Copper and aluminium in transformer windings have different properties, but the quality of the device is determined by the entire design. Check 4 facts about losses, durability, dimensions and operation.

On the table lie two offers.

In one, someone declares: copper, so premium.

In the other: aluminium, so economical.

Both sound confident.

Both try to win your attention with a single word.

And this is where the problem begins.

Because in transformers, a single word very rarely tells the truth about the whole device.

We are writing about this because these doubts often return in conversations with investors, designers and contractors. Each time we see the same mechanism:

The winding material is often sold as an ideology, although in practice what counts is the whole transformer design: its losses, cooling, short‑circuit strength, termination method and manufacturing quality.

The applicable efficiency requirements in the EU and the USA do not force a choice by definition of copper or aluminium. They demand a technical result. That is a fundamental difference.

The question "copper or aluminium" is often poorly framed.

A better question is: which transformer design gives me real technical, operational and economic benefit for my application?

This text is for people who do not want to buy a slogan.

After reading, you will be able to distinguish material properties from manufacturer marketing, understand when copper really makes sense, when aluminium is a sensible choice, and what questions to ask so that silence falls on the other side of the table, followed by the most valuable sentence: yes, that is exactly the point.

Concrete content awaits you inside.

First, we will dismantle the most common myths.

Then we will go through the physics of materials, the impact on efficiency and dimensions, behaviour during short circuits, connection and service issues, and how to read an offer.

Finally, we will give you a practical decision filter.

Reading time: ~ 8 minutes

What really determines the quality of transformer windings?

Do not jump too quickly.

First, name the game.

In the dispute over windings, the game usually looks like this: copper is presented as the choice of sensible, durable and professional people, while aluminium is presented as a cheaper substitute.

Or the opposite: aluminium is shown as modern, light and good enough, while copper is shown as a costly relic.

Both narratives are convenient for sales because they simplify reality to a single symbol.

Technology does not work that way.

Manufacturers and standards evaluate a transformer by the result of the whole design.

What counts are no‑load and load losses, temperature rise, insulation, impedance, mechanical strength, heat dissipation method, behaviour under overloads, and connection quality.

European ecodesign regulations for transformers focus on minimum efficiency levels.

Similarly in the United States, the DOE (Department of Energy) tightens energy efficiency requirements for transformers but does not impose one single correct winding material.

This is an important moment. Because when a salesperson starts with the material rather than with loss parameters, temperature, insulation class and operating conditions, it is very possible they are trying to close the conversation before you ask uncomfortable questions. In negotiations, this is a classic shortcut. In transformers as well.

Truth number one: copper conducts better, but that does not end the matter

There is no point pretending the differences do not exist.

Copper has very high conductivity and serves as the reference point for the IACS scale – the international standard of conductivity.

For annealed copper, the standard is 100% IACS.

At the same time, its density is high, about 8.89 g/cm³ according to the definition used for the IACS standard.

Aluminium conducts less well on a volumetric basis, but has a much lower density.

The Aluminium Association also points out something that copper marketing does not like to repeat: aluminium gives about twice the conductivity per unit mass compared to copper.

That is why for decades it has been the preferred material in many transmission and distribution applications.

And this is where the simple story ends and real design begins.

If aluminium has higher resistivity, the designer compensates with a larger conductor cross‑section.

In other words, you do not compare a naked piece of metal to a naked piece of metal, but two complete winding designs.

Therefore, the sentence "copper has lower losses" is too crude to decide anything sensibly.

Copper may have lower losses at the same cross‑section, but a transformer is not a competition for the same cross‑section.

It is a competition for the result of the whole construction.

Eaton explicitly emphasises that the common belief that a transformer with copper windings is by definition more efficient, more reliable or stronger under short‑circuit conditions is a simplification and a false assumption.

It is a bit like comparing two cars only by the material of their pistons, without asking about the engine, cooling, gearbox and aerodynamics.

Sounds impressive. Says little.

Truth number two: efficiency does not sit in the name of the metal, but in the design

In recent years, efficiency requirements have become tougher.

The EU has Regulation 2019/1783 amending the earlier ecodesign requirements for transformers, and the European Commission explicitly indicates that these regulations have pushed the market towards models with higher efficiency and lower life‑cycle costs.

In the USA, the DOE adopted new standards for distribution transformers, published in 2024, with compliance mandatory from April 23, 2029.

What does this mean in practice?

That the market is increasingly less tolerant of transformers based on slogans alone. The manufacturer must deliver the parameters.

If an aluminium design meets the loss and temperature requirements, it meets them really, not pretend. If a copper design does not close them or does so at the cost of unjustified price increases, the mere presence of copper does not save the offer.

And here we come to the point where the marketing narrative often breaks.

Copper is not an automatic guarantee of better overall transformer efficiency.

Aluminium is not an automatic guarantee of worse efficiency.

Efficiency is the result of the electromagnetic and thermal design, core selection, winding geometry, cooling method and loss control.

When someone tries to close the conversation with a single word, it is worth calmly replying:

"I understand – are you saying that the material itself is more important than the declared load losses, no‑load losses and temperature rise?"

Very often after such a question the conversation suddenly becomes more substantive.

Truth number three: copper more often wins where compactness and mechanical margin matter

Not to fall into the opposite extreme, one must honestly say: copper has real advantages.

Thanks to its higher volumetric conductivity, it allows the required resistance to be achieved with a smaller cross‑section than aluminium. In many designs, this translates into more compact windings and easier fitting of the design into a limited space.

Copper also has high mechanical strength and good thermal conductivity, which in practice is an advantage in constructions where compactness, high power density, high mechanical rigidity or specific short‑circuit conditions matter.

Industry sources highlight these features, and even a report comparing busbar systems indicates that the obvious advantages of aluminium are lower initial cost and weight, while copper offers more compact solutions and greater mechanical robustness.

This does not mean that every copper design beats every aluminium design.

It only means that under certain design conditions, copper gives the designer greater comfort. If the transformer has to fit into a tight enclosure, operate in more difficult thermal conditions, or the investor prioritises minimising dimensions, copper often becomes a strong candidate.

Here the truth is inconvenient for both sides of the marketing dispute.

The copper advocate cannot say: always better.

The aluminium advocate cannot say: there is never any difference.

A difference can exist. You just have to know how to locate it.

Truth number four: aluminium is not a poorer cousin; it is a material that requires honest design

The most damaging myth is: aluminium is just cost cutting.

No.

Aluminium is a full‑fledged engineering material, widely used in power engineering.

If aluminium is given the right cross‑section, well‑designed connections, proper winding geometry and is backed by a sensible manufacturing regime, it can create a transformer with very good performance.

And here it is worth pausing for a moment.

The problem is not aluminium itself.

The problem can be a poor design based on aluminium, or the way such a design is later sold. Because if someone wants to buy aluminium at the price of aluminium, yet expects the compactness of copper, its design margins and the psychological comfort of the word "premium", they stop talking to physics and start talking to their own imagination.

And physics remains calm. It is not interested in labels. It is interested in cross‑sections, losses, operating temperature, impedance, termination method and test results.

That is where marketing ends and the truth about transformer quality begins.

When does aluminium in a transformer make sense?

This is where the conversation becomes really practical.

Because even the best material can be spoiled by a poor connection.

For years, aluminium has had a reputation as a tricky material at terminals.

Part of this reputation grows from the history of old, poorly executed applications, but part comes from the real need for proper approach to connections and terminations.

ANSI C119 standards cover tests for aluminium‑aluminium, aluminium‑copper and copper‑copper connectors. NEMA also reminds that for conductors of different metals, appropriate certified connectors and proper installation procedures should be used, and the quality of terminations should comply with the requirements of the hardware and equipment manufacturer.

In other words, the problem is not "aluminium is bad".

The problem is: is the entire connection system designed and executed as it should be?

This is precisely the point where the buyer should stop hunting for a quick "yes" and start looking for a real "no".

Instead of asking "do you have copper?",

it is better to ask: how have you solved the material transitions, what connectors do you use, what are the tightening torque procedures, how do you validate connections, and what operational experience do you have? Then the other party will either engage in the technical details or stay with the slogan.

And you will know who you are talking to.

The infographic organises the key issues that return when asking: copper or aluminium in transformer windings? It shows the differences in conductivity, cross‑section, weight, losses and design requirements, making it easier to understand what really determines efficiency, durability and the selection of a transformer for a specific application. This is a synthetic summary for those looking for a practical answer to questions about copper and aluminium windings, no‑load and load losses, operational safety and total life‑cycle cost.

Copper or aluminium in a transformer – which is better?

The truth does not lie on one side of the barricade.

Copper indeed has higher volumetric conductivity, usually allows more compact designs to be built, and often gives greater comfort where dimensions, mechanical margin or demanding operating conditions matter.

Aluminium, on the other hand, has for years been a full‑fledged material used in power engineering. With properly designed windings, appropriate connections and a well‑calculated overall design, it does not have to mean either lower efficiency or lower reliability.

Marketing begins when someone tries to turn this technical difference into a worldview war. In one version we hear that only copper is professional. In another, that aluminium is always just as good and there is no point in paying extra. Both narratives are convenient.

Both look good in a catalogue. And both simplify the topic to a level that ceases to be useful for the investor.

A mature decision looks different.

If compact dimensions, a specific mechanical margin, a specific winding architecture or limited installation space are key, copper may be the right choice.

If the priority is a well‑calculated total cost, reasonable weight, adequate efficiency and a proven design with correctly solved connections, aluminium may be a fully rational choice. The problem, therefore, is not which material sounds better.

The problem is whether someone evaluates the transformer through parameters and design, or only through a label.

What is more important in a transformer than copper or aluminium itself?

The best questions usually do not sound spectacular.

They sound calm and precise.

Therefore, instead of starting the conversation with the winding material alone, it is better to ask about the declared no‑load and load losses, insulation class, temperature rise, short‑circuit impedance, dimensions, weight, termination method, connection type and warranty conditions.

It is also worth asking which standards and tests confirm the given solution, and what exactly copper or aluminium gives in this specific unit, not in a general sales presentation.

It is here that the difference between technique and storytelling very quickly becomes apparent. If the other side provides numbers, relationships, documentation and specific answers, the conversation stands on solid ground. If instead prestige, emotion and a mental shortcut appear, you are most likely entering not a world of parameters but a world of marketing.

And perhaps this is where the most honest answer to the whole question of copper and aluminium lies. The truth does not reside in the metal itself. It resides in the design, documentation, manufacturing quality and honesty of the conversation. Copper and aluminium are not heroes of a moral tale. They are tools. Both materials can work very well. Both can also be used badly.

The most expensive mistake appears when someone stops thinking and buys a narrative instead of parameters.

What you can expect from us

In transformers, as in life, the most confusion is usually caused by answers that are too simple.

At Energeks, we look at the subject of windings more broadly than just through the lens of the slogan "copper" or "aluminium". What matters much more to us is whether the whole transformer has been designed responsibly, coherently and with long‑term stable operation in mind.

Therefore, for MarkoEco2 oil‑immersed transformers, what counts for us is the whole: hermetic construction, oil compliant with IEC 60296, compliance with EN 50588‑1 and EN 60076‑1, monitoring capabilities and solutions supporting long life and loss reduction.

It is from such decisions that a device is created that is supposed to work calmly, stably and without surprises.

We look similarly at TeoEco2 dry‑type transformers. Here, quality is determined by disciplined engineering: compliance with EcoDesign Tier 2, reduction of no‑load and load losses, F1 fire safety, and readiness for real operating conditions and cooperation with protection systems. This is equipment that is supposed not only to look good in an offer but above all to find its place where certainty matters.

We offer both transformer types in variants with aluminium and copper windings.

Sometimes the best answer is copper, sometimes aluminium, and sometimes simply a well‑chosen design. And that, actually, is quite good news.

In power engineering, the most expensive thing is not the material itself.

The most expensive thing is oversimplification.

That is why it is worth negotiating with an offer the same way you negotiate good cooperation terms.

With an attitude towards real mutual benefit.

You get a transformer that does its job for years.

The manufacturer gains a customer who understands what they are paying for.

And only then does the conversation truly make sense.

Sources:

1. European Commission, Power Transformers, Ecodesign Requirements

2. U.S. Department of Energy, Distribution Transformers, 2024 final rule and compliance timeline

3. Eaton, Copper vs. Aluminum Conductor Information for Distribution Transformers

The power industry loves paradoxes.

The largest devices in the power system very often depend on the smallest details. A transformer can weigh several tons, have a power rating of several megavolt-amperes, and operate continuously for 30 years. Yet the part that often decides its reliability is only a few centimetres in size.

It is the transformer terminal.

More precisely, the component that connects the medium voltage cable to the transformer bushing.

To someone outside the industry, it looks like an ordinary piece of metal with a few bolts. A detail that few people pay attention to, as long as everything works.

For a power engineer, it is a completely different story. It is one of the most critical points in the entire installation. Right here, high currents meet, mechanical forces from heavy cables act, temperature changes occur, and the very practical question arises: will this connection safely withstand years of operation in real conditions?

Transformer terminals are connection components mounted on the bushings of a medium voltage transformer. They enable safe connection of MV cables, increase the contact surface area of the conductors, and improve the mechanical stability of the connection.

This brings very concrete benefits.

• Lower contact resistance.

• Lower risk of connection overheating.

• Greater predictability of transformer operation over a long service life.

That is why TOGA-type transformer clamps are often used in medium voltage transformers. They are not an aesthetic detail or a marketing add-on. They are a solution born from a very practical need. The need to better manage current, temperature, and connection mechanics in a place that looks unremarkable but in practice is of enormous importance.

And this article is about those issues.

We will show what TOGA-type transformer clamps are and how they are built.

We will look at why conventional cable connections at transformer bushings can be problematic.

We will explain how the clamp construction affects current, temperature, and contact resistance.

We will also examine why grid operators increasingly require stable connection solutions.

We will show, through examples, in which installations transformer clamps become fundamental to the reliability of the entire station.

Reading time: ~11 minutes

TOGA-type transformer clamps – the small component that keeps hundreds of amperes in check

Anyone who has ever stood next an open medium voltage transformer knows that moment.

You look at the massive machine. Several tonnes of steel, a magnetic core, oil, windings. Everything looks calm, heavy, almost majestic.

Then your eyes stop on something the size of a hand.

The clamp.

And this is where real engineering begins.

Because this is not an ordinary piece of metal.

It is a component that must flawlessly carry hundreds of amperes, withstand temperature changes, vibrations, and mechanical forces from cables, while maintaining very low contact resistance for years.

A TOGA-type transformer clamp acts as an adapter between two worlds.

On one side we have the transformer and its bushing – the point where energy exits the tank.

On the other side we have the medium voltage cable, often thick, heavy, and not very flexible.

The clamp introduces an additional conducting element between them, most often made of copper or its alloys. This element increases the contact surface, stabilises the conductor, and distributes mechanical forces over a larger area.

From the point of view of physics, three important things happen:

• The current has a larger surface area through which to flow.

• The metal-to-metal contact pressure is more even.

• The connection is less susceptible to movement and stress.

The effect is simple: less heat, fewer problems, more operational peace.

The photo shows a set of medium voltage transformer clamps mounted on the porcelain bushings of an oil‑immersed transformer. Each clamp serves as the connection point for the MV cables, enabling safe and stable connection of the conductors to the transformer winding. The massive construction of the metal connection blocks increases the contact surface area and allows even current flow, which limits local heating and reduces the risk of energy losses. At the same time, the clamps take up the mechanical loads from the heavy cables, protecting the bushings from stress.

It is in this unremarkable place that all the physics of the transformer’s operation comes together – current, temperature and connection durability – which must remain stable for decades of service.

Photo CC: ENERGEKS 2026

Why conventional cable connections at transformer bushings can be problematic

Cable lug, bolt, tighten – done.

On paper, it works perfectly.

In reality, three very concrete problems appear.

The first is the weight and stiffness of the cable.

Medium voltage cables with large cross-sections are not delicate. They are heavy, springy constructions that very often do not want to go exactly where the design intended. If the cable comes in at an angle or is under tension, it starts acting like a lever and loads the bushing terminal.

The second problem is the contact surface area.

Metal does not make ideal contact with metal. Current flows through microscopic contact points. If there are few such points, current density increases, and along with it, temperature.

And suddenly, a small resistance starts turning into a local heat source.

The third problem is time.

A transformer does not operate in a perfect vacuum. There are vibrations, temperature changes, material expansion and contraction, short-term overloads. If the connection relies on only a single pressure point, micro‑movements can occur over time.

And micro‑movements in power engineering have a bad reputation.

Because they always end with degraded contact.

And this is precisely where the need for better solutions begins.

But even then, the story is not over.

Because once we have improved the mechanics and the electrical connection, another level of challenges appears. One that does not arise solely from current, bolts and cable geometry, but from the fact that the transformer works in the real world, not in a sterile laboratory. In an open station, in an environment full of moisture, dust, temperature variations and all that unwanted biological activity that power engineering knows all too well.

MV bushing covers – what they are and what they really protect against

At first glance, they look a bit like little black hoods.

And that is why they are easy to dismiss. Someone looks at the transformer, sees the bushings, clamps, porcelain, metal, and treats these covers as an extra. A technical trifle that just happens to be there.

Yet in power engineering, such trifles very often do the dirty work that allows everything else to operate calmly.

MV bushing covers are installed to protect the most sensitive area of the transformer connection point. This is where we have live parts, metal components, and relatively small insulation clearances. Exactly the kind of combination we do not want to expose to chance, weather and the creativity of nature.

Most often they are referred to as bird guards. And this is no exaggeration or industry legend. Birds really can cause trouble in a transformer station. All it takes is for one to perch in an unfortunate spot, brush a wing, come close to two points at different potentials, and physics immediately takes over. An arc appears, protection trips, and suddenly we have an outage that nobody planned.

It sounds unremarkable, but this is exactly what some of the most irritating operational problems look like. Not a major failure from a movie. Just a small incident that stops the equipment.

And this is where bushing covers come in.

All black, without any unnecessary fanfare. 😎

Their role is very simple. They make accidental contact with live parts more difficult and reduce the risk that something or someone creates a bridge between potentials.

A bird, a small animal, a branch, a metal object, and sometimes even a tool during service work – all of this can become a problem if it gets too close to where theory ends and medium voltage begins.

A cover does not, of course, make the transformer armoured and indifferent to the whole world. But it very effectively reduces the risk of the simplest, most absurd and, unfortunately, entirely real events. The kind after which one looks at the report and thinks: really? because of that?

Well, yes.

That is why MV bushing covers are no gimmick. They are a practical safeguard that supports the reliability of the transformer from its most mundane side. They do not improve the catalogue glamour of the device. They improve its chances of calm, long-term operation in the real world.

And the real world, as we know, does not always cooperate.

The photo shows medium voltage bushing covers installed on an oil‑immersed transformer. These unassuming black covers protect the critical connection points against accidental contact with live parts and reduce the risk of flashovers caused by birds, small animals and other external factors. They are a simple but very important protective element that supports the safety and operational reliability of the transformer in daily service.

Photo CC: ENERGEKS 2026

From a project perspective, the most sensible approach is when the entire connection system can be selected as a coherent solution, rather than assembled later from random components. Depending on the needs of the investment, these can be transformers equipped with terminal clamps, clamps for a specific type of connection, or MV bushing covers that increase operational safety. Such solutions are available in the Energeks offer; therefore, for a specific project, it is best to simply discuss the configuration and match it to the real operating conditions of the station – and the easiest way to do this is to contact us directly.

How the clamp construction affects current, temperature and contact resistance

Here begins that part of power engineering that looks unremarkable from the outside but is pure physics on the inside.

And as is the case with physics, you can disagree with it, but it will do its job anyway.

At first glance, a transformer clamp is simply a metal component that connects the cable to the transformer. Except that current does not behave as politely as we would like to imagine. It does not flow ideally through the entire contact surface like a beautifully spread sheet of water.

In reality, it flows through those places where metal truly touches metal. And there are far fewer of those contact points than intuition suggests.

That is exactly why the construction of the clamp matters so much.

If the contact surface is larger and the pressure is more evenly distributed, more actual contact points appear. This in turn lowers contact resistance. And lower contact resistance means one thing: less heat where we least want to see it.

Because resistance and temperature are a pair that very quickly show their claws. Joule’s law clearly states: the power dissipated in the connection increases with the square of the current. This means that even a small resistance, under a high operating current, can turn into a local source of heating. First, a few extra degrees appear. Then the material starts to operate hotter, ages faster, and the connection gradually loses its original parameters.

A transformer clamp does three very important things at once.

First, it increases the contact surface area, so the current has more space to flow calmly.

Second, it distributes the contact pressure better, so the connection does not rely on only one small fragment of metal.

Third, it stabilises the whole assembly over time, reducing the risk of micro‑movements that, over the years, can degrade the quality of the contact.

The effect is simple, though extremely valuable from an operational point of view. The current does not concentrate in one tight spot but spreads over a larger area. The temperature of the connection remains lower. And a lower temperature means calmer, more predictable transformer operation.

It can be compared to traffic. The same number of cars squeezed onto a single narrow street quickly creates chaos. When they are given a wide road, everything flows much more calmly. Current behaves similarly. It also likes to have space.

That is why a well‑designed clamp is not a technical detail for the sake of principle. It is a component that helps keep three things in check at once: current, temperature and connection durability. And for a transformer operating for decades, that is truly no small matter.

Why grid operators increasingly require stable connection solutions

Grid operators have one big advantage over the rest of the market.

They do not see a single transformer; they see a whole repeated picture of operation.

For the designer, a transformer is a device selected to meet technical parameters. For the investor, it is an element of a larger puzzle. For the grid operator, it is part of a system that must operate calmly not for one or two years, but for 30, sometimes 40 years.

And it is this perspective that changes everything.

Because when you look at thousands of devices operating in different locations, under different weather conditions and different loads, you very quickly see which solutions age well and which only look good on the day of acceptance.

Every failure, every thermal imaging report, every overheated connection and every case of degraded contact goes into the analysis. At first, it is a single event. Then a second. A third. A tenth. And suddenly it becomes clear that this is no longer a coincidence, but a recurring pattern.

And power engineering does not like recurring problems.

That is why operators are increasingly looking not only at the transformer’s power, loss levels or insulation parameters, but also at how the cable connections are designed. Whether the connection is mechanically stable. Whether the contact surface is sufficient. Whether the arrangement can withstand the stresses from heavy cables, vibrations, temperature changes and years of operation.

Because practice shows something very interesting.

In many cases, the transformer itself, as a machine, works flawlessly. The windings are in good condition, the oil maintains its parameters, the core operates stably. The problem does not begin in the heart of the device.

The problem begins at its interface with the outside world.

Exactly where the cable connects to the transformer.

And that is the moment when a detail ceases to be a detail.

It becomes an element of the entire station’s reliability.

It is from this logic that the operators’ technical requirements arise. The more operational experience, the more attention is directed to the construction of bushings, the method of making cable connections, the stability of clamps and the resistance of the whole connection system to real operating conditions.

Because ultimately, the operator does not buy just the transformer.

The operator buys operational peace.

The photo shows a set of medium voltage transformer connection components: a transformer clamp, a porcelain bushing and a bushing cover that protects the critical point from environmental influences. It is here that current, mechanics and operating conditions meet, which is why each of these components must be consciously selected and work as a coherent system. In practice, this means one thing: reliability begins with a detail, and a well‑designed connection is not an accident but the result of properly selecting all the components that together create a safe and durable connection.

Photo CC: ENERGEKS 2026

Where transformer clamps show whether the project was truly well thought out

There are installations where the transformer has a rather comfortable life. It runs steadily, the cable arrives without too much acrobatics, the load does not do a rollercoaster every day, and everything looks as neat as in the nice drawing from the project.

But there are also places where reality quickly verifies whether the connection at the transformer was designed with intelligence or simply so that it could be bolted together and the matter closed.

And there, transformer clamps cease to be a technical curiosity.

They become a very practical test of the quality of the whole solution.

Take photovoltaic farms.

Everything seems simple.

There is energy production, there is a transformer, there is a power output to the grid. End of story. Except that the transformer in a PV farm operates under conditions that like to test the patience of materials. In the morning the system wakes up, then power rises, then full sun comes, a cloud passes, sun again, ambient temperature does its thing, and along with it the operating conditions of the connections change. This is not the calm, uniform life of an old distribution transformer that does roughly the same thing for half a day. Here current and temperature can change dynamically, and each such cycle means work for the material, the contact pressure and the contact interface.

Add to this the cables. Thick, heavy, serious, with character. Cables that have no intention of lying down gently just because someone drew a nice route on the plan. If the connection at the bushing is weak or too sensitive to stress, the PV farm will show it quickly. And it will do so without sentiment.

Very similar is the case in industrial installations.

Here the emotional stakes rise even higher, because on the other side of the cable there is often a process that really does not like downtime.

Steelworks, foundries, chemical plants, large logistics centres, data centres, plants with production lines operating in continuous mode. In such places, the transformer does not supply an abstract power from a table. It supplies concrete work, concrete machines, concrete money that either flows or stops flowing. If the connection at the transformer starts to heat up, age or lose stability, it is no longer a minor technical defect. It is the beginning of a problem that can affect the entire facility.

That is why, in industry, no sensible person wants the critical point of the system to behave like a moody paving stone after the first winter. The connection has to be stable, predictable and boring in the best possible sense. It simply has to work.

There are also container stations.

The place where theory very quickly meets tight reality.

Here every centimetre matters. Cables enter from below, the switchgear stands close, the transformer has its dimensions, and the person responsible for installation suddenly discovers that the planned geometry was beautiful until the real cable appeared. Not the one from the brochure, but the real one – stiff, heavy and moderately interested in cooperating.

Under such conditions, even a good connection can get out of breath if it does not have adequate stabilisation. The cable rarely comes in perfectly straight, the manoeuvring space is limited, and every unnecessary stress‑inducing twist later affects the terminal and the quality of the contact. This is where a well‑designed clamp shows its true value. Not in a folder, but when you have to manage physics, space and cable weight all at once.

There are also installations that are more environmentally demanding.

For example facilities with large temperature variations, outdoor infrastructure, or locations where the transformer has to operate in an environment of dust, moisture and constant changes of conditions. There, every detail of the connection matters even more, because the connection does not work in a comfortable laboratory but in a world that regularly checks whether everything was done properly.

That is precisely why solutions that increase the contact surface and mechanical stability are not a luxury for hardware aesthetes. They are simply a sensible response to operating conditions.

Because the truth is rather amusing, though for operation it is less amusing.

The transformer can be excellent.

The core solid, the windings well‑made, the oil within spec, everything looks as it should.

And then all that majesty of several tonnes of equipment can be put to the test by a few centimetres of metal at the connection point.

A related topic worth knowing:

Why an MV transformer bushing terminal has one or two holes?

f you want to better understand why even such a small detail as the cable attachment method matters, take a look at our article about the construction of MV bushing terminals. We show there where the difference between one and two mounting holes comes from and how it affects the stability of the connection and its durability over time.

Where to get such a transformer, clamps and those hoods?

And here we come to a very practical question.

Because theory is theory, physics is physics, and temperature curves look beautiful in an article, but in the end someone has to close the topic.

You need to select the transformer.

You need to select the clamps.

You need to plan the bushing covers. You need to make sure that everything fits together not only in the catalogue but also later on the real station, with the real cable, real installation and real operator requirements.

And this is where the difference begins between assembling a system from random components and designing a solution that makes sense as a whole.

You can look at the transformer as a separate product, the clamps as separate hardware, and the covers as yet another add‑on to order. But in power engineering practice, these things do not work separately. They meet at the same place, on the same connection, under the same current, temperature and the same pressure of reality.

That is why the most sensible approach is to think about them together.

In the Energeks offer you can find both low‑loss medium voltage oil‑immersed transformers and cast‑resin dry‑type transformers. You can contact us about selecting transformer clamps and medium voltage bushing covers.

In this way, the entire system can be selected coherently, for a specific project, for the cable routing method, for the installation conditions and for the requirements of a given installation. Without guessing, without improvisation at the end of the investment and without nervously wondering whether all the components will really work together as they should.

And that really matters in power engineering.

Because sometimes the reliability of a transformer is not only decided by what is inside the tank.

What happens on the outside can be just as important. On the bushings, on the clamps, at the interface between the cable and the device. In all those places that do not make a great impression in a long‑distance photo, but which can make a great difference after several years of operation.

If you like technical stories from the power industry told without pomposity but with respect for detail, we also invite you to our LinkedIn.

Referencje:

IEEE Power Transformer Handbook

Pfisterer – Technical documentation (MV connection technology)

Sometimes the most interesting things in the power industry are surprisingly small.

You're standing by a medium voltage transformer, looking at a porcelain bushing, and you see a metal terminal.

On one phase, one hole.

On another, two. Someone asks: is this a mistake? Is something missing?

No. It's a conscious design decision.

In the world of MV transformers, such small details aren't just cosmetic.

They are elements that affect the installation's durability for the next 30 years of operation.

In the place where the cable meets the transformer, enormous currents, electromagnetic forces, and temperature also meet.

And right there, one additional hole can make a huge difference.

Today, we'll take a look at one of the most underestimated elements of an MV transformer.

The bushing terminal and why it sometimes has one hole and sometimes two.

If you design transformer stations, work with MV transformer installation, set up PV farms, or simply want to understand the power industry more deeply, this article will show you something important.

You'll understand why the construction of the bushing terminal isn't an accident.

You'll learn how the number of holes affects currents, temperature, and connection durability.

And why, in power engineering practice, one extra hole can save a transformer from overheating.

In this text, we'll discuss:

• how an MV transformer bushing works and is constructed

• why terminals have one or two mounting holes

• how the number of bolts affects current, temperature, and contact resistance

• what distribution grid operators require

• which installation errors most often lead to connection overheating

It's worth reading, because the only thing truly worth accumulating in life is knowledge!

Reading time: ~12 minutes

How an MV transformer bushing works and is constructed

Before we move on to the mounting holes themselves, it's worth understanding the role of the bushing.

A medium voltage transformer typically operates in the range from about 6 kV to 36 kV. The windings are inside a tank filled with transformer oil. This oil serves two functions. It cools the windings and provides electrical insulation.

The problem appears where the conductor has to exit the tank.

The current must pass from inside the transformer to the outside, to the cable or busbar. At the same time, electrical breakdown through the housing cannot be allowed. The potential difference is enormous.

That's why bushings are used.

A transformer bushing is an insulated element, usually made of porcelain or composite, that conducts the conductor through the transformer tank wall. Inside it, there is a conductive pin connected to the transformer winding.

On the outside of the bushing, there is a terminal.

The metal fitting to which the cable or busbar is connected.

And it's in this fitting that the topic of one or two holes appears.

The bushing terminal, a small element with great responsibility

The bushing terminal is the meeting point of two worlds.

On one side, we have the transformer. A device that can have a power rating from several hundred kilovolt-amperes to several megavolt-amperes.

On the other side, the medium voltage cable or busbar leading the energy further into the grid.

At this single point, currents in the order of hundreds of amperes, and sometimes over a thousand amperes, flow. At the same time, the metallic contacts must maintain very low resistance.

If the contact resistance increases even minimally, the Joule effect appears.

Electrical energy starts turning into heat.

And heat in the power industry is enemy number one.

Why an MV transformer bushing terminal has one mounting hole

The simplest and at the same time very common construction of a medium voltage transformer bushing terminal has one mounting hole.

At first glance, this may seem like a minimalist solution, but in reality, it is a conscious compromise between electrical requirements, mechanical needs, and installation practice.

In such an arrangement, the cable lug is bolted to the terminal with one bolt.

The bolt presses the lug eye against the flat metal surface of the bushing terminal. This creates an electrical connection through which energy from the transformer can flow further to the medium voltage cable.

For many installations, this solution is fully sufficient and has been used in distribution power engineering for decades.

To understand why, it's worth looking at the scale of currents on the medium voltage side.

In distribution transformers with a power of several hundred kilovolt-amperes, the currents on the MV side are relatively small. This follows directly from the relationship between power, voltage, and current.

For example, a 1000 kVA transformer operating in a 15 kV network generates a current of about 38 amperes on the medium voltage side. Even with a 2500 kVA transformer, this value increases to about 96 amperes.

These are values that, from the perspective of electrical connection construction, are relatively small.

A properly made bolted connection with one bolt and an adequate contact surface carries such currents without any problem for many years of operation.

That's precisely why, in transformers with lower power ratings, using a terminal with one mounting hole is a completely rational solution.

One bolt ensures adequate pressure on the contact surfaces.

If the surfaces are clean and the bolt tightening torque is correct, the contact resistance remains very low. This means that no significant energy losses or excessive heating appear at the connection point.

The connection is also simple to install. The installer needs to fit one cable lug and tighten one bolt with the appropriate torque. In the conditions of constructing or modernizing a transformer station, this has practical significance because it shortens installation time and reduces the risk of errors.

A terminal with one hole also has construction advantages.

First of all, it is more compact. In container stations, where space between transformers, switchgear, and cables can be very limited, every centimeter of space matters. A smaller terminal makes it easier to route cables and maintain the required insulation clearances.

The second advantage is the lower weight of the entire bushing assembly.

In distribution transformers, which are often installed in large quantities in the grid, every structural element is optimized for cost and simplicity of production. A simpler terminal means less material and fewer technological operations during manufacturing.

There is also the aspect of compatibility with typical cable lugs used in medium voltage networks. In many cable systems, standard lug eyes are designed specifically for single-bolt connections.

Thanks to this, installation is quick and requires no special intermediate elements.

In power engineering practice, a terminal with one hole is therefore a good solution in several typical situations.

The first is a transformer with relatively low power, where the currents on the medium voltage side are not large. Under such conditions, a single bolted connection provides sufficient contact surface and mechanical stability.

The second situation is cable installations where the transformer is connected directly to an MV cable terminated with a standard cable lug. The cable is flexible and does not generate large mechanical loads on the terminal, so one attachment point is sufficient.

The third situation is transformer stations with limited installation space. A compact terminal makes it easier to route cables and maintain safe distances between phases.

However, physics and operational practice remind us that every solution has its limits.

One bolt means one pressure point.

It also means that the entire contact surface is pressed in one place. If the connection is made imprecisely, the contact surface may be smaller than assumed.

As transformer power increases, currents increase, and with them, the requirements for the quality of the electrical connection increase.

MV transformer bushing terminal with one mounting hole used in standard cable connections in MV transformer stations. The single-bolt construction enables quick and compact connection of the cable lug to the transformer bushing, ensuring adequate contact surface for typical operating currents in distribution transformers. This solution is often used in transformers with lower and medium power ratings, in cable installations, and in container stations where simplicity of assembly and limited connection space are important.

© ENERGEKS 2026

At a certain point, one bolt ceases to be the optimal solution.

That's when the construction with two mounting holes appears, which allows for increased mechanical stability and improved pressure distribution on the contact surface.

And it is this solution we will look at in the next step.

Why an MV transformer bushing has two mounting holes and when it is necessary

A terminal with two holes is a construction used where the electrical and mechanical requirements of the entire system increase. In transformers with higher power ratings and in industrial installations, a simple single-bolt connection ceases to be the optimal solution.

In such an arrangement, the cable lug or copper busbar is bolted to the bushing terminal with two bolts. At first glance, the difference seems small. In reality, it changes a great deal in the behavior of the entire connection during the transformer's many years of operation.

The first benefit concerns mechanical stability.

With one hole, the cable lug is pressed at a single point and can rotate minimally around the bolt axis. This movement isn't large, often fractions of a millimeter, but in power engineering, even such small changes matter. A transformer during operation is not a completely static element. There are magnetic core vibrations, temperature changes causing material expansion, and electromagnetic forces generated by fault currents.

If the connection has only one attachment point, the lug may shift slightly over time. Two mounting holes eliminate this problem. The cable lug becomes locked at two points, which practically prevents rotation and stabilizes the entire connection.

The second benefit is related to contact surface area.

Power connections work best when the contact surface area between metals is as large as possible. In practice, this means the conducting elements must be pressed together with adequate force over as large an area as possible.

Two bolts result in a more even distribution of pressure over the surface of the cable lug or copper busbar. Thanks to this, a larger part of the metal surface participates in conducting current. As a result, local current density decreases and energy losses at the connection point are limited.

The third benefit concerns one of the most important parameters of any electrical connection:

CONTACT RESISTANCE

Contact resistance always arises where two conductors are mechanically joined. Even very smooth metal surfaces actually only touch each other at many microscopic points. The better the pressure and the larger the contact surface, the lower the connection resistance.

If contact resistance increases, the phenomenon of heat generation appears according to Joule's law. Electrical energy starts being converted into heat at the connection point.

To illustrate the scale, it's worth looking at a simple example:

If the connection resistance increases by just 100 microohms, and a current of 600 amperes flows through the joint, the power loss will be about 36 watts at a single point.

On paper, this seems like a small value. However, in reality, this energy is released on a very small metal surface.

This means local heating of the joint to temperatures significantly higher than the ambient temperature. Over time, this can lead to surface oxidation, a further increase in resistance, and accelerated degradation of the connection.

Two bolts help keep contact resistance at a minimum level because they provide stable pressure and a larger effective contact area between metals.

In practice, terminals with two holes appear most often in several situations.

The first is a transformer with higher power.

As power increases, operating currents and requirements for the quality of electrical connections also increase.

The second situation is connections made using copper busbars instead of cables.

Busbars are rigid and heavy, therefore requiring more stable attachment.

The third situation is industrial installations or transformer stations operating in difficult operating conditions.

Vibrations, temperature changes, and high fault currents mean that the mechanical stability of the connection becomes critical.

In such cases, using two mounting holes in the bushing terminal is not a construction luxury.

It is a design element that significantly increases the reliability of the entire transformer over a long operating period.

MV transformer bushing terminal with two mounting holes intended for connections with higher current loads. The double-bolt construction enables stable connection of the cable lug or copper busbar, increases the contact surface area, and limits contact resistance. This solution is most often used in transformers with higher power ratings, in transformer stations with busbar connections, and in installations meeting distribution system operator requirements, where long-term connection stability and minimization of joint heating are crucial.

© ENERGEKS 2026

At Energeks, we take such details seriously. Our MV transformers can be equipped with various bushing termination configurations, tailored to the station design, cable connection method, and grid operator requirements. This applies to both single-hole and double-hole terminals, as well as various types of connection clamps used in power engineering, such as TOGA-type solutions, selected depending on the connection configuration and design standards. If you want to see more examples of such solutions, check out our Energeks transformer offer,

or contact our advisors directly to match the solution precisely to your needs.

How the number of bolts in an MV transformer terminal affects current, temperature, and contact resistance

In power engineering, there is something beautiful in the details.

From the outside, a transformer seems like a massive, calm machine. Several tons of steel, a magnetic core, an oil tank. Meanwhile, its longevity is often determined by elements you can hold in your hand. One of them is the bolted connection at the end of the bushing.

At first glance, the difference between one and two bolts seems like a trivial detail.

In reality, it is a decision that affects three very important physical phenomena.

The flow of current, the temperature of the connection, and contact resistance.

And it is these three parameters that decide whether the connection will work calmly for 30 years or start showing signs of fatigue after a few seasons.

#1 Let's start with current.

The greater the transformer's power, the larger the currents appearing in the system. In distribution transformers with a power of several megavolt-amperes, currents on the medium voltage side can reach hundreds of amperes. Under such conditions, even a small imperfection at the contact point begins to matter.

Current does not flow uniformly through the entire metal surface. In reality, it flows through many microscopic contact points where the metal surfaces actually touch. Each of these points carries part of the total current.

If the contact surface is small, the current density at these points increases.

And when current density increases, temperature also increases.

#2 This leads us to the second phenomenon: Temperature.

In every electrical connection, contact resistance appears. Even in the best-made connections, there is a slight electrical resistance resulting from the microstructure of the metal surface.

Joule's law states that the power dissipated as heat equals the product of resistance and the square of the current. The formula is simple, but its consequences are enormous.

If the current is 500 amperes and the contact resistance is only 50 microohms, about 12.5 watts of heat is dissipated at the connection point. That's not much, as long as the heat is distributed over a large metal surface.

The problem begins when the electrical contact is limited to only a small fragment of the surface. Then this energy concentrates in one place and the temperature starts to rise.

Two bolts act here as a very simple but extremely effective engineering tool. They increase pressure and distribute it over a larger surface. Thanks to this, the number of microscopic contact points between metals increases, and contact resistance decreases.

#3 The third phenomenon is equally interesting: Electrical stability over time.

A bolted connection is not a perfectly rigid structure. During transformer operation, temperature changes occur. Metal expands and contracts. The transformer core generates slight magnetostrictive vibrations. During grid faults, powerful electromagnetic forces appear.

If the connection is held by only one bolt, the cable lug may move minimally. These are very small movements, often on the order of tenths of a millimeter. However, over many years of operation, such micro-movements can gradually degrade contact quality.

Two attachment points stabilize the connection in a completely different way. The cable lug becomes immobilized in two places, and pressure is distributed more evenly. The connection is less susceptible to geometry changes during device operation.

That's why, in transformers with higher power ratings, manufacturers very often use double-bolt terminals as standard. This applies especially to units above several megavolt-amperes, where operating currents are already large enough that every construction detail matters.

A similar situation appears in the case of connections with busbars.

Copper busbars are much heavier and stiffer than power cables. They introduce additional mechanical loads into the system resulting from their own weight and from electromagnetic forces during faults. Two attachment points allow these forces to be distributed and protect the transformer bushing from excessive stress.

Do grid operators require terminals with two bolts in MV transformers?

In many projects, yes. Distribution system operators manage thousands of transformers working in very diverse environmental conditions. Every failure is analyzed, and conclusions later find their way into technical guidelines for new installations. Over the years, in many countries, this has led to the introduction of requirements for double-bolt bushing terminals in specific classes of MV transformers.

Power engineering is a field that learns from experience. Every overheated connection, every thermal imaging inspection report, and every grid event analysis becomes part of the knowledge that later influences design standards.

Therefore, when you look at a transformer bushing terminal and see two bolts instead of one, often behind it is not only the manufacturer's decision but also grid operator requirements and years of practical observation of equipment operation in real power systems.

Transformers such as MarkoEco2 are designed with real distribution grid operation in mind.

This means one thing: they must fit the operator's standards even before they reach the station.

That's why, already at the design stage, we consider the technical requirements of distribution system operators and investor specifications. This also applies to seemingly minor elements such as the configuration of MV bushings or the method of terminating cable connections.

In practice, this means the transformer arrives at the station prepared exactly for the conditions of a given project.

This approach is simple.

The transformer should not force the grid to adapt.

The transformer should be adapted to the grid.

That's why the bushing configurations, the arrangement of single-bolt or double-bolt terminals, and connection solutions in Energeks transformers are designed to seamlessly fit into operator requirements and the practice of working in real power stations.

Top 5 problems causing cable connections at MV transformers to overheat

In the operational practice of medium voltage transformers, very many problems do not start with the transformer itself. They start with the connection. The place where the cable or busbar meets the bushing terminal.

This is one of the most stressed points in the entire system. Large currents flow there, temperature changes occur, and at the same time, it is a mechanical connection dependent on installation quality. That's why minor installation errors can, after a few years, lead to overheating, metal oxidation, and in extreme cases, even failure.

Problem 1: Imprecise preparation of the contact surface.

Metal surfaces, in theory, should fit together perfectly. In practice, on their surface there are oxide layers, dirt, and sometimes even a thin layer of paint or residues from cable lug production. If such surfaces are bolted together without cleaning, electrical contact occurs only at a few microscopic points.

As a result, contact resistance increases, and the connection starts to heat up. That's why, in professional installation, contact surfaces are cleaned, and often also protected with a special contact paste that limits oxidation.

Problem 2: Incorrect bolt tightening torque.

Too little tightening causes insufficient pressure of the cable lug against the terminal. The metal surfaces then do not adhere properly, and contact resistance increases. After some time, connection heating appears.

On the other hand, too much tightening torque can deform the cable lug or damage the terminal thread. In extreme cases, it can also cause cracking of insulating elements in the bushing.

That's why transformer and cable lug manufacturers always specify the recommended bolt tightening torque. In professional installation, torque wrenches are used to achieve the proper pressure.

Problem 3: Using the wrong cable lug.

The lug must be matched both to the cable cross-section and to the construction of the bushing terminal. Too small an eye causes improper lug positioning, while too large an eye limits the contact surface. In both cases, connection resistance increases.

Sometimes a encountered problem is also a situation where the terminal has two mounting holes, but only one bolt is used during installation.

Superficially, the installation works correctly. Current flows, the transformer operates, and the installation passes technical acceptance. However, the connection lacks full mechanical stability. The lug may move minimally during temperature changes or transformer vibrations.

After a few years of operation, oxidation of the contact surface appears and connection temperature rises.

Problem 4: Improper cable routing.

A medium voltage cable has significant mass and specific stiffness. If it is routed at the wrong angle or is under tension, it can exert a constant force on the bushing terminal. Over a long period, this causes micro-movements of the connection and gradual deterioration of electrical contact.

That's why, in professional installations, cable supports and appropriate cable bending radii are used to eliminate stresses acting on the transformer terminal.

Problem 5: Lack of periodic connection inspection.

A transformer is designed for decades of operation. However, bolted connections can change over time under the influence of temperature, vibrations, and material aging. That's why, in many industrial installations, periodic inspections are performed using thermal imaging cameras.

Thermal imaging allows very quick detection of a point where the temperature is higher than in the other phases. Often this is the first sign that contact resistance is starting to increase and the connection requires inspection.

In power engineering, very often it is the small details that determine installation reliability. The cable connection at the transformer bushing is one of those places where installation quality has a direct impact on the operational safety of the entire station.

Small detail, big physics

The story of one or two holes in a bushing terminal says more about power engineering than might seem.

Because this is not an industry of spectacular gestures. It's an industry of decisions that at first glance look like trivial details, but in practice work for decades.

An MV transformer doesn't get a second chance every few years. It stands and works. Day after day. In winter, in summer, under load, after faults, in silence and without attention. For 30, sometimes 40 years.

And that's precisely why details like the method of attaching a cable lug matter. Because they decide whether everything will work as it should, without unnecessary losses, without overheating, without surprises.

So when you look at a bushing terminal with one or two holes, you are looking at the result of an entire industry's experience. Physics, tests, errors, and conclusions that someone once had to draw.

At Energeks, we like this level of thinking.

Because we know that a well-designed transformer is not just parameters on paper, but a fit to the reality of operation.

That's why our MV transformers can be equipped with various bushing termination configurations, tailored to the station design, cable connection method, and grid operator requirements.

If you want to see how different solutions look in practice, check out our offer.

And if you appreciate a technical perspective on power engineering without unnecessary noise, we also invite you to our LinkedIn, where we regularly share knowledge from projects and work with transformers.

REFRENCES:

IEEE Power Transformer Handbook, IEEE Press
Electric Power Transformer Engineering, James H. Harlow, CRC Press

It can pretend for years that everything is under control.

And then, in a very short time, it reminds you that the hard sciences also have a hard memory 🫣

A medium voltage transformer is a master of patience.

It can endure more than the table suggests. Work longer than someone planned.

Survive decisions that were borderline but were supposed to work out.

And that's precisely why it can be treacherous.

It doesn't break when things are really bad.

It breaks when, for a long time, things were almost good.

When the power margin was slowly dwindling, and no one noticed the moment when physics started charging interest.

This text isn't about failures.

It's about how to maintain control before the last 20% of margin disappears faster than you expect.

We see it more and more often.

Grids are working more intensively.

Load profiles are sharper.

Renewable sources, energy storage, chargers, inverters introduce dynamics into the system that older design assumptions simply didn't foresee.

The trusty old transformer copes and keeps working.

Only it's operating in a different world than the one it was selected for.

And that's not an unsolvable problem; it's a phenomenon to be understood.

This article is for those who prefer to know sooner rather than replace later.

For people who treat a transformer not like a grey box, but as an element of an energy strategy.

If you read on, you'll see how to recognize the moment when overload stops being flexible, why short episodes have long consequences, and how to make decisions that genuinely extend a transformer's life instead of heroically shortening it.

We'll look at why transformer aging accelerates non-linearly.

We'll explain how much operating outside rated parameters really costs.

We'll debunk the myth of momentary overload and show why many failures are the logical consequence of earlier choices, not equipment malice.

It'll be interesting, so stay until the end, where a small bonus also awaits you🥰.

Reading time: about 9 minutes

When overload stops being flexible

Every medium voltage transformer has a certain tolerance.

The designer isn't naive.

They know life won't be a catalog table.

They know load will spike temporarily, that summer will be hotter than the standard average, that someone will add another charger or inverter.

And for a long time, everything indeed works.

The problem begins when overload stops being flexible and starts being structural. The difference is subtle.

Flexible overload is an episode.

A dozen or so minutes of higher current, after which the transformer returns to thermal equilibrium. Structural overload is a situation where the operating point permanently shifts closer to the thermal limit.

The key indicator isn't the power percentage itself, but the hot-spot temperature of the winding.

IEC 60076 and IEEE guidelines clearly show that the aging rate of cellulose insulation increases exponentially with temperature.

An increase of 6 to 8 °C can double the aging rate.

This isn't a linear relationship. It's a chemical reaction accelerated by temperature.

In practice, the critical moment is recognized by several signals: shortened cooling time after a load peak, more frequent fan activation, an increase in no-load and load losses measured indirectly through active and reactive power analysis.

Add to this the analysis of gases dissolved in the oil, which shows whether the insulation is starting to react.

A transformer doesn't shout. It whispers in the data.

If we don't look at load profiles on an hourly and seasonal basis, it's easy to miss the moment when 80% of rated power stops being safe because the operational context has changed.

And today, context changes faster than ever.

Why short episodes have long consequences

Many investors think like this:

It was only 30 minutes.

Nothing happened.

From an operational point of view, they're right.

From the point of view of insulation chemistry, not necessarily.

Paper insulation in a transformer ages due to cellulose depolymerization.

Every temperature increase accelerates this process. A short episode of high load raises the hot-spot temperature. The cellulose chain molecules shorten.

We cannot reverse this process.

If there are a few such episodes a year, the impact may be negligible.

If they repeat daily during peak hours, we start building a permanent loss of dielectric strength. The transformer still works, but its safety margin decreases.

It's a bit like metabolic debt in the body. One sleepless night doesn't cause a revolution. Hundreds of such nights change biological parameters.

In systems with a high share of RES, high-load episodes often combine with higher-order harmonics generated by inverters.

Harmonics cause additional losses in the core and windings.

Losses mean heat. Heat means accelerated aging.

A short episode can mean a few percent of annual insulation life loss.

No one will see this at the moment of the event. We'll see it a few years later in the form of a failure that seems sudden.

Physics doesn't forget. It accumulates.

And at a certain point, a very specific question arises: since the transformer is still working, is it better to modernize it, regenerate it, or plan for replacement?

This isn't a zero-one decision.

Factors include oil analysis results, the degree of insulation polymerization, energy efficiency, compliance with Ecodesign Tier 2 requirements, and the real costs of losses.

Sometimes renovation makes sense and allows regaining several years of stable operation.

Sometimes economics and safety clearly indicate that it's better to replace the unit before a failure does it for us.

If you're facing such a dilemma, we discuss this topic more broadly in the article:

Is it worth investing in a new transformer when the old one still works?

It's a good complement to this conversation, especially when the decision concerns the next 20 years of installation operation, not just the upcoming season.

How to make decisions that genuinely extend a transformer's life

The most important decision is moving away from catalog thinking.

Rated power isn't an absolute.

It's a reference point for specific conditions.

If a transformer operates in an environment with higher ambient temperature, variable load profiles, and an increased harmonic level, this must be accounted for in the life model.

In practice, this means temperature monitoring, power quality analysis, and periodic oil diagnostics.

Decision number two is planning reserve with the future in mind, not just based on construction loads.

If we know that within three years, energy storage and high-power DC chargers will be added, it's worth planning for a transformer with a higher thermal class or greater power.

Decision number three is peak management.

EMS systems and energy storage control can realistically flatten the load profile.

Sometimes investing in intelligent control is cheaper than premature transformer replacement.

Extending a transformer's life isn't heroism.

It's consistent data management.

An MV transformer can work for 30 or even 40 years.

Provided we don't treat it like an unlimited resource.

Why aging accelerates non-linearly

Here we get to the heart of the matter.

The aging of paper-oil insulation is described by the Arrhenius law.

Simply put, it states that the rate of a chemical reaction increases exponentially with temperature.

If at 98 °C a transformer uses one unit of life per year, then at 110 °C it may use two or three. At 120 °C, the rate of increase is even greater.

The last 20% of the power margin often means operating in a temperature range where aging acceleration is dramatic compared to the nominal range.

That's why we talk about non-linearity.

In the first 60% of load, changes are gentle.

Near the limit, they become abrupt.

That's precisely why a transformer can work without problems for years, and then, in a short time, enter a phase of rapid degradation.

This isn't a whim of the device. It's a consequence of materials physics.

And it's at this moment that the real dilemma appears.

Should we still invest in renovation, drying, oil replacement, or is this already the stage where insulation parameters directly state that the construction is approaching the end of its technical life?

If the topic concerns units with 30, 40 years of operation, it's worth looking more broadly at the technical and economic aspects of such a decision.

We discuss them in detail in the article:

Refurbish or replace? Your transformer's last chance!

It's a natural complement to this part of the conversation, especially when you want to understand where cost-effective regeneration ends and responsible replacement planning begins.

How much does operating outside rated parameters really cost

The cost isn't limited to the energy bill.

First, we shorten the device's technical life.

If the designed service life is 30 years, and we realistically achieve 22, then the missing 8 years have their own capital value.

On the scale of a PV farm or industrial plant, this means millions of PLN shifted in time.

Second, the risk of unplanned downtime increases.

And the cost of downtime often exceeds the cost of the transformer itself.

Third, power quality parameters deteriorate.

Higher temperatures mean higher losses, higher losses mean lower efficiency.

Differences of one or two percent in large installations translate into significant annual amounts.

Operating outside rated parameters doesn't have to be a mistake.

It can be a conscious decision. There's one condition. We must know its price.

The myth of momentary overload

We hear this often. The transformer is oversized; momentary 110% won't hurt it.

It will hurt it or not, depending on the context.

If momentary overload occurs at low ambient temperature and the transformer has cooling reserve, the impact may be minimal. However, if it's 110% on a hot day, with an already elevated harmonic level, the effects are completely different.

The myth lies in looking at the power percentage, not at the thermal and electrical conditions.

A transformer doesn't feel %%. It feels temperature and electric field.

Momentariness isn't a time category. It's an energy category.

Why failures are the logical consequence of earlier choices

A failure is rarely a single event.

It's the result of a sequence of decisions.

Power selection on the edge. Failure to update load analysis after installation expansion.

Abandoning monitoring because nothing happened for years.

Each of these decisions is rational at the time it's made.

The problem arises when the system changes, but the assumptions remain old.

A transformer doesn't know the budget. It only knows the laws of physics.

That's why we say many failures are the logical consequence of earlier choices.

That's good news. Since they're logical, they can be prevented.

The transformer as part of a strategy, not a cost

In many projects, an MV transformer appears in the budget as a purchase item.

Power, voltage, delivery date, price.

Ordered, installed, connected.

It's supposed to work.

But the moment we start looking at it as a strategic asset, the conversation changes tone.

A transformer isn't just a device for changing voltage levels.

It's the energy node of the entire installation.

Every decision about power expansion, every new DC charger, every additional inverter, every energy storage unit passes through it.

If it's minimally selected, the company's entire energy strategy starts being constrained by one grey box in the station.

Life cycle planning means more than just writing "30 years" into the documentation.

It means analyzing how the load profile will change, what the power growth scenarios are, how the structure of loads will change. Today, a production plant has a specific consumption.

In 3 years, it might have a line that's 40% more energy-intensive.

If the transformer has no room for such a change, investment in development starts with infrastructure replacement.

TCO analysis, or total cost of ownership, often brings surprising conclusions.

A cheaper transformer with higher losses generates greater energy costs over 20 years than the difference in purchase price. A unit non-optimally selected for harmonics may operate with reduced efficiency and age faster. In the long-term balance, savings at the start turn out to be an illusion.

When energy storage enters the system, the transformer ceases to be a passive element.

It becomes part of the power control system.

You can smooth peaks, limit overloads, consciously manage reactive power.

That's specific kilowatts less during critical hours and specific degrees Celsius less in the winding.

In this perspective, the last 20% of power ceases to be a free reserve.

It's a zone we treat as an area of high responsibility.

We enter it when we know why, for how long, and with what consequences.

Not because it "still fits somehow."

This isn't a conservative approach. It's a mature approach.

BONUS: Answers to the most frequently asked questions on the topic

Does a transformer always have to operate below 80% power?

No. The key factors are temperature, load profile, and cooling conditions.

In many cases, 90% is safe if it's well calculated and monitored.

Does oil change extend a transformer's life?

It can help if the oil has degraded, but it won't reverse paper aging.

That's why diagnostics must be comprehensive.

Is it worth installing online sensors in older units?

In many cases, yes.

The cost of monitoring is small compared to the value of information about temperature and gases in the oil.

Does oversizing always pay off?

Not always.

Sometimes a better solution is intelligent load management or support from an energy storage system.

Summary and invitation

Transformer aging isn't linear.

The last 20% of power often tempts, because it looks like a safe reserve.

In practice, that's precisely where the technical cost grows fastest.

Fortunately, we aren't helpless. Data from monitoring, temperature and power quality analysis, sensible power planning, and updating design assumptions allow us to keep the situation under control. Without drama. Without fighting fires at the last minute.

An MV transformer can be just another device in the station. It can also be a consciously managed asset that works stably for decades. The difference lies in decisions made earlier, not in the failure itself.

As Energeks, we support investors, designers, and operators in the selection and modernization of MV units based on real work profiles.

Our offer includes oil transformers and resin-insulated transformers, all in Ecodesign Tier 2 standard, designed for high efficiency and a long life cycle. We also deliver complete transformer stations and solutions integrated with energy storage.

If the topic concerns your installation, it's worth talking sooner rather than later.

On our website and LinkedIn, we share knowledge from projects and implementations, showing how to approach a transformer not emotionally, but strategically.

References:

IEEE Std C57.91 Guide for Loading Mineral Oil Immersed Transformers
A classic document that details the relationship between temperature, load, and accelerated insulation aging. You'll find thermal models, life loss calculations, and a practical approach to short-term and long-term overloads.

CIGRE Technical Brochure 761 – Condition Assessment of Power Transformers via https://www.scribd.com/
A very concrete study on assessing the technical condition of transformers, interpreting oil tests, diagnostics, and making decisions about modernization or replacement based on data, not intuition.

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.

—>

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.

—>

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

Accessories and equipment for transformers. What's worth having on hand?

Anyone who has worked with transformers for more than one season knows this scenario.

The documentation checks out, the parameters are calculated, the handover passed without remarks.

The transformer is in place. It's operating. And for a long time, nothing happens.

Then one day, an alarm sounds, there's a smell of heated oil, or irritating vibrations spread through the entire station. That's when the sentence we all know is uttered:

But everything was brand new! 🤬

The problem is that a transformer is never a solitary device.

It's the center of a small ecosystem. Current, heat, vibrations, moisture, dust, mechanical stresses. They all circulate around it daily. Accessories aren't just aesthetic or catalog add-ons.

They are the tools that allow this ecosystem to remain stable.

This article is a map for thinking about which transformer accessories are worth considering from the start, because later they become the answer to questions that arise under stress, often after the fact.

Reading time: ~10 min

Why transformer accessories determine trouble-free operation

A transformer ages slowly and very consistently.

Insulation loses its properties with temperature.

Oil degrades faster if it's not monitored.

Mechanical vibrations, even minor ones, can over years cause more damage than a single overload.

These are processes you can't see at first glance.

That's why experienced operators say plainly: a transformer without monitoring accessories is a device operating in the dark. And working in the dark always ends in reaction instead of prevention.

In the following chapters, we'll go through the most important groups of accessories.

From electrical components, through temperature measurement and monitoring, to mechanics and cooling.

Each one addresses real problems that genuinely occur.

Insulators and connections, or the first line of electrical peace

It always starts with the connection.

And that's not a coincidence or a figure of speech.

All the electrical systems in the world, regardless of voltage and power, boil down to one question:

how to safely and stably transfer energy from one element to another?

Cable, busbar, transformer termination.

It is precisely at this point that two orders, which by nature don't get along, meet.

The electrical order and the mechanical order.

On one hand, we have voltage, electric field, current, temperature.
On the other, mechanical forces, vibrations, thermal expansion, the weight of conductors, and movements resulting from the operation of the entire system.

The insulator is the element that must reconcile these worlds.
It must provide electrical insulation while simultaneously transferring mechanical loads.
It must maintain the geometry of the connection while preventing discharges.
It must be invisible in daily operation but absolutely reliable for years.

It is precisely at these connection points where problems most often begin, remaining hidden for a long time.
Local overheating due to insufficient contact pressure.
Surface micro-discharges that don't yet trigger protection but already degrade the insulation.
Slight loosening of connections caused by heating and cooling cycles.

The transformer as a whole may appear healthy, while its weakest points are operating at the edge of tolerance.

In the case of medium-voltage cable terminations, the method of securing the conductor is fundamental. A cable is not a static element. It changes its length with temperature, transmits vibrations, and is sometimes subjected to additional installation stresses. If the connection lacks controlled pressure, contact resistance appears.
And where there is resistance, heat appears.

In practice, the question often arises: what insulator to choose for a medium-voltage cable termination?

In such cases, medium-voltage cable terminal insulators are used, which provide a stable connection and controlled conductor pressure. Their task is not just electrical insulation.
They actively stabilize the connection.

They ensure uniform and repeatable conductor pressure, regardless of whether the installation is operating in winter at low temperatures or in summer under full load.
This solution is particularly important in stations where cables are long, heavy, or routed in a way that generates additional mechanical forces.

A well-chosen insulator with a terminal ensures the connection maintains its parameters not just on the day of handover, but also after 5 or 10 years of operation.

In installations based on busbars, the problem looks somewhat different.

A busbar is rigid, massive, and transmits much greater forces.
There is no room for random tolerances here.
Precision in positioning and resistance to vibrations resulting from high current flow and electrodynamic phenomena are what count.

Insulators with busbar clamps serve as precise support and guide points.

They maintain a constant system geometry, prevent busbars from shifting, and protect connections from loosening. Thanks to them, contact parameters remain stable even during prolonged operation under high load. This is especially important in industrial installations where a transformer doesn't operate occasionally, but daily, often close to its design limits.

Oil-air bushings are a separate category.

They are responsible for one of the most difficult tasks in the entire transformer.
Safely transitioning voltage from the oil-filled interior to the outside, to the air environment. In this single element, different dielectrics, different tempreatures, and different environmental conditions meet.

An oil-air bushing must be sealed, resistant to aging, contamination, and moisture.

Any weakening of its properties can lead to surface discharges, and in extreme cases, to a loss of the transformer's seal. Silicone versions are increasingly chosen today because silicone handles contamination, rain, UV radiation, and variable weather conditions excellently. Even when the insulator's surface isn't perfectly clean, silicone retains its dielectric properties.

This is precisely why silicone oil-air bushings have become the standard in modern transformer stations. Not because they are trendy, but because they better withstand the real world.
And the real world, as we know, is rarely laboratory-clean ;-)

In environments requiring particular mechanical flexibility, EPDM (Elastimold) insulators are also used. EPDM is, in simple terms, a special type of technical rubber, designed to work where ordinary materials would quickly give up. It's not soft rubber like in a tire nor brittle like plastic. It's an elastomer, i.e., an elastic material that, after deformation, returns to its shape and doesn't lose its properties for years.

You could compare it to a very durable seal that doesn't harden in the frost, doesn't crack in the sun, and doesn't crumble over time. EPDM withstands continuous vibrations, temperature changes from frost to high heat, and the effects of moisture and ozone present in the air.

In practice, this means that components made of EPDM don't 'age nervously'.
They don't crack suddenly, don't lose elasticity, and don't require frequent replacement.
Therefore in compact transformer stations and prefabricated solutions, where everything works close together and is subject to constant micro-movements, EPDM performs significantly better than rigid insulating materials.

Tapered bushings, or safe passage through the housing

A tapered bushing is a component rarely talked about until it starts causing problems.

And it is precisely this component that is responsible for one of the most critical points in a transformer:

the passage of voltage through the housing.

Leaks, micro-cracks, improper installation.

Any of these factors can lead to moisture ingress into the insulation and, consequently, to accelerated transformer aging.

That's why tapered transformer bushings are no place for compromises.

A well-chosen bushing ensures electrical stability, oil tightness, and mechanical strength. In practice, its quality directly translates to the lifespan of the entire device.

In many cases, upgrading the bushing solves problems that were previously attributed to the windings or oil.

Oil and winding temperature, or what really ages a transformer

If there is one parameter that most affects a transformer's lifespan, it's temperature.

A transformer doesn't wear out because it's old.

It wears out because it's too hot.

Sometimes just a little too hot, but for long enough.

In the physics of electrical insulation, there is no mercy or romanticism. There is temperature and time. The rest are consequences.

For decades, it has been known that every increase in winding temperature above the design value dramatically accelerates insulation aging. Every 6 to 8 °C above the nominal operating temperature can halve the insulation's lifespan.

This isn't a textbook curiosity; it's hard operational reality.

For a transformer, this means a reduction in life not by a few percent, but by half.

And most interestingly, this process happens quietly. Without sparks, without noise, without an alarm at startup.

The oil in a transformer cannot be treated solely as an insulating medium.

It is primarily a carrier of information about the device's condition. Its temperature speaks volumes about what's happening inside, even when the windings are still invisible and inaccessible. Therefore, measuring the oil temperature is not an add-on or a premium option. It's an absolute minimum if we want to know how the transformer is really performing.

The simplest and still very effective form of control is transformer oil temperature indicators. Mechanical, without electronics, resistant to environmental conditions. Their huge advantage is immediacy.

A single glance is enough to know whether the device is operating within a safe range or is starting to approach limits that are better not exceeded too often.

When the installation becomes more demanding and loads variable, information alone is no longer enough. This is where temperature controllers, such as the CCT 440, working with PT100 sensors, come into play. This is no longer just measurement. This is temperature management.

Automatic cooling activation, alarm signals, the possibility of integration with a superior system. The transformer stops being mute and starts actively communicating its state.

PT100 sensors for transformers have become standard for a reason.

They are stable, precise, and predictable.

They can be used for both oil temperature measurement and direct winding measurement.

It is precisely they that provide the data which allows for a reaction earlier, before elevated temperature turns into a real operational problem.

DGPT2 Monitoring and RIS Systems - or when a transformer starts to speak

A transformer communicates with its surroundings constantly.

It never operates in silence. It is always signaling something.

It changes oil temperature, reacts with increased pressure inside the tank, generates gases resulting from insulation aging or local overloads.

These phenomena occur regardless of whether anyone is observing them.

The problem is that without appropriate sensors, these signals remain unnoticed.

For the transformer, this is its natural language. For a person without monitoring, it's just background noise.

And it is precisely in this space between phenomenon and information where failures occur, later labeled as 'sudden'.

The DGPT2 system is a classic protective and measuring device used in oil-immersed transformers.

It monitors three basic parameters: Gas, Pressure, and Temperature.

The presence of gas signals processes occurring in the oil and insulation.

A rise in pressure informs about dynamic changes inside the tank.

Temperature allows for assessing the transformer's thermal load.

DGPT2 operates locally and provides clear alarm signals or triggers protective actions.

The RIS system, on the other hand, is a strictly monitoring solution focused on observing trends and analyzing the transformer's condition over time.

It collects data, archives it, and enables interpretation without the need to shut down the device.

Thanks to this, an operator can see not only that a parameter was exceeded, but also how it happened. Whether the temperature rose gradually or suddenly. Whether pressure changes are one-off or repetitive.

Not long ago, both DGPT2 and RIS systems were mainly associated with large transmission stations. Today, they are increasingly used in medium-sized industrial installations and renewable energy farms.

The reason is simple and very pragmatic.

Installation downtime costs more than a monitoring system.

Thanks to such solutions, the operator doesn't learn about a problem at the moment of failure or protective device operation.
They learn earlier, when they still have time to make a decision.
They can schedule maintenance, adjust the load, or check cooling conditions.

The transformer ceases to be a black box and starts being a device that speaks before it starts screaming.

Vibrations and mechanics, the signs of a transformer's life

A transformer vibrates.

Always.

Even a brand new one, fresh after handover, that still smells of paint.

This is not a factory defect or a sign of problems.
The magnetic field, electrodynamic forces, and the core's operation cause the device to live by its own, very subtle rhythm. This isn't visible in catalog data, but it's audible and tangible in the real world.

The trouble begins when these natural vibrations don't stay where they should.

Instead of dissipating within the transformer's structure, they travel further.

To the foundation, to the station housing, to building walls, and sometimes even to neighboring equipment. Then a faint humming appears, followed by irritating noise, and after years, minor cracks, loosened bolts, and components that have... simply shifted apart.

Vibration damping pads for transformers are one of those accessories that rarely impress at the project stage but earn huge points during operation.

They act like shock absorbers. They isolate vibrations from the rest of the structure, reduce noise, and ensure the foundation doesn't have to participate in every impulse of the transformer's work.

It's a simple, somewhat underappreciated, and very effective solution.

In many facilities, it's precisely the lack of vibroacoustic separation that turns out, after years, to be the cause of mechanical problems described with one word: wear and tear.

And the truth is often more prosaic. The transformer was simply gently reminding everyone of its existence the whole time, and no one gave it pads so it could do so more quietly.

Ventilation and cooling, or when nameplate power meets summer

Every transformer has its proud rated power listed in the documentation.

The numbers match, the calculations too. The problem is that these values are very often derived under conditions with only moderate connection to reality. A friendly ambient temperature. Proper ventilation. No heatwaves, no dust, no enclosed station standing in full sun.

And then summer comes.

Concrete heats up like a frying pan. The air in the station stands still.

The transformer does exactly what it always does: dissipates heat.
Only suddenly, it doesn't really have anywhere to put it.

And here begins the real verification of nameplate power.

Transformer overheating rarely starts dramatically.

First, there are a few extra degrees on the oil. Then more frequent fan operation, if there are any at all. Sometimes the need arises to limit load during peak hours.

Seemingly nothing serious, but each such episode adds its brick to the accelerated aging of the insulation.

AF fans for transformer cooling are the answer precisely for this moment when theory meets climate. Their task is simple and very specific. To increase heat exchange where natural convection is no longer sufficient.

Without interfering with the transformer's construction, without replacing it, without a revolution in the design.

That's why AF fans are used both in new installations, as a planned element from the start, and in the modernization of existing stations.

They often appear where a transformer is technically sound, but its operating conditions have changed over time. Greater load. A different consumption profile. Higher ambient temperatures than a decade ago.

In practice, it's precisely additional cooling that very often solves a problem that previously seemed serious.

Instead of constantly balancing on the edge of its power rating, the transformer returns to calm operation.
Instead of plans for costly replacement, reasonable support for heat dissipation is enough.

Cooling doesn't magically increase a transformer's power.
It allows it to safely utilize what it already has.

And in operation, that can be the difference between comfort and constantly worrying if it's going to be too hot again today.

Accessories as a system, not an add-on

The biggest mistake in approaching transformer accessories is treating them like a list of options to tick off at the end of a project. One here, another there, just to have them.

Meanwhile, in real operation, they don't work separately.

They cooperate. They form a system of safety, control, and daily operational comfort.

Insulators ensure energy has a stable path.

Bushings guard the boundary between the interior and the external world.

Sensors and monitoring provide information before a problem appears.

Vibration pads and fans take care of mechanics and temperature, things that work continuously, even when no one is looking.

Each of these elements addresses a very specific situation that, in practice, happens more often than we'd like.

A transformer equipped with such accessories isn't more complicated.

It's simply more resilient to reality. To summer, to variable loads, to vibrations, to time. And time, as we know, is the most demanding test for any installation.

If you've made it to this point, it means you think about transformers not as catalog objects, but as systems that need to work for years.

At Energeks, we believe in a partnership approach. We don't look at a transformer as a single device taken out of context, but as an element of a larger system that must operate stably for years. That's why, when designing and selecting transformers, we always consider the operating conditions, future load, and the realities of operation.

If you want to see which transformers and system solutions best fit your installation, we invite you to explore the Energeks offer.

And if you'd like to stay longer, exchange knowledge, and see what the world of transformers really looks like behind the scenes, join us on LinkedIn.

This blog is an invitation to systems thinking. And to further conversations.

Sources:

C57.143-2024 - IEEE Guide for Application of Monitoring Equipment to Liquid-Immersed Transformers and Components

IEC 60076-1: Power Transformers - General Standard via studylib.net

Winter rarely arrives with a bang.

It more often creeps in quietly.

First, a few chilly mornings.

Then dampness that doesn't disappear even at noon.

And finally, small, easy-to-ignore signals. The transformer is operating. Parameters are still within spec. Nothing is whining. Nothing is sparking. And that's precisely when the problem begins.

Water vapor condensation inside a transformer tank doesn't produce spectacular symptoms.

It doesn't shut down the grid in one day. It doesn't send an SMS alarm. It works like a slow corrosion of trust. Accumulating on the tank walls, in the paper insulation, and in the oil, it systematically reduces the electrical withstand strength of the system.

This is a topic that returns every winter. And almost always when it's already too late.

For years, we have worked with medium-voltage transformers in real operating conditions.

We have seen transformers that were correctly sized electrically, met EcoDesign Tier 2 requirements, had complete documentation, and new oil.

And yet, after two or three winter seasons, they started causing problems.

The common denominator was very often moisture.

Water vapor condensation is not a manufacturing defect. It's a physical phenomenon.

This text is for everyone who wants to understand what really happens inside a transformer tank in winter and how to prevent it before the quiet killer starts counting the losses.

After reading, you will know where the water in a transformer comes from, why the problem intensifies in winter, what the real consequences are for the insulation, and how to mitigate the risk through both design and operation.

Reading time: 12 minutes

Where does water vapor in a transformer tank come from

Air always contains water.

Even when it seems dry.

Relative humidity is not an abstract parameter from a weather forecast. It is the actual amount of water vapor that can condense when the temperature drops.

A transformer tank is a closed space, but it is rarely perfectly sealed in the physical sense. Even hermetic constructions have micro-phenomena of diffusion.

Add to this moments of opening, transportation, installation, oil filling, and maintenance work.

If air with a specific humidity enters the tank interior, and then the temperature of the tank walls drops, water vapor begins to condense.

The dew point is often reached faster than we expect.

In winter, this mechanism works mercilessly.

During the day, the transformer operates, the oil heats up, and the air inside increases its capacity to carry moisture.

At night, everything cools down.

The water vapor seeks the coldest surface.

Most often, these are the upper parts of the tank and structural components

Why winter acts as a catalyst for the problem

Winter is a season of large temperature amplitudes. A difference of several dozen degrees between day and night is not unusual. For a transformer, this means the cyclic breathing of the oil and air volume.

The key concept here is the dew point. This is the temperature at which air with a given relative humidity can no longer keep water vapor in a gaseous state.

For example, air with a relative humidity of 60% at a temperature of 20°C reaches its dew point at around 12 degrees.

This means that any surface colder than this threshold becomes a site for condensation.

The walls of a transformer tank in winter very often have a temperature significantly lower than the air inside. Especially the upper parts of the tank, the covers, and structural components protruding above the oil level. That is where water vapor condenses first.

In breathing transformers, every cooling cycle means drawing in air from the outside. If the air dryer is worn out, incorrectly sized, or simply forgotten, moisture enters the interior. At temperatures near zero, the air's capacity to store water vapor drops sharply, so condensation occurs almost immediately.

In hermetically sealed transformers, the phenomenon is subtler but still exists. Oil changes volume with temperature.

With a temperature drop of 20°C, the oil volume can decrease by about 1%.

In a tank with a capacity of several thousand liters, this means real changes in pressure and the performance of seals.

Moisture doesn't enter through the door, but it enters through the window of physics. The diffusion of water vapor through sealing materials is slow but non-zero. Winter gives it time and favorable conditions.

Additionally, in winter, the transformer often operates under a higher load. Heat pumps, electric heating, electric vehicle charging infrastructure. More heat during the day, more cold at night.

Ideal conditions for condensation.

What happens to water after it condenses

Water inside a transformer tank does not behave like a puddle on concrete. Its fate depends on many factors.

Some of the condensed water flows down the tank walls and enters the oil.

Transformer oil has a limited capacity to dissolve water.

At a temperature of around 20°C, this is in the range of several dozen ppm*.

*ppm = parts per million - equivalent to 1 milligram per liter of substance (mg/l) or 1 milligram per kilogram (mg/kg) of water.

Excess water migrates into the paper insulation. And electrical insulation paper acts like a sponge. Once absorbed, moisture is very difficult to remove from it.

Each percentage point increase in water content within the paper dramatically lowers its electrical withstand strength and accelerates aging. This is not a linear process. It's a curve that suddenly begins to spike.

Olej i wilgoć. Toksyczny duet

Olej transformatorowy pełni dwie kluczowe funkcje. Izoluje i chłodzi. Wilgoć uderza w obie naraz.

Rozpuszczalność wody w oleju transformatorowym silnie zależy od temperatury.

W temperaturze 20° C typowy olej mineralny jest w stanie rozpuścić około 30 do 50 ppm*

Przy 60° C ta wartość może wzrosnąć nawet trzykrotnie.

To oznacza, że w ciągu dnia olej wchłania wilgoć, a w nocy, gdy temperatura spada, nadmiar wody zaczyna się wytrącać.

Już niewielki wzrost zawartości wody w oleju powoduje spadek napięcia przebicia.

Przy poziomie 20 ppm napięcie przebicia może wynosić ponad 60 kV.

Przy 40 ppm spada często poniżej 40 kV.

To różnica, która w warunkach zwarciowych decyduje o przeżyciu lub porażce izolacji.

Zimą zdradliwy jest efekt pozornej poprawy.

Pobierając próbkę oleju w niskiej temperaturze, można uzyskać wynik wskazujący niższą zawartość wody rozpuszczonej. Część wilgoci znajduje się wtedy już w papierze lub w postaci mikrokropelek, których standardowe badania nie zawsze wychwytują.

Do tego dochodzi przyspieszone starzenie oleju.

W obecności wody i podwyższonej temperatury rośnie tempo reakcji chemicznych.

Tworzą się kwasy. Zwiększa się liczba kwasowa.

Olej traci swoje właściwości szybciej, niż przewiduje IEEE.

Oil testing in winter - 3 key methods

In winter, interpreting oil test results requires particular caution.

Three tools become crucial.

The first is determining water content using the Karl Fischer method.

The result must always be referenced to the oil temperature at the time of sampling and the transformer's operational history. A low ppm result from a cold sample does not mean moisture is absent. It may mean it has already left the oil.

The second tool is the analysis of Dissolved Gases (DGA).

Elevated concentrations of hydrogen and carbon monoxide in the absence of classic fault gases can be the first signal of insulation paper degradation caused by moisture.

The third element is observing trends, not single data points.

In winter, comparing results from different seasons is especially important.

Spikes in water content between summer and winter tell more than the absolute value.

Analysis of transformer oil allows for detecting the effects of water vapor condensation before it leads to degradation. This type of analysis helps identify insulation threats before winter failures occur. Photo CC: Freepik/13628

A transformer doesn't fail on the day it's tested. It tells a story that one must know how to read.

Paper insulation. The weakest link

At first glance, paper insulation seems like a secondary element.

It's not visible from the outside, it doesn't have parameters easily sold in a table, it doesn't impress like power or efficiency. And yet, it is very often what determines the real end of a transformer's life.

Electrical insulation paper ages by definition.

The process of cellulose depolymerization always occurs, even under ideal conditions.

The problem begins when moisture enters the game. Even a small increase in the water content of the paper acts as an aging catalyst. It is accepted that each doubling of the paper's moisture content significantly accelerates the degradation of cellulose chains.

What does this mean in engineering practice?

A drop in the mechanical strength of the windings. The paper ceases to serve as a stable spacer, and the windings lose their resistance to the electromechanical forces that appear during faults.

A transformer can operate correctly for years, until the first major grid test. Then, weak insulation doesn't fail spectacularly. It simply doesn't hold up.

Moisture is not a failure. It's a process.

A quiet killer that doesn't destroy immediately but systematically erodes the transformer's safety margin. And that's precisely why paper insulation is often the weakest link in the entire system.

Not because it is bad, but because it is merciless towards neglect.

Hermetic transformer or one with a conservator? Differences in moisture risk

In winter, a transformer quickly reveals which school of construction it comes from.

A hermetic transformer, by definition, limits contact with external air. The oil, gas space, and tank form a closed system. For moisture, this is a difficult situation. There are no revolving doors, no daily invitations for water vapor to enter. This is a huge advantage during the heating season.

But a hermetic transformer is not a magical vacuum capsule.

It's still steel, seals, and people doing the assembly. One poorly tightened connection, one gasket installed on a humid day, and moisture has a subscription for years. No dryer, no vent, no evacuation route. Silence, calm, and very long-term consequences.

Constructions with an oil conservator work differently.

Here, the oil volume is compensated by contact with atmospheric air.

This is a known, proven, and still common solution. However, in winter, it requires character.

An air dryer is not a decoration. It's the security guard at the gate. If it's asleep, moisture walks in without asking. And in winter, a dryer tires out faster than in summer. The gel loses effectiveness, indicator colors can lie, and every night's cooling cycle is another dose of moisture sucked inside.

In short, it looks like this. In a hermetic transformer, the design and installation are responsible. In a transformer with a conservator, operation is responsible. Physics is impartial, but very meticulous.

Therefore, the choice shouldn't start with the question which is better, but rather who will take care of it during winter.

We've already covered this topic in more detail here:

Transformer oil conservator – what it is, how it works, and when it is needed

Because water vapor doesn't have a favorite technology.

It simply checks where it can enter without knocking.

Common installation mistakes

Moisture is rarely the fault of the equipment itself.

More often, it's the result of small oversights:

✖ Opening the tank in humid conditions without protective measures.
✖ Leaving the transformer without oil for extended periods.
✖ Transport and open-air storage without protective covers.
✖ Lack of preheating before startup in winter.

Each of these elements seems harmless on its own. Together, they build the perfect environment for condensation.

Symptoms that are easy to ignore

The first signals of moisture presence are subtle:

✖ Slight changes in oil parameters.
✖ A gentle increase in the dissipation factor (tan delta).
✖ A minimal reduction in breakdown voltage.

They often end up in a periodic test report and remain there for years. Without any action (✖!) because, after all, the transformer is operating. The problem is that physics doesn't read reports.

How to reduce the risk of condensation

It's impossible to completely eliminate moisture.

But it is possible to manage it.

From a design perspective, it's worth opting for hermetic constructions.
Ensure appropriate oil volume reserves and solutions that minimize temperature fluctuations.

From an operational perspective, discipline is key.
Inspections, oil testing, responding to deviations.

In winter, the startup procedure becomes particularly important.
Gradual loading.
Avoiding sudden heating and cooling cycles.

A modern approach to MV transformers

Modern transformers are designed with such scenarios in mind.

Winter will always come.
Water vapor condensation doesn't make noise.
It doesn't flash red.
But it leaves a mark every season.

Conscious design, correct installation, and attentive operation allow you to erase that mark before it turns into a costly failure.

That's why the choice of a transformer is increasingly not just a decision about power and voltage.
It's becoming a decision about resistance to real operating conditions.

If you are considering purchasing or replacing a transformer, our current range of oil-immersed transformers has been designed precisely for scenarios where moisture, temperature variability, and seasonal load changes are the norm, not the exception.

They are complemented by dry-type transformers for where environmental conditions or the nature of the installation require a different approach.

We also invite you to the Energeks community on LinkedIn, where we regularly share knowledge from the power engineering industry.

SOURCES:

IEEE Power and Energy Society. Moisture effects in oil filled transformers.

CIGRE Technical Brochures on transformer insulation ageing.

IEC publications on insulating liquids and moisture management.

Cover Photo: Freepik/2148635097

There is a moment like that.

The transformer is already on its foundation, the oil is filled, everything looks solid, and someone half-jokingly says, "Well, that's one thing off our plate."

The unit is in place, voltage is present, the network is operational. At first glance, the matter is closed.

Except an oil transformer doesn't know the concept of "off our plate."

It is only just beginning its work.

And it remembers very well how it was installed, the conditions it operates in, how it was treated in the first months of service, and whether anyone even glanced at its documentation after commissioning.

When writing about the installation and maintenance requirements of oil transformers, we are not revisiting theory for theory's sake.

We are revisiting experiences from project implementations, whose origins almost always lie much earlier than it seems. Often in decisions that, at the moment of installation, seemed minor, obvious, or "done this way for years."

This article is for designers, contractors, investors, and maintenance personnel who want to have calmer heating seasons and fewer phone calls that start with the words, "something's up with the transformer."

To start, we'll talk about why installing a transformer is more than just correctly placing it on a foundation.

Next, we'll look at daily operation and what the transformer "tells" us through its behavior long before a failure occurs.

Finally, we'll return to maintenance, understood not as a checklist of tests, but as a way of thinking about a device that is meant to operate stably for decades.

reading time ~10 min

Installation of an oil transformer, or the moment you create your future or problems in installments

Installing an oil transformer is not just a "logistical operation."

It is not just unloading, placing, and signing a handover protocol. It is the moment when this device gets its character. Like a person at the start of their career. You either set them up for success, or later you'll be hauling them to workshops. Except this involves costly, time-consuming hassle.

A transformer pays you back for everything in failures.

A shoddily made foundation is a classic.
Concrete, sure. Rebar, sure. There was a design, sure.
The level was checked once because they were in a hurry. "It's almost level."

And here, the first red light goes on. An oil transformer is patient, but it's not naive. It remembers every millimeter of tilt, every makeshift solution, and every solemn "we'll fix it later." "Later" usually never comes.

At first, everything looks proper. Oil is filled, the tank stands, cooling works.
Except with even a slight tilt, the oil inside starts working differently than the manufacturer intended. Cooling becomes uneven, windings experience conditions no one predicted, and the transformer begins to age faster than it needs to. This isn't visible immediately. It shows up over time. Always over time.

Ventilation is another topic that often loses to reality.

An oil transformer doesn't like standing in a stuffy corner, even if it looks like a chunk of solid iron. A too-tight enclosure of a prefabricated transformer substation, a lack of sensible airflow, poorly chosen clearances. A classic. The first season is quiet. The second one too.

And then questions start about why temperatures don't match the theory.

If anyone wants to see how much operating conditions can change the rules of the game, it's worth revisiting the topic of transformer substations operating in heavy industrial conditions:

Otoczenie, montaż i projekt to jeden organizm, a nie trzy osobne tematy:

How not to burn a million? Principles for building a transformer substation for heavy industry

The environment, installation, and design are one organism, not three separate topics.

Grounding is a separate story

"It's connected, the resistance tested out, the protocol is done."

Everyone has heard that.

Except that grounding doesn't exist for paper. It's there to protect the transformer, the installation, and people. A poorly executed one will take its revenge during the first disturbances, overvoltages, or lightning strikes. And again, not always immediately. Most often, when nobody has time for it.

Installation is not a cost. It is an investment. An investment in whether you'll sleep soundly in five years or be nervously sifting through documentation wondering who signed off on the foundation back then.

Operation of an oil transformer, or: it's talking all the time, you just have to stop pretending not to hear it

An oil transformer in operation is not a "grey box."

It is not a device that either works or it doesn't. It talks non-stop.

Just not via email or alarms, until it absolutely has to. It talks through sound, temperature, smell, and behavior. The problem is that many people consider this background noise.

At first, everything is by the book.

It runs, voltages match, load is normal. And then the most dangerous phrase in power engineering appears: "It works, don't touch it." Hearing that phrase, an oil transformer starts planning its revenge, only spread out over time.

The first signal is often sound.

A soft hum is normal, everyone knows that. But a change in the sound's character is not normal. A deeper tone, a metallic resonance, irregularity. This isn't "the charm of an old network." It is information. Ignored information.

Then come the temperatures. Someone glances at the readings and waves it off.
"Summer, it's warm, higher load." Sure, it happens.
But if the transformer regularly runs warmer than before, it's not a whim of the weather. It's a signal that something in the operating conditions has changed. Cooling, oil, ventilation, surroundings. Something is off.

The smell of oil near the transformer is something many people only notice when it's already really strong.
A pity. Transformer oil can tell you a lot much earlier. A change in smell, color, clarity. These are trivialities only for someone who doesn't want to see them. For the transformer, it's a full-fledged language of communication.

Oil leaks are one of those signals that everyone sees, but many pretend it's "nothing serious." A drop here, slight dampness near a gasket, a trace on the oil sump.
At this moment, the oil transformer isn't screaming. It's just raising its hand and calmly saying that something is no longer sealed. Ignoring such small things is a straight path to accelerated insulation aging, cooling problems, and costs that always appear at the least opportune moment.

That's why if someone wants to understand why oil leaks are not a cosmetic issue but a real warning signal, it's worth checking out the separate article dedicated to this topic:

Oil leaks in transformers – do not ignore these signals

There you can see in black and white that oil doesn't escape without reason, and every leak is information about the state of the transformer, not just the state of a gasket.

Operation is also about loading.

An oil transformer can handle overloads because it was designed for that.
But it handles them short-term. Permanently operating at the power limit is not proof that "we managed with a reserve." It is a very consistent and very predictable way of shortening the device's life.

An oil transformer doesn't spring surprises. It is predictable to a fault.
You just have to want to listen, not assume that if the light is green, the issue doesn't exist.

Maintenance of an oil transformer, or why revisiting the beginning saves the future

Maintenance has terrible PR.

It's associated with paperwork, costs, and an obligation that can always be pushed to later. Preferably to the next quarter. Or the next year.

Meanwhile, for an oil transformer, maintenance is the purest form of ensuring longevity. Without it, even the best-designed device starts showing signs of fatigue sooner.

And here it's worth going back to basics for a moment.

To the moment when the transformer was installed and commissioned. Because very often, what we call an operational problem today is not a new failure or some malicious fault of the equipment. It is a consequence of how the installation was done at the start.

An oil transformer doesn't change the rules mid-game. It simply delivers on what it was given at the beginning.

If something was rushed during installation, if something was done by eye, if the handover was quick because the deadline was looming, then maintenance will show it sooner or later. Temperature changes, unusual sounds, faster oil aging, cooling problems. These aren't new phenomena.

They are the effects of earlier decisions, just stretched over time.

Oil testing is the best example here.

It's not a manufacturer's whim or a standard's invention. It is the simplest and cheapest way to look inside a transformer without taking it apart. Physicochemical parameters, dissolved gas content, oil moisture level say more than many a visual inspection.

And yet, in practice, tests are done irregularly or only "for handover," as if the oil stopped working after the protocol was signed.

Seals, accessories, electrical connections, and grounding also age.

A transformer doesn't stand in a sterile lab. It operates under variable temperature, humidity, vibration, and pollution. Every season adds its share. A lack of regular inspection means small problems have time to grow. And then everyone is surprised that something that seemed cosmetic suddenly becomes an emergency issue.

That's why returning to the installation stage when operational and maintenance questions arise is one of the best things you can do.

Checking whether the foundation truly met the assumptions, whether ventilation works as intended, whether grounding was executed according to the craft, not just according to the protocol. This often explains more than hours of analyzing current parameters.

The specific stages that have a real impact on how the transformer behaves later in daily operation, and why some units work quietly for years while others start acting up much sooner, are described here:

Power transformer installation – a comprehensive checklist

The most important thing is the approach

Maintenance is not a checklist to tick off or an obligation imposed by standards.

It is a way of thinking about a transformer as a device that should operate stably for twenty, thirty years. Every test, every note, and every review shorten the list of surprises.

An oil transformer does not spring surprises.

It is predictable to a fault. If something starts happening, it is very rarely a coincidence. Usually, it's a response to the conditions it has been given. Except the response comes with a delay, at a time when everyone is already convinced the matter was closed long ago.

If you want smooth operation, you need to honestly look at the beginning and regularly check in along the way.

An oil transformer doesn't require flattery or gifts. It requires attention.

And attention pays back with interest, most often when others are busy putting out fires.

Don't stop at the start

An oil transformer is not a matter to "tick off." It is a piece of infrastructure that either works quietly for years or regularly reminds you of itself at the least opportune moments.

Transformer installation, operation, and maintenance are not three separate worlds.

It's one story, written from the day the transformer was placed on its foundation. Every decision at the beginning works in the background later. Either for you or against you. An oil transformer doesn't create drama. It simply adds up the facts.

That's why if you're planning an investment, a modernization, or simply want peace of mind in operation, it's worth looking broader than just the moment of purchase.

At Energeks, we have been working with oil transformers in real grid, industrial, and infrastructure conditions for years. Our offering includes both oil-filled and dry-type (resin-insulated) units, selected for specific operating conditions.

Everything is in the EcoDesign Tier 2 class, with full documentation and certificates:

You can find the current transformer offering here.

Thank you for taking the time to read this text.

If even one thought stayed with you, it means it was worth it. And if you want to stay updated, I invite you to Energeks on LinkedIn.

Winter is when everything comes to light.

For most of the year, the installation works correctly.

The oil transformer has a power reserve. Voltage stays within limits. There are no complaints, no alarms, no phone calls from users.

And then the first cold wave hits, and suddenly something no one planned for begins to happen.

Flickering lights. Notifications about voltage being too low.

Heat pumps that shut down exactly when they are needed most.

In the background, a transformer that according to the documentation "should handle this," but in reality is operating on the edge of stability.

This isn't a story about faulty technology.

It's also not a tale of user errors.

It's a story about the collision between a new way of using energy and infrastructure that was designed under completely different circumstances.

Heat pumps have changed the network load profile.

They did it quickly, massively, and often without a parallel shift in thinking about medium voltage transformers. The annual energy consumption still adds up. The nameplate power looks reasonable.

And yet, in winter, voltage drops, alarms, and questions arise that are difficult to answer in a single sentence.

Why do problems start precisely when the temperature drops below zero?
Why does an oil transformer, which operates calmly in summer, react completely differently in winter?
And why does the classical approach to power rating selection stop being sufficient in a world of mass-scale heat pumps?

This article was created to organize these phenomena.

Without scaremongering about failures. Without oversimplifying the physics. Without shifting blame to one side.

We will show what the load generated by heat pumps really looks like during the heating season, how an oil transformer reacts to it, where voltage drops occur, and why they are not random.

And what can be done before the only answer becomes a costly modernization.

If you are responsible for the network, a project, a facility, or investment decisions, this text will help you look at the problem from a broader perspective. One that considers both the technology and the real operating conditions.

Reading time: approximately 13 minutes

How heat pumps really stress the grid in winter

In summer, a heat pump is almost invisible to the grid.

It operates sporadically, mainly for domestic hot water. Its momentary power draw is moderate, and its load profile blends into the background of other consumers. An oil transformer sees it as just one element among many in the landscape.

In winter, the situation changes radically.

The heat pump stops being an add-on. It becomes the primary source of thermal energy, and therefore a device operating for long periods, intensively, and often in sync with hundreds of other similar installations on the same network.

One key word here is: momentary power.

Project documents most often analyze annual consumption. The kilowatt-hours add up, the SCOP coefficients look good, and the energy balance seems reasonable. The problem is that a transformer doesn't see kilowatt-hours. It sees amperes, here and now.

And in winter, "here and now" looks different than in summer.

When the temperature drops below zero, the demand for heat increases. The heat pump's compressor runs longer and more frequently. Its momentary efficiency drops, so generating the same amount of thermal energy requires more electrical energy. Add to this the defrost cycles of the evaporator, which generate short-term but repetitive power draw spikes.

On the scale of a single house, this still looks innocent.

On the scale of a housing estate, a facility, or an area supplied by one MV/LV transformer, the cumulative effect begins.

Everyone heats at the same time.

The coldest days mean peak load occurs at exactly the same morning and evening hours. The grid has no time to "breathe," and the transformer enters prolonged operation near the limits of its thermal and voltage capabilities.

This is where the first paradox appears, which often surprises investors and designers.

An oil transformer may not be overloaded in terms of power, yet it can still cause problems.

Why?

Because the problem isn't always exceeding the nameplate rating. Often, it is the voltage drop resulting from the nature of the load.

Heat pumps, especially inverter-driven ones, are not linear loads. Their current draw changes dynamically. At low temperatures, the current on the low-voltage side increases, and every additional ampere means a greater voltage drop across the transformer's impedance and the supply line.

In summer, the same transformer operates at a higher secondary voltage, lower current, and with a large regulatory margin. In winter, that margin disappears.

If we add to this networks designed decades ago with the assumption that the main loads would be lighting, appliances, and occasional electric heating, the picture becomes clear.

This isn't a failure.

This is a change in boundary conditions that the infrastructure simply wasn't designed for.

In the next part, we'll take a closer look at how an oil transformer reacts to such a load from a physics perspective. Without myths about "overheating in winter" and without magical explanations. Only what really happens in the core, windings, and oil when the grid starts breathing frost.

What really happens inside an oil transformer during a frost

From the outside, a transformer looks the same in July and January.

The same enclosure. The same oil. The same parameters on the nameplate.

The difference begins on the inside.

An oil transformer does not react to winter in an intuitive way. The low ambient temperature is not a problem in and of itself. Quite the contrary. Cooling is more efficient then. The oil dissipates heat to the surroundings more easily, and the thermal headroom seems larger than in summer.

And it's right here that a false sense of security is born.

Because in winter, the problem is not the transformer's temperature. The problem is voltage and current.

When the load on the low-voltage side increases, the current in the windings rises. Along with it, copper losses—proportional to the square of the current—increase. This phenomenon is well known and accounted for in design.

But simultaneously, the voltage drop across the transformer's impedance increases.

Every transformer has its short-circuit impedance. This is not a flaw or a random feature. It is a design parameter that determines how the transformer will behave under load and during a short-circuit.

The greater the current, the greater the voltage drop.

In summer, this drop is hardly noticeable. In winter, under prolonged load close to peak, it begins to be felt by the connected equipment.

Heat pumps are particularly sensitive to this.

The inverters controlling the compressors have their own lower voltage thresholds. When the voltage drops too low, the electronics react immediately. First, it limits power. Then it goes into an alarm state. Finally, it shuts the device down.

From the user's perspective, this looks like a random failure.
From the transformer's perspective, it's a logical consequence of operating under conditions the network wasn't designed for.

A further domino effect occurs.

When some heat pumps shut down due to low voltage, the load temporarily decreases. The voltage bounces back up. The devices attempt to restart. The inrush current appears simultaneously at many points in the network.

The transformer receives a series of load impulses that further destabilize the voltage.

This is not an overload in the classical sense.

It is an operational instability resulting from the nature of the loads and their synchronization.

This often leads to a question about the transformer's tap changer.

If the voltage is dropping, maybe it's enough to raise it.

Sometimes this helps. Sometimes it just shifts the problem elsewhere.

Raising the secondary voltage increases the margin for heat pumps, but it also raises the voltage during hours of lighter load. This can lead to exceeding permissible voltage levels for other consumers. Especially where the network is short and has low impedance ("stiff").

A transformer does not operate in a vacuum. It is a part of a system.

If the system has changed, the transformer begins to reveal its weak points.

In the next part, we will examine why classical methods for selecting transformer power ratings are becoming insufficient in a world of mass-scale heat pumps and what warning signs appear long before the first winter alarm.

Why the classical power rating selection method stops working

For years, everything was logical and predictable.

Selecting a transformer was based on installed power, simultaneity factors, and annual energy consumption. Add a small safety margin—sometimes 10 percent, sometimes 20. In most cases, that was enough.

Because the loads were passive and spread out over time.

Lighting, motors, household appliances. Each had its own operating rhythm. Even if several devices turned on at the same time, the scale of the phenomenon was limited.

Heat pumps have changed this order.

Not because they are faulty. Not because they draw "too much current." They changed it because they introduce a strong temporal correlation of load.

When it gets cold, they all want to run. At the same moment. For many hours without a break.

Classical simultaneity factors begin to lie. On paper, everything adds up. In reality, the network sees nearly the full load for a long time, not short inrush peaks.

Another element, often overlooked in analyses, comes into play.

A transformer is selected based on active power. Winter problems very often start with reactive power and the nature of the current.

The inverters in heat pumps improve the power factor (cos φ), but they don't completely eliminate current distortions. Harmonics, especially lower-order ones, increase the effective current without a proportional increase in active power. The transformer sees a greater current load, even though the energy meter doesn't show it directly.

This is another reason why "the kW adds up," but the voltage drops.

In practice, this means a transformer selected perfectly according to the old methodology can operate in winter under conditions no one considered. Not as a short-term exception, but as a new norm.

The first warning signs appear early.

They are not failures or protection tripping.

They are subtle symptoms that are easy to ignore.

Voltage at the lower limit of the norm in the morning hours. An increased number of voltage alarms in the inverters. User complaints that "something sometimes flickers." Logs from monitoring systems showing long periods of high load without distinct peaks.

This is the moment when the network is still working. But it has no margin left.

Many investment decisions are made only after the first serious problem appears. In winter, under time pressure, user dissatisfaction, and weather conditions. This is the worst possible moment for a calm analysis.

That's why, in the next part, we will move on to what can be done earlier.

What diagnostic tools truly provide answers, how to distinguish a power problem from a voltage problem, and when a transformer is actually undersized, versus when it's simply poorly matched to a changed network.

What to check before a real problem begins

In winter, the network doesn't forgive illusions.

If the first signs of instability appear, it means physics has already sent a warning signal. It's just not screaming yet.

The most common mistake is trying to answer with a single parameter. Transformer power rating. Cable cross-section. Protection setting. However, winter problems rarely have a single cause.

It starts with measurements. But not the kind that last a few hours on a random day.

A seasonal picture is needed.

Load profiles from summer and winter periods. At least several weeks of data. Preferably with fifteen-minute or shorter resolution. Only then can you see whether the load is impulsive or continuous. Whether the voltage drops slowly or collapses sharply at specific times.

A transformer rarely lies. It simply shows what the network is doing to it.

The next step is to analyze voltage at several points in the low-voltage network, not just at the transformer terminals. The voltage drop at the transformer might look acceptable, while at the end of a supply line it exceeds permissible limits.

This is especially important where heat pumps have been added to existing buildings without upgrading lines and distribution boards.

It's also worth looking at what happens with reactive power and effective current.

If the current rises faster than the active power, it's a signal that the transformer is being loaded in a way that isn't visible in standard energy consumption summaries. Harmonics, phase imbalance, and uneven switching of loads can eat up the margin faster than you think.

A frequently overlooked element is voltage regulation.

Transformer tap settings are often based on historical conditions, from before the facility's modernization. Changing one tap step can improve the situation in winter, but only if preceded by an analysis of voltages across the entire load range. Otherwise, the problem will shift to summer.

This brings us to an important distinction.

Not every winter problem means the transformer is too small.

Sometimes its power rating is sufficient, but it's operating in a network with too high impedance. Sometimes it's correctly sized, but the load is too strongly time-correlated. And sometimes the limit has indeed been exceeded, but no one wanted to call it by its name earlier.

A good diagnosis allows you to choose the right tool.

Upgrading the transformer is one of them. But it's not always the first, nor the most sensible, option.

We've covered this topic in more detail in a separate article:

Renovate or replace? The last chance for your transformer!

In the next part, we'll show which action scenarios are realistic in practice. From the simplest operational adjustments, through changes in network configuration, to investment decisions that only make sense when they are based on data, not winter panic.

How to design and operate transformers in a world of heat pumps

The biggest change in recent years hasn't been about the transformers themselves.

It's about the way we think about the network.

For decades, design was an attempt to predict averages. Average consumption. Average peaks. Average customer behavior. This model worked as long as appliances had different rhythms and didn't respond en masse to the same stimulus.

Heat pumps respond to temperature. Simultaneously. Without negotiation.

This means the network must be designed for extreme scenarios, not just for the annual balance.

A transformer ceases to be merely a source of power. It becomes an element of voltage stabilization under conditions of prolonged load. This changes the selection criteria.

Increasing importance is placed not only on the nameplate rating, but on the transformer's impedance, its voltage regulation characteristics, and its cooperation with the rest of the infrastructure. Two transformers with the same power rating can behave completely differently in winter if they have different short-circuit impedances or different regulation capabilities.

Operation also requires a new approach.

Instead of reacting to failures, it's worth observing trends. Are minimum voltages dropping year by year? Is the operating time under high load lengthening? Is the number of power electronic loads growing faster than assumed?

These are signals that appear long before a crisis.

A well-designed network with oil transformers is not afraid of winter. It has a margin. It has flexibility. And above all, it has the awareness that the way energy is used has already changed and will not return to the state before mass-scale heat pumps.

Therefore, the key question today is not: will the transformer survive this winter?

The question is: will it still operate stably in five years within a network that is increasingly reactive to weather, automation, and simultaneity?

If the answer isn't clear, the best time to act is now. Calmly. With data. Without winter panic.

Because winter will always come. And the network should be ready for it before it gets truly cold.

In the end, it's worth putting a period in a place that doesn't close the topic, but opens up possibilities.

Today, the oil transformer is no longer a passive piece of infrastructure.

In the reality of mass-scale heat pumps, it becomes a tool for conscious management of voltage, losses, and network stability. A well-chosen, properly configured unit that meets current Ecodesign Tier 2 requirements — like the MarkoEco2 from Energeks — can regain the margin that is most sorely missed in winter. Not through oversizing, but through better power quality, lower load losses, and a true match for modern operating profiles.

Our current transformer offering has been designed precisely for such scenarios, where the network must operate stably not only today but also in the heating seasons to come.

It includes both oil transformers, proven in demanding operating conditions and resilient to prolonged winter loads, and dry-type transformers, chosen where fire safety, environmental conditions, or indoor installation are of key importance.

In both cases, the starting point is the same. Voltage stability, low losses, compliance with current energy efficiency requirements, and a genuine fit for modern load profiles—where heat pumps are no longer the exception, but the norm.

Thank you for your time and attention. If you are interested in such analyses, real project experiences, and thoughtful conversations about how the energy sector is changing from within, we invite you to our community on LinkedIn.

Sources:

International Energy Agency (IEA)

https://www.iea.org/reports/the-future-of-heat-pumps

ENTSO E

https://www.entsoe.eu/publications/system-development-reports/