distortion, while voltage distortion worsens depending on grid impedance and the transformer setup.

Reactive power is the control of voltage and the flow of reactive energy.

An inverter can supply or absorb it according to grid operator requirements, but this control changes the currents in the system and can increase the transformer's load.

Resonance is a situation where inductive and capacitive elements in the system begin to amplify certain frequencies.

In PV systems, there's plenty of capacitance: cables, filters, compensation capacitors, grid properties. Inductance too: chokes, transformers, lines.

It doesn't have to explode, but it can generate overvoltages, vibrations, and... strange protection errors.

Why harmonics make the transformer do extra work

A transformer has no-load losses in the core and load losses in the windings. When harmonics appear, three things happen simultaneously.

The RMS current increases, even if the active power doesn't. This means greater I²R losses in the windings. And that's the first reason for heating.

Added to this are additional losses, such as eddy currents in the windings and structural components. These increase faster with frequency, so higher harmonics can cause disproportionately large thermal damage.

The third thing is noise and mechanical vibrations. The transformer may start operating louder, and the winding mechanics experience greater fatigue over the long term.

The most insidious part is that on SCADA, everything might look decent because the power is stable, and only thermal imaging shows that something is wrong.

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If you want to go deeper and understand how to calculate this and translate harmonics into real requirements for the transformer, we recommend our article:

Transformer K-Factor: The Key to Protection Against Harmonics.

In it, we explain what the K-Factor is, what it tells us about non-linear loads, how it helps select a transformer for actual operating conditions, and how to limit the risk of overheating and insulation life reduction before the problem shows up in temperatures and alarms.

Where overheating comes from when parameters seem normal

There are three typical scenarios.

The first is apparent load.

Someone looks at the MW and is calm, but the transformer is loaded by currents resulting from reactive power and distortion. It doesn't heat up from MW. It heats up from current and losses.

The second is inverter operation in regulation modes.

For example, voltage control via reactive power, active power curtailment, operation under variable grid conditions. This changes the transformer's load profile over time, often faster than in conventional power systems.

The third is a design mismatch.

A transformer selected for a linear load may have too small a margin for additional harmonic losses. The power rating seems to match, but thermally, there's no breathing room.

This leads to a practical conclusion: in PV, checking kVA isn't enough.

You have to think about power quality, the share of reactive power, and the expected operating profile.

Reactive power control: a tool that helps the grid but loads the system

Grid operators increasingly require voltage support.

The inverter then has to implement curves: cos φ as a function of P, Q as a function of U, or a specific set Q.

First, let's break this down in plain language, without magical shortcuts.

Imagine the inverter has two knobs: one for active power P (the one you sell in kWh), and one for reactive power Q (which doesn't give kWh but affects voltage and currents in the grid).

The grid operator tells the inverter how to turn the second knob.

What does 'cos φ as a function of P' mean?

Cos φ is, simply put, information about the share of reactive power relative to active power.

When cos φ is close to 1, there's almost no Q. When it drops, Q increases.

Cos φ as a function of P means:

the power factor should depend on the current active power. The more P you produce, the more the inverter should change cos φ according to a set curve.

How it looks in practice:

When the farm produces little power, the inverter can operate near cos φ = 1.
When the farm enters high production, the inverter starts generating or absorbing reactive power to help keep voltage within the permissible range.
It's like an automatic transmission for voltage: it depends on the load.

Why do this?

Because during high generation, the voltage at the connection point tends to rise.

Reactive power can pull it down or push it up, depending on the direction.

What does 'Q as a function of U' mean?

Q as a function of U means: reactive power should depend on voltage.

This is pure regulation automation.

If voltage rises above a set threshold, the inverter starts acting to lower it.
If voltage drops, the inverter does the opposite to raise it.

It works like a thermostat, only instead of temperature, you have voltage, and instead of a heater, you have Q.

Now, an important detail: This isn't just an on/off state. It can be a smooth curve. For example, the higher the voltage, the more Q the inverter should absorb to reduce it. The lower it is, the more it should supply Q to boost it.

What does 'a specific set Q' mean?

This is the simplest version:

Someone tells the inverter upfront how much reactive power to produce, regardless of P and U.

For example:
We set the inverter to constantly absorb 1 MVAr.
Or constantly supply 0.5 MVAr.
Or maintain Q at a level resulting from the operator's dispatch.

Why do this?
Because sometimes the grid needs a specific amount of voltage support at a given moment, not automation dependent on local measurements.

From the grid's perspective, this is good.

From the perspective of the transformer and cables, it means higher currents for the same active power.

If the installation operates with a significant share of reactive power, the transformer may hit its current limit before reaching its nominal active power rating.

This is a classic source of situations like: theoretically I have reserve, but in practice, the temperature is rising.

What's treacherous for the transformer and cables in all of this

Here's the core of why we're mentioning this.

Reactive power increases the current in the system. Even if the active power P doesn't change.

If you have P (active power) and you add Q, the apparent power S increases, and along with it, the current.

Simply put:
More Q = higher current = greater thermal losses in cables and the transformer.

And that's why sometimes this happens:

On the screen, everything looks fine because the MW are stable.

But the transformer has a higher temperature because the current is larger.

Or the current limit appears earlier, before you reach full active power.

Control via cos φ from P, Q from U, or a set Q are ways the grid operator tells the inverter to support voltage, but this support is carried out by current, so it can increase the load on the transformer and cables even when active power doesn't change.

Additionally, if there's separate compensation in the system, you have to be very careful about who is controlling what. An inverter with its own regulation and a capacitor bank without coordination can enter into unpleasant interactions.

This rarely looks like a major failure.

More often, it looks like instability, fluctuations, protection errors, strange background harmonics.

Overvoltages and resonances: a problem that often reveals itself after commissioning

In PV, you have plenty of elements that create capacitances and inductances.

Long cables on the AC side, filtration, sometimes compensation, plus the transformer and grid parameters. Resonance doesn't have to be constant.

It can appear only in specific operating states, at a specific power, or with a specific grid configuration.

Symptoms can be misleading:

overvoltages, an increase in voltage THD, reactive power fluctuations, random protection trips, sometimes damage to filter components or overheating that doesn't match the load.

The most important design practice is this:

resonance must be treated as a systemic risk, not as bad luck. If there are capacitors, filters, and long lines in the project, frequency analysis of the system ceases to be a luxury.

What tools really solve these problems

When do you need compensating reactors and filters, and when are proper settings enough?

A line compensating reactors on the inverter output limits the steepness of current changes and suppresses some higher harmonics. An LCL filter does this more effectively but is more sensitive to grid parameters and requires proper tuning and damping.

If the problem is mainly current distortion and local harmonic amplification, passive or active filters might be the right solution.

A passive filter is simpler but requires good matching because it can interact with the grid.

An active filter is flexible but more expensive and requires sensible power sizing.

In many projects, the first step should be inverter settings:

THD limits, control strategy, filter parameters, Q regulation modes.

Sometimes the problem isn't that you need new hardware, but that the control is set up in a way that provokes the system.

If you want to understand when a compensating reactor is a real stabilization tool and when it's just a patch for a poorly selected system, check out our article:

Why low-loss transformers don't need compensating reactors?

We break down there where the need for these in compensation systems even comes from,

what low-loss transformers change in the reactive power and current balance,

and how to avoid situations where adding compensation elements starts creating new problems instead of solving them.

It's a text for those who prefer to calculate and select correctly once, rather than tune the installation later in the field ;-D (been there, done that…)

How to select a transformer for non-linear load

A transformer for PV should be selected not only based on apparent power, but also on the expected harmonic level, reactive power share, and cooling conditions.

In practice, what matters is thermal performance and additional losses, because these determine whether the unit will operate stably for years or live on the edge of its insulation.

If you anticipate significant current distortion, you have to account for the fact that harmonic current increases losses.

Some losses simply increase with current, while others increase faster because higher frequencies drive additional losses in windings and structural components.

The classic approach then calls for transformers adapted to non-linear loads, a power margin, and conscious cooling design.

This isn't oversizing for sport. It's a thermal reserve meant to allow the system to breathe in a real operating profile, without constantly pushing temperatures to the limit.

In PV, there's another layer rarely discussed openly until the hunt for the cause of strange currents and events begins.

That's earthing and winding configuration, i.e., the connection group.

The choice of group affects how third-order harmonics and zero-sequence components behave, where they can close their circuit, and whether they get the conditions to do so at all.

If the connection has a delta on one side, some components have a place to circulate locally.

If it doesn't, these same phenomena can flow into the grid or appear as currents in places no one suspected. This isn't a detail. It's the difference between an installation that is quiet and predictable and one that generates additional loads and diagnostic complications.

In the same basket is the tap changer—voltage regulation on the transformer side.

In PV projects, it's tempting to treat it as a one-time setting during commissioning. But it often becomes a tool for matching voltages in a real grid, with real drops and rises, with real reactive power control.

If you have the wrong tap range or the wrong regulation method, you can end up with a system where the inverter overcompensates with Q regulation because the transformer is set too high or too low relative to the connection conditions.

And again, this doesn't have to look like one spectacular failure. More often, it looks like long-term, unnecessary current loading and temperatures that are a few degrees higher than they should be.

That's why selecting a transformer in PV is worth treating as matching the interface between the inverter and the grid, not as buying a device with the right nameplate power.

Preparation for this involves analyzing the operating profile, power quality requirements, reactive power control, and thermal conditions, and then selecting transformer parameters and winding configuration so that the system is predictable.

With emphasis on what's hardest to fix after commissioning: thermal performance, harmonic interactions, and zero-sequence behavior.

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If you have doubts, we're happy to advise, and we also explore this topic in this article:

Which transformer should you choose for a 50, 100 or 150 kW PV system? Here’s what you need to know

5 solutions to the most critical problems in transformer-inverter cooperation

A transformer is a fan of a clean sine wave and predictable work.

An inverter is a waveform editor: it takes DC, assembles AC, regulates P and Q, plays according to grid requirements.

Usually, this works beautifully. Trouble begins when this digital finesse leaves traces in the world of iron: harmonics, high-frequency components, rapid current changes, reactive power operation.

That's why in PV, two things are crucial: grid conditions and control.

Below, we suggest solutions to the five most common problems related to this topic.

1. Harmonics and current distortion, or the bill for 'nice' electronics

Inverters are non-linear by nature. Even if they have a filter at the output and look well-behaved, in practice they can introduce current harmonics, especially at certain operating points and grid configurations.

What this does to the transformer:
Harmonics increase losses in copper and the core, as well as so-called additional losses, which in transformers grow faster than linearly with frequency and distortion.

The end result is boring and brutal: higher temperature. And temperature is the currency of insulation life.

What to do?

The simplest move is to check whether the problem lies in the emission itself or in grid resonance. Because sometimes the inverter is 'OK', and the grid turns its harmonics into a megaphone.

In practice, the following help: well-chosen line chokes, passive filters, active filters in larger installations, and conscious management of the impedance seen by the inverter. For MV PV farms, how the cable distribution and section lengths are designed is also crucial, because cable capacitances can shift resonant frequencies.

2. Reactive power and voltage control, or when the inverter helps a little too much

Modern inverters have volt-var and volt-watt functions, i.e., voltage-dependent regulation. Grid connection requirements in Europe strongly promote the ability to control reactive power and provide voltage support from distributed generation.

What this does to the transformer:
Reactive power itself isn't bad. The problem arises when its flow is unpredictable or too intense relative to the assumptions.

The result can be: currents increase, losses increase, the voltage drop across the transformer impedance rises, sometimes control oscillations appear if several devices 'fight' over the same voltage.

Solutions in three steps:
The first level is inverter settings consistent with requirements and the operator's philosophy.
Manufacturer documentation and guidelines for specific connection rules, such as VDE AR N 4105 in the German context, show how important reactive power control parameters are.

The second level is coordination: if you have compensation, an OLTC in the transformer, inverter regulation, and automation at the HV/MV substation, it's worth asking one basic question: who is the voltage leader here, and who is just supporting.

The third level is measurement and monitoring: without recording the Q profile, cos φ, and voltage over time, it's impossible to distinguish normal operation from automation chasing its own tail.

3. Transformer overheating despite correct rated power

This is a classic: everything 'fits in kW', yet the transformer still struggles more than it should.

Most common causes:
First, harmonics and additional losses, as discussed.
Second, high ambient temperature and cooling conditions, because PV stations often stand in places where summer air is like a warm compress.
Third, dynamic loads: fast power ramps, daily weather cycles, frequent changes in operating point.

Solutions:
A dual-track approach works here: selecting a transformer with the load profile in mind and ensuring power quality. Sometimes this means conscious oversizing, sometimes it means design parameters for distorted loads and choosing a winding connection group that helps close certain harmonics in the delta instead of pushing them into the grid.

If you want to approach this engineering-wise, the path looks like this:

current measurement, spectrum analysis, additional loss calculation, winding and hotspot temperature verification, and only then decisions about filters or setting changes.

4. Overvoltages, steep edges, and voltage surprises in cables

The inverter works in a pulsed manner. Cables have capacitance. The transformer has inductance. The system likes to create oscillations, and oscillations like to appear when no one invited them.

What happens in practice:
With long cable runs between inverters and the transformer, or between the transformer and the connection point, phenomena related to wave reflections and local overvoltages can appear. Add to this classic surges from the grid and switching operations, which in PV can be more frequent because automation works intensively.

Solutions:
Surge protection selected for the actual installation location, sensible earthing, control of cable lengths and their parameters, sometimes damping elements. In larger systems, designers also use solutions that limit the steepness of current changes seen by the transformer—so again we return to chokes and filters, only this time the motivation isn't THD, but insulation protection and spike limitation.

5. The common coupling point and the magic of weak short-circuit power

There's another unassuming hero: the short-circuit power of the grid at the connection point.

The weaker the grid, the more visible the impact of inverters on voltage and distortion.

This isn't an inverter flaw. It's a fact about the system's impedance.

Solutions:
Power quality analyses are performed, taking into account grid impedance and emission allocation, precisely in the spirit of the approach from IEC TR 61000-3-6.

Practically, this means that sometimes it's better to invest in a filtration system and setting coordination than to hope the transformer will SOMEHOW bear it—because a transformer is not a harmonic filter.

Simple ways to improve stability

First, start with a diagnosis: is the problem current-related, voltage-related, or resonance-related?

If current harmonics dominate, target filtration and control parameters.

If voltage sags or fluctuates, look at grid impedance, Q control, and regulation coordination.

If there are random events and overvoltages, suspicion falls on resonances, filter tuning, interactions with compensation, and cable lengths.

Then, get control in order: inverter settings, consistent regulation curves, no conflict between compensation and the inverter, control of power ramps and limits.

Next, selection and verification of the transformer for the real operating profile.

If data shows that currents and additional losses are high, the solution might be a transformer with better thermal performance, a different range of permissible distortion, or simply a properly chosen margin.

Finally, only then add filtration equipment where it makes quantifiable sense: chokes, LCL filters, passive or active filters, sometimes correction of compensation and protection settings.

Answers to the most frequently asked questions - FAQ

Can a photovoltaic inverter accelerate transformer aging?

Yes, if current harmonics, a DC component, or poorly set reactive power enter the grid, the transformer can heat up more than would result from the active power alone.

What is the most common PV problem affecting transformers?

Power quality surprises: harmonics, voltage fluctuations, and reactive power operation controlled by inverters.

Does a filter or choke really make a difference?

Yes, because it limits distorted currents and steep current edges, which increase losses and temperature in the windings.

What's more important: transformer power or its resistance to distortion?

In practice, both. A kVA reserve helps, but design for non-linear loads and grid conditions also matters.

What standards help set harmonic limits and connection requirements?

In Europe, the reference point is often grid connection requirements based on EN 50549, as well as compatibility and harmonic emission assessment rules from IEC 61000-3-6.

The interface between a PV inverter and a transformer is a bit like a big city intersection

On paper, the rules are simple, but in reality, what counts is traffic intensity, road surface quality, and whether the signaling is set up for the actual rush hours.

In photovoltaics, these rush hours repeat daily, and power quality, grid stiffness, and protection settings can turn an ordinary installation into a system requiring smart coordination.

The good news is that most tricky topics can be handled without stress if you approach them systemically.

First, understanding what's really happening in the currents and voltages.

Then, measurement and PQ monitoring to speak the language of data, not impressions.

Finally, design decisions that make a difference.

Sensible filtration, reasonable reactive power control, adaptation to grid conditions, and a transformer selected for the real operating profile, not just the nameplate.

If you are at the stage of selecting a transformer for PV or want to stabilize the operation of an existing installation, we invite you to explore our offer.

For low-loss oil transformers MarkoEco2, compliant with EcoDesign 2 ——> click here,

for TeoEco2, cast resin transformers Tier 2 ——> click here

In both cases, we're happy to help select a solution for your grid conditions, connection requirements, and inverter operating mode.

We also develop these topics on LinkedIn, more behind the scenes and more operationally. If you like specifics, follow us on LinkedIn and join the conversation.

Thanks for this shared journey through a topic that at first glance looks like a detail, but in practice determines the stability of an entire farm.

We are people for people, and we work best in partnership when both sides bring curiosity, precision, and a desire to do things properly.

REFERENCES:

IEC TR 61000-3-6. Electromagnetic compatibility (EMC) - Part 3-6: Limits - Assessment of emission limits for the connection of distorting installations to MV, HV and EHV power systems

Technical Requirements of Photovoltaic Inverters for Low Voltage Distribution Networks, K. Chmielowiec, Ł. Topolski, M. Dutka, A. Piszczek, Z. Hanzelka, T. Rodziewicz via MDPI

IEEE Standard for Harmonic Control in Electric Power Systems