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

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

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

When voltage rises faster than expected

In the world of modern energy systems, the line between standard operation and serious risk is often razor-thin. Transient overvoltages, spikes caused by lightning strikes, overloads, or grid disturbances can occur within milliseconds and bring weeks of work to a halt.

At the same time, dynamic industrial installations, photovoltaic farms, and compact substations today demand much more than just voltage conversion. A transformer is no longer a passive link. It becomes an active participant in the power system.

It protects, it monitors, it communicates, and it adapts.

This article presents four specialized solutions applied in medium-voltage transformers. Each addresses a specific need: safety, control intelligence, resilience to environmental conditions, or ecological impact. While not every application requires all features, understanding them allows for better decision-making.

If you manage energy infrastructure, work in the industrial sector, operate PV farms, or are responsible for ensuring the uptime of distribution substations, this overview may help you avoid costly mistakes and optimize your equipment choices.

What you’ll find in this article:

• How a transformer with surge protection works and when to use it

• What sets a transformer with built-in automation apart and what it offers

• Why TOGA terminals and MIDEL oil are a strong combination for modern installations

• The benefits of a transformer in a metal enclosure with fire-resistant oil

Reading time: approx. 11 minutes

What does it mean when a transformer does more?

A standard transformer is just the beginning. Today’s energy systems demand solutions tailored to the environment: stormy weather, dynamic loads, the need for remote supervision, or limited installation space.

A modern transformer can now perform more functions than ever before. It can:

• monitor and transmit data on load, temperature, and insulation condition

• respond to voltage fluctuations or overloads

• protect against disturbances, both from the grid and from consumers

• minimize fire risk by using fire-safe oils and sealed enclosures

Let’s now take a closer look at the specifics.

Transformer with surge protection – when to use it and how it protects installations from lightning and grid spikes

Voltage spikes are among the most common and dangerous causes of failure in energy infrastructure. A surge protection device (SPD) has a single purpose: to immediately reduce excessive voltage to a level safe for the transformer's insulation and the rest of the system.

Integrating a surge arrester directly into the transformer enclosure is a solution increasingly seen across Europe’s medium-voltage installations, from industrial zones to rural distribution substations.

This approach minimizes reaction time, lowers installation costs, and reduces the number of components exposed to corrosion or mechanical failure.

The SPD works by redirecting the surge energy to ground.

It reacts within microseconds to sudden voltage increases, typically from lightning or switching large loads. Modern class B and C devices can withstand surges of several tens of kA while maintaining performance across repeated events.

Integrating an SPD into the transformer can be crucial where reliability and restoration time are paramount. In many European countries, this is now standard in high-risk facilities: hospitals, data centers, EV charging stations, and PV installations in open areas.

What does a surge protection device do?

It is a component that instantly diverts surge energy (such as from a lightning strike) to ground before it can damage the transformer's insulation.

In practice, it:

• protects transformer windings and downstream components

• extends the life of the entire MV system

• prevents production downtime and losses

Key data:

• response time: <25 ns

• sparkover voltage: 15–45 kV (depending on grid design)

• service life: >10 years under standard surge exposure

When to use:

• substations installed in open terrain

• areas with frequent lightning (e.g. mountainous or coastal zones)

• grids with unstable voltage supply

• mobile or temporary substations

Transformer with control automation – intelligent solutions for MV grids and modern industrial installations

The development of smart grids, industry automation, and the need for remote infrastructure management has led to transformers increasingly being equipped with built-in automation systems. These units do more than measure voltage and current – they also communicate with SCADA systems, enable dynamic reconfiguration, and detect faults in real time.

Transformers with built-in control systems are most commonly used in locations with high load variability – industrial plants, urban networks, EV charging hubs, and interconnection points for distributed energy resources.

The automation package can include energy quality meters, winding and oil temperature sensors, tap changer controllers (OLTC), and communication modules supporting protocols such as IEC 61850, Modbus TCP/IP, or DNP3.

This allows operators to adapt transformer operation to network conditions in real time, anticipate overloads, and optimize energy flow.

Additionally, built-in automation helps meet European efficiency and environmental regulations such as the Ecodesign directive and Regulation 2019/1783. Thanks to precise monitoring, transformers can operate with reduced losses and maintain performance for longer periods.

What does automation include?

• integrated PLC controller

• electrical parameter recorders

• oil and winding temperature sensors

• communication interface (Modbus, CAN, IEC 61850)

Typical functions:

• oil and winding temperature control

• remote switching

• load analysis

• predictive maintenance

Application example:

A 2 MW PV farm in western Europe reduced average winding temperature by 6°C using a transformer with automation. This extended service life by 4 years and eliminated the need for unplanned maintenance.

Where does it work best?

• heavy industry (e.g. steelworks, foundries)

• solar and wind farms

• urban smart grids

• temporary container substations

Transformer with TOGA terminals and MIDEL oil for photovoltaic installations

TOGA terminals (TO – touch-proof terminals) are a special connector format that enhances safety when connecting power cables. These terminals provide superior insulation, reduce the risk of accidental short-circuits, and simplify maintenance.

They are often selected where access to the transformer is limited or where operations are carried out in the field – such as PV farms, open-air industrial applications, or containerized solutions.

Even more important is the choice of insulating fluid.

Traditional mineral oil, while reliable, is increasingly being replaced by safer and more advanced alternatives. One of them is MIDEL – a synthetic ester with a very high flash point (over 300°C) and extremely low toxicity. It is biodegradable, fire-safe, and compliant with environmental regulations in many European countries.

Using MIDEL oil in transformers with TOGA terminals combines safety and sustainability. Such units are more resilient to environmental conditions, require less maintenance, and can be installed in protected areas – near water sources or in nature reserves.

A TO + MIDEL transformer is the ideal choice for those who refuse to compromise on operational safety or environmental impact.

TOGA terminals:

• fast and safe plug-in cable connection

• minimized short-circuit risk during installation and maintenance

• better ergonomics in field and industrial setups

• easier inspection and servicing

MIDEL oil:

• fire-resistant – flash point above 300°C, far higher than mineral oil

• biodegradable – over 98% breakdown within 28 days

• non-toxic – safe for people and ecosystems even in case of leaks

• compliant with EU norms – REACH, RoHS, approved for use near water protection zones and Natura 2000 areas

Applications:

• ideal for PV farms where fast installation, safety, and environmental resilience are essential

• effective in industrial contexts where installation space is limited and safety is a priority

Technical and environmental benefits:

• reduced fire and contamination risk

• high reliability under variable weather conditions

• eco-conscious choice aligned with ESG and sustainability policies

Transformer in a metal enclosure with MIDEL oil – sealed, durable, and safe in a compact format

A compact design, easy transport, enhanced mechanical resistance, and full safety compliance – these are the main advantages of transformers housed in a metal enclosure and filled with MIDEL oil. These units are increasingly chosen for prefabricated transformer stations, urban installations, and critical infrastructure.

The metal enclosure offers protection against mechanical damage, moisture ingress, and environmental exposure. Combined with a well-selected cooling system – either natural or forced – it enables long-term, stable operation without frequent maintenance.

Using fire-resistant synthetic MIDEL oil increases installation safety, reducing the risk of fire in case of internal faults or overheating. The oil does not release toxic fumes and can be used safely even in highly regulated environments such as medical facilities or public infrastructure nodes.

The M + MIDEL transformer in a metal enclosure is a particularly attractive solution for investors planning grid expansion in confined or complex environments. Ready to connect and resistant to external influences, these transformers deliver uncompromised reliability.

Metal enclosure:

• increased mechanical durability and sealed construction

• protection against moisture, dust, and mechanical impacts

• ideal for prefabricated substations and urban infrastructure

• enables fast installation and simplified logistics

Applications:

• container and prefabricated substations where quick setup and sealed housing matter

• critical infrastructure – hospitals, public facilities, urban areas

• environmentally sensitive locations – without risk of soil or water contamination

Technical and operational advantages:

• low noise and vibration emissions

• reduced failure rates and extended maintenance intervals

• suitable for challenging environmental conditions

• compliant with PN-EN 60076 and Ecodesign directive

When a transformer becomes more than a box

A transformer is no longer just an auxiliary device.

In the era of distributed networks, electromobility, decentralization, and rising environmental requirements, it becomes a strategic part of infrastructure. Choosing the right configuration – with surge protection, automation, safe terminals, or eco-friendly oil – directly impacts system reliability, safety, and operating costs.

Each of the solutions described has a valid purpose and application. The best decisions are those that consider not just today’s needs but also where your installation is heading in the years ahead.

We hope this article helped you see transformers from a new perspective.

If you are planning a project where long-term safety, clear documentation, and adaptability are essential, we are here to support you.

We help select, configure, and test transformers to meet PN-EN 60076 compliance, ready for commissioning, and built for decades of operation.

Check out our transformer range – available in versions compliant with PN-EN 60076, with full routine testing and optional special tests when required by your project or environment.

Planning a retrofit or new station? Get in touch – our engineers can help tailor solutions to your specific conditions.

Join our community on LinkedIn – we share hands-on knowledge from hundreds of real-world projects.

Thank you for reading to the end.

We hope this article offered not just information but inspiration for asking better questions – because better questions are what move the energy sector forward.

Sources:

Shell MIDEL

Power Transformers - Ecodesign requirements apply to this product.

IEEE Smart Grid Research: Control Systems

One decision that can eat away your solar ROI

It was supposed to be a quick return on investment.

A small 99 kW PV farm, set up by a farmer in a rural part of Europe, was expected to pay for itself within five years.

Everything checked out: the location, the panels, the inverters, the grid connection terms. Everything except one detail.

The transformer. A cheap, “universal” model that, on paper, could handle any system.

In reality? Excessive no-load losses, incompatibility with the medium-voltage grid, unstable voltage during peak hours, and months of frustrating back-and-forth with the distribution operator. Now, 18 months later, energy output still fails to meet expectations.

This blog is a remedy for mistakes like that. Written by engineers, for engineers — and for anyone building a PV farm with the help of a friend on the weekend.

If you're wondering which transformer to choose for a 50 kW, 100 kW or maybe 150 kW PV farm — you're in the right place.

You will learn which parameters actually matter, how to avoid mistakes that can cost thousands, and what questions to ask your substation designer before it's too late.

In this article, you’ll learn:

• When 50 kW is still a micro-installation and when it becomes a professional PV plant

• What parameters matter when selecting a transformer for 50, 100 or 150 kW PV systems

• Why a standard transformer might not work well with solar

• Whether it's possible to build a PV system without a transformer — and when

• How to select a PV transformer step by step, using real examples

• What mistakes investors and installers often make when choosing a transformer

• Dry vs. oil transformers — what pays off in agricultural vs. industrial settings

• How to stay compliant with your grid operator and deliver quality energy

Reading time: 12 minutes

What transformer for a 50, 100 or 150 kW PV farm?

It might not look like much — a PV installation rated at 50, 100 or 150 kW. It’s not a utility-scale solar plant, but it’s not residential either. Often it’s a private, agricultural or small business project with one goal in mind: not just to save money, but to earn it.

And this is exactly the power range where things often go wrong — in ways that are hard to reverse. The common denominator? One simple but high-stakes question: what transformer is actually right for a small PV farm like this?

On industry forums, in project documentation, in investor meetings, we keep hearing the same doubts:

• Is a 100 kVA transformer enough for a 100 kW PV plant?

• Should I oversize to 200 kVA “just in case”?

• Can I just use a stock transformer from the warehouse?

And that’s where the trouble starts. Because when it comes to PV systems in the 50 to 150 kW range, a transformer cannot be an afterthought. It’s not just about power. It’s about compatibility with the MV grid, resilience to voltage fluctuations, and understanding that at 50 kW, you are already playing in the professional league — not at home.

Is 50 kW still just a “system,” or is it already a PV farm?

From an investor’s perspective, 50 kW might still feel “small” — a few panel strings on a warehouse roof or a field near the main building. But in the eyes of energy law and the distribution network operator (DNO), 50 kW marks a turning point.

In practice:

• It is the upper limit of a micro-installation

• Anything beyond falls under the category of “small-scale renewable installation” (MIOZE)

Which means:

• No more simplified connection procedures

• A full design and approval process is now required

• Strict technical criteria apply, including harmonic distortion (THDi), voltage compliance, and galvanic separation

That’s why a transformer for a PV system in this category is not just a voltage adapter. It’s a fully integrated component of the electrical infrastructure. It must be compliant with MV grid specifications, resilient to variable load conditions, and designed with future upgrades or energy export in mind.Common mistakes? Unfortunately, all too familiar

Investors often limit the declared capacity to 49.9 kW to avoid the regulatory burden of MIOZE procedures. Yet they still order a 100 kVA transformer “just in case.” Or they install inverters that, at peak generation, push up to 110 percent of nominal power. The result?

• Higher no-load losses – the transformer operates outside its optimal efficiency range

• Increased harmonic distortion (THDi) – standard transformer cores are not designed to handle PV inverters

• Voltage spikes on the MV side – without voltage regulation at ±2.5 percent, synchronization and compliance issues start to appear

What was supposed to be “extra headroom” becomes a bottleneck. Good intentions turn into unexpected faults, performance drops, and delayed settlement with the grid operator.

What parameters define a good transformer for a 50 to 150 kW PV system?

It depends on the configuration, but the core rules are consistent:

• MV grid voltage – most commonly 15.75 or 20 kV, depending on region and local utility

• Transformer ratio – typically 0.4/15.75 kV, though 0.8/15.75 kV is required for 800 V inverter outputs

• Grounding – defined by the operator’s requirements: isolated neutral point, resistor grounded, or directly grounded

• Usage profile – rooftop PV for five-day operations or ground-mounted for seven-day continuous exposure

A 63 kVA transformer is usually sufficient for a 50 kW installation. But if you plan to scale up, it is better to consider 80 to 100 kVA. The condition: proper insulation rating (at least class F), cooling method (ONAN or AN), and a matching voltage ratio for the inverters.

Conclusion

If you're asking yourself which transformer to choose for a 50, 100 or 150 kW PV system, remember there’s no room for guesswork. It’s like choosing the foundation for a building. It might not draw attention at first, but everything else will depend on it. And the cost of getting it wrong stays with you long after the invoice is paid.

What kind of transformer does a PV system really need?

At first glance, a transformer seems like a simple component. Two windings, voltage conversion, an iron core. What could possibly go wrong?

Plenty. That assumption is one of the most common reasons why PV systems underperform. Using a standard transformer for an application it was never meant for creates a mismatch that’s invisible until energy losses, overheating or grid compliance issues show up.

Because solar is not like industrial power supply. There is no steady consumption around the clock. Instead, there are rapid surges at noon, near-zero flow at night, and high levels of harmonic distortion caused by inverters. As a result, the operational environment for PV transformers is fundamentally different.

A PV transformer plays a different tune

So what sets a PV transformer apart from a conventional one?

• Load profile
  In solar, the transformer faces highly asymmetrical conditions. No generation at night, peak output midday. Standard units are not built for such swings.

• Power direction
  In a PV system, power flows from the inverters into the grid – the opposite of traditional setups. This affects thermal behavior and winding design.

• Harmonics
  PV inverters produce current distortion, typically 6 to 10 percent THDi, sometimes more. A transformer for PV must have a suitable core, larger winding cross-sections, and often oversizing to prevent overheating under harmonic load.

• No-load conditions
  On cloudy days or low-irradiance periods, inverters may generate little to no power, but the transformer remains energized. In such cases, no-load losses become a real cost driver.

All this means that a standard transformer might "work" in theory, but in practice leads to reduced efficiency, higher bills, and frustrated technicians.

What are the minimum specs for a PV transformer?

• Insulation class: at least F (155°C), ideally H (180°C), for thermal safety under overload

• Cooling type: ONAN (natural oil and air cooling), ideal for outdoor transformers up to 250 kVA

• Low-voltage winding: matched to the inverter output (0.4 kV or 0.8 kV) – the wrong ratio can trigger failures

• Harmonic tolerance: windings and core must handle THDi levels up to 10 percent without excess losses

Example from the field:
A 150 kW PV farm using 800 V inverters was fitted with a 0.4/15.75 kV transformer. After just three months, problems emerged: overheating, inverter shutdowns, lost output. Diagnosis? A mismatch in voltage ratio. The transformer was replaced with a 0.8/15.75 kV unit with an amorphous core. Production rose by 11 percent, and the system finally delivered as promised.

Can a standard transformer be used in a PV system?

This question comes up surprisingly often. Can I use a regular transformer for a solar farm?

Technically, yes — if efficiency, durability and grid compliance are not your priority.

But if you expect your system to perform reliably for 15 to 20 years, the answer is simple: it’s not worth the risk.

Can you build a PV system without a transformer? When it works and when it’s asking for trouble

This is one of the most commonly searched questions among individual investors and small business owners. Does a PV installation really need a transformer? Especially in the 30 to 50 kW range, where the line between a micro-installation and a small PV plant is blurry and every additional component, including the transformer, adds to the cost. So the question arises — could you skip it?

PV without a transformer — wishful thinking or real option?

Let’s start with theory. A transformer in a photovoltaic system is not absolutely required from a physics standpoint. In certain technical conditions, it is possible to build a PV system without a dedicated transformer station. But those cases are the exception, not the rule.

When can a PV system operate without a transformer?

• Installed capacity is up to 50 kW — still qualifies as a micro-installation, so direct low-voltage (LV) grid connection may be allowed

• You have access to an internal LV switchboard (not part of the DSO infrastructure) — for example, expanding a factory’s existing internal grid

• Low-voltage inverters (3x400 V) — so no galvanic isolation or voltage step-up is required

• DSO accepts direct connection — which is often the most difficult part. Operators usually require isolation and voltage compliance with the grid

In such a configuration, instead of a transformer station, you must ensure:

• proper protection devices

• reactive power compensation

• harmonic filtering (e.g. active filters)

• continuous energy quality monitoring

But here’s the catch — very few installations meet all of these criteria simultaneously.

What could replace a transformer in a PV system?

In theory, a transformer can be "replaced" with a carefully configured system of inverters and filters. In practice, though, this is not really a substitution but a complete redesign. The inverters would need to ensure:

• output voltage matches the grid (e.g. 3x400 V, ±10%)

• harmonic distortion remains low (THDi < 4%)

• operation without galvanic isolation (which requires DC-side grounding)

• adaptation to variable load and reactive power demands

All of this increases the system’s complexity and cost. And often, it turns out that building a transformer station is actually the more economical choice. It’s not a paradox — it’s the result of the many roles a transformer plays in a PV system: voltage regulation, galvanic separation, harmonic filtering and protection against disturbances.

When is a transformer absolutely necessary?

• When capacity exceeds 50 kW — the system qualifies as a small-scale installation and falls under strict grid rules

• When connecting to a medium-voltage grid (15 or 20 kV) — a transformer is required, without exception

• When galvanic separation is required by the operator — which is the case in most countries

• When the system is far from the load center — for example, in a ground-mounted PV plant with no existing LV infrastructure

A transformer is not just a voltage step-up device. It is also a safety buffer that protects inverters from overvoltage and grid-side noise. It is what allows the system to meet the technical connection conditions — and without that, no grid agreement will be signed.

Conclusion — can you build PV without a transformer?

Yes, but only in specific setups. And usually only for smaller capacities, up to 30 to 40 kW. In every other case, a transformer is essential — not just because "rules say so," but because it determines:

• user safety

• grid operator approval

• the quality of injected power

• the long-term durability of your inverters

What transformer for a 50, 100 or 150 kW PV plant? Technical specs and real-life examples

You walk onto the construction site. PV tables are mounted, inverters are wired, the foundation for the substation is in place. Everything looks great — until you look at the transformer. It’s a stock 160 kVA unit with a 0.4/15.75 kV ratio. Sounds good? Maybe — but if your inverters output 800 V, that transformer could be a time bomb.

At Energeks, this is not theory. This is our daily reality.

What transformer for a 50 kW PV system?

For a 50 kW installation with 3x400 V inverter output, the typical transformer setup is:

• 63 kVA

• 0.4/15.75 kV or 0.4/20 kV ratio

• ONAN cooling

• Voltage regulation ±2 x 2.5%

• Insulation class F

• No-load losses up to 350 W

This configuration meets MV grid requirements, enables safe connection to the DSO switchgear, and helps compensate basic inverter-generated harmonics. And let’s be clear — even in small PV farms, the transformer is not just a “step-up box.” It stabilizes the entire system.

What transformer for a 100 kW PV system?

This is where things get serious — especially because of the increased peak current levels. For a 100 kW PV plant, we recommend:

• 125 kVA

• 0.4/20 kV or 0.8/15.75 kV ratio depending on inverter specs

• Core rated for THDi up to 8 to 10%

• Insulation class H for improved thermal endurance

• No-load losses up to 600 W, load losses around 1.5 kW

A common question is: is 100 kVA enough for a 100 kW system? The answer is — only under ideal conditions. In practice, a 20 to 25 percent oversize margin helps maintain efficiency and system life, especially for projects expected to operate 15 to 20 years.

What transformer for a 150 kW PV system?

At this scale, any mismatch in specs can quickly compromise safety and grid compliance. A typical configuration:

• 160 to 200 kVA (most commonly 200 kVA)

• 0.8/15.75 kV ratio — necessary for 800 V inverters like SolarEdge or SMA CORE2

• Amorphous or oversized conventional core

• ONAN or AN cooling, depending on indoor or outdoor mounting

• Voltage regulation ±2 x 2.5% or even ±5%

• Harmonic resilience: THDi up to 12%

A frequent mistake? Using a 0.4/20 kV transformer with 800 V inverters. The result: inverter overheat alarms, voltage mismatch, and a drop in output by 8 to 10 percent versus expected production.

Does the transformer have to be bigger than the PV capacity?

This comes up almost as often as “can I save money on cables?”

In theory, the transformer can match inverter output exactly. In practice:

• it should be oversized by 10 to 15 percent

• account for cable losses

• allow for short-term overloads on sunny days

• give room for future expansion

So for a 150 kW PV plant, a 200 kVA transformer is not overkill. It’s standard good practice that ensures stability and compliance.

Step-by-step transformer selection for a PV farm

• Check inverter output voltage — is it 400 V or 800 V?

• Choose the right transformer ratio — based on grid voltage (15.75 or 20 kV)

• Account for THDi — if above 8 percent, choose a unit with reinforced low-voltage windings

• Verify short-circuit level of the MV grid — transformer withstand must match it

• Select insulation and cooling — class H and ONAN are a solid baseline

This is not a spreadsheet. It’s a construction site. A transformer for a 50, 100 or 150 kW PV plant has to withstand 365 days of work per year, with variable loads, under real grid conditions. A poor choice can cost you not only your warranty — but the profitability of the entire system.

Why your PV transformer overheats: 5 mistakes that only show up after commissioning

On paper, everything looked perfect. Inverter output: 100 kW. Transformer: 125 kVA. Manufacturer efficiency: 98.4 percent. Sizing margin: 25 percent. Spreadsheet says the return on investment is five years. The investor is happy. The installer too.

Then comes real life. Inverters start disconnecting around noon. Voltage at the low-voltage busbar swings unpredictably. Transformer temperature hits 95°C on a warm afternoon — and that’s not even at full load. What went wrong?

A transformer is not a number — it’s a behavior in a system

A PV transformer is a dynamic component. It operates in a system where everything changes hourly — irradiance, load, grid voltage, harmonic content. And a spreadsheet knows nothing about clouds, surges, or inverter behavior.

Here are the five most common mistakes that do not show up on the drawing board — but appear after the PV plant goes live.

1. Transformer too small for real-world overproduction

A 100 kW PV system can easily generate 110 to 115 percent of its nominal power on sunny days. That’s normal — panels are often rated above STC and optimized for extra output. But a 125 kVA transformer with no headroom for overloads? That’s a bottleneck.

Symptoms:

• inverter disconnections during peak sun

• transformer overloads and thermal alarms

• higher-than-expected load losses

What to do: if you’re asking should the transformer be larger than the inverter power, the answer is yes — smart oversizing (10 to 15 percent) is an industry standard, not a luxury.

2. Wrong voltage ratio

One of the most frequent field errors. Your inverters output 800 V, but someone orders a 0.4/15.75 kV transformer because “that’s what we always use.” The result? Voltage mismatch, inefficient operation, overheated windings, and inverter faults.

Fix: always verify your inverter AC output. SMA CORE2 and SolarEdge SE100K require 0.8/15.75 kV, not 0.4 kV.

3. No resilience to harmonics

PV inverters generate non-sinusoidal current. THDi levels can easily hit 8 to 10 percent, especially at partial load. Standard transformers rated for <3 percent THDi cannot handle this distortion.

Consequences:

• overheating of core and windings

• higher iron and copper losses

• shorter insulation life span

What to look for: choose a PV-specific transformer with low-loss core material, reinforced windings, and thermal headroom for harmonics.

4. Ignoring the short-circuit level of the MV grid

Designers focus on transformer size and ratio but forget to check short-circuit levels at the point of connection. If the MV grid can deliver 16 to 20 kA and your transformer is only rated for 12.5 kA, it may fail on the first switching surge.

Risk: winding deformation or insulation breakdown due to undervalued withstand strength.

Pro tip: always ask your DSO for fault level data and confirm that your transformer’s mechanical and dielectric specs match.

5. No voltage regulation on the primary side

MV grid voltage is not a constant. It fluctuates — especially in regions with high renewable penetration. If your transformer has no primary-side regulation taps (±2 x 2.5 percent), matching inverter output to grid voltage becomes guesswork. Inverters do not play well with guesswork.

Outcome: inverters disconnect due to overvoltage, poor power quality, rejected compliance tests.

Recommendation: voltage regulation on the MV side is low-cost insurance for long-term grid compliance and uptime.

What to verify before you switch on your PV transformer

• Is the transformer rated with enough margin for real-world peaks?

• Is the voltage ratio compatible with the actual inverter output?

• Can the core and windings handle high THDi?

• Does the withstand rating match the fault level of the MV grid?

• Is there voltage regulation on the MV side?

Because a PV transformer that looks fine on paper can fail in real life by week one. And instead of ROI, you’re looking at RMA.

Dry or oil transformer? What pays off — in the field, in a container, or inside a facility

If there is one question that keeps coming up in PV investment discussions, it is this one: “Should I go with a dry or an oil-immersed transformer for my solar farm?” It sounds simple enough. But the answer depends on many variables — and what seems cheaper at first is not always better in the long run.

Although datasheets for both technologies may look similar, real-life working conditions tell a different story. Ambient temperature, humidity, installation location, cooling capacity, and daily load profile all shape performance. And the wrong choice here? It will show up not on day one, but in year two — when your inverters start to complain.

Oil-immersed transformer — the workhorse of containerized and field-mounted PV

Let’s begin with the classic solution: the ONAN (Oil Natural Air Natural) transformer. This is the most common choice for containerized substations and pole-mounted systems used in open-air PV farms.

Why it works:

• Superior cooling performance — the oil bath stabilizes temperature during sustained output

• Better tolerance to overloads — ideal for high midday peaks

• Lower cost at higher power levels — especially above 160 kVA

• Greater harmonic resilience — oil-immersed cores handle non-linear loads more effectively

An oil transformer is a long-term, outdoor-ready solution, especially in regions with wide temperature swings from winter to summer. It fits perfectly in prefabricated container stations, ensures galvanic isolation, and allows for relatively easy servicing.

Field example:
A 150 kW ground-mounted PV installation using SMA CORE2 inverters (800 V AC) was paired with a 200 kVA ONAN transformer, 0.8/15.75 kV ratio, insulation class H. After two full seasons, the system remained stable, cool, and fully compliant — no shutdowns, no alarms, no complaints.

Dry-type transformer — clean, quiet, and safe for indoor solar systems

The dry-type resin-insulated transformer (AN) is the go-to choice when the substation is located inside a building — a warehouse, a manufacturing hall, or a commercial facility with rooftop PV.

Key advantages:

• No oil, no risk of leakage — no containment basin needed

• Environmental safety — easier to pass fire safety inspections

• Lower noise levels — typically 50 to 55 dB, ideal near offices or equipment

• Compact footprint — can be installed in technical rooms with limited space

However, dry transformers are not perfect. They do not handle overloads as well, are more sensitive to humidity, and rely entirely on passive cooling, which can be insufficient in higher power classes unless additional ventilation is installed.

Case study:
A rooftop PV system of 100 kW on a production facility used a 125 kVA dry-type transformer, 0.4/20 kV. Thanks to the quiet operation and lack of oil, the unit was installed just a few meters from occupied office space, with no special fire separation required. The result? Fast commissioning and zero complaints from facility management.

Oil or dry? Choose based on where it lives

Here is how to compare the two, not on paper — but where they will actually operate:

• Installation site
  Oil transformer: outdoors, in container stations
  Dry transformer: indoors, in technical rooms or warehouses

• Cooling performance
  Oil transformer: very efficient, natural circulation
  Dry transformer: moderate, passive cooling only

• Overload tolerance
  Oil transformer: high
  Dry transformer: medium

• Containment needs
  Oil transformer: yes — spill basin or protective barrier
  Dry transformer: none

• Noise levels
  Oil transformer: 60 to 65 dB
  Dry transformer: 50 to 55 dB

• Humidity resistance
  Oil transformer: high
  Dry transformer: lower

• Cost above 160 kVA
  Oil transformer: lower
  Dry transformer: higher

Don’t ask “which is better” — ask “where will it work?”

If your PV installation is located in an open field or a prefabricated container substation, an oil-immersed transformer is the better option. It offers flexibility, strength, and better thermal performance.

If you are building inside a facility or near office areas, and environmental or acoustic limits are a factor, then a dry-type transformer is often the only viable solution.

Both have their place. What matters is selecting the right one for your project’s specific context, not just what’s in stock.

A transformer is a strategic choice — not just an electrical detail

A transformer may not be the most visible part of your PV system. But it is one of the most consequential. It affects energy quality, uptime, compliance with the grid operator, inverter durability, and — ultimately — the financial performance of your investment.

Whether you are designing a 50 kW micro-installation or scaling up to a 150 kW rooftop or ground-mounted PV plant, choosing the right transformer is a decision that pays off for years. It is not just about matching ratings. It is about building a system that works — every day, every season, with zero surprises.

At Energeks, we work with designers, installers, and investors across Europe who want smart, field-tested energy solutions — not catalog copy.

If you want to:

• consult a transformer selection with one of our engineers

• check the availability of PV-ready dry or oil models

• compare setups for rooftop, field, or container-based stations

visit our current offering here:
🔗 energeks.com/offer

And if you value honest engineering stories, real-life case studies, and technical wisdom that goes beyond datasheets — we’d love to connect with you on LinkedIn.

🔗 Follow Energeks on LinkedIn

Let’s keep building solar the right way — with focus, care, and a long-term mindset.

Thank you for reading. If you found this helpful, feel free to share it or reach out.
We’re always happy to exchange ideas with those who treat energy like it matters.

Sources:

C57.110-2018 - IEEE “Recommended Practice for Establishing Liquid-Immersed and Dry-Type Power and Distribution Transformer Capability When Supplying Nonsinusoidal Load Currents”

NREL.GOV: Inverters: A Pivotal Role in PV Generated Electricity

IEC 60076-1:2011, Power transformers - Part 1: General

Photo Cover: Trinh Tran pexels/191284110-14613940

How gas laws help understand DGA and predict problems before smoke appears (literally).

Dive into a world where gas tells the truth about the condition of multimillion-dollar investments. Discover the laws that are neither magic nor art—but pure physics.

If you work with transformer diagnostics, design substations, or manage energy infrastructure, understanding the basic gas laws can transform your approach to DGA—from intuitive to scientifically precise.

And that difference can save millions—not through "cost cutting" but through more accurate technical decisions.

Why are we talking about gas laws?

DGA (Dissolved Gas Analysis) is more than just “gut feeling and belief.” It’s the analysis of gases dissolved in transformer oil that can detect microscopic changes before a failure occurs.

But to truly understand what these gases are telling us, it’s worth starting with the physical laws that govern their behavior.

The ideal gas is not a myth. Even though reality is more complex, the ideal gas law equations provide a starting point for understanding diffusion, partial pressure, and equilibrium in the oil–gas system.

What exactly is Dissolved Gas Analysis (DGA)?

Dissolved Gas Analysis, or DGA, is a diagnostic method used in oil-immersed transformers. Its goal is to detect trace amounts of gases produced by thermal or electrical faults.

These gases dissolve in the insulating oil and serve as “fingerprints” of different types of degradation—before anything becomes visible to the naked eye.

Which gases are analyzed in DGA?

The most commonly monitored are seven key gases:

Hydrogen (H₂) – indicates early partial discharges and corona,

Carbon monoxide (CO;)
and carbon dioxide (CO₂) – linked to the degradation of insulating paper,

Methane (CH₄);
and ethane (C₂H₆) – signs of oil overheating,

Ethylene (C₂H₄) – higher temperatures, often associated with hot spots,

Acetylene (C₂H₂) – a marker of electrical arcing (the most dangerous type of fault).

What are the standards and gas tests?

ASTM D3612 is an international standard defining methods for extracting and measuring gases from transformer oil. It is complemented by standards like IEC 60567 and IEC 60599, which classify fault types based on gas ratios.

There is also frequent mention of the “three gas tests” in DGA:

• Gas ratio test (Rogers Ratio or Dornenburg) – comparing ratios of selected gases,

• Duval Triangle – a visual method for classifying faults based on three dominant gases,

• Threshold test – assessing whether the concentration of a specific gas exceeds defined alarm limits.

1. The ideal gas law – the foundation of it all

In the world of transformers, where precision can mean millions, the ideal gas law is not just a school formula—it is the foundation upon which the entire logic of Dissolved Gas Analysis (DGA) is built.

The state equation:

PV = nRT

can be treated as the mathematical DNA of gas behavior inside a transformer. And although a transformer is not a vacuum flask in a lab, its interior—especially the oil–gas system—operates according to the same physical principles.

What do the symbols mean?

P – gas pressure: how strongly the gas "pushes" against its surroundings.

In a transformer, this refers to the partial pressure of individual gases, either dissolved or above the oil surface.

V – the volume the gas occupies. Even when gases are dissolved in oil.

Their molar volume plays a role when estimating the amount of gas produced.

n – number of moles of gas.

This is key to understanding how much hydrogen, methane, acetylene, or carbon oxides were generated in a reaction.

R – the gas constant. Constant, yet not to be ignored.

A universal value that connects all variables into one logical framework.

T – temperature. Often non-uniform in transformers.

"Hot spots" can locally reach up to 200°C.

How does it work in practice?

Let’s assume a microscopic amount of acetylene forms due to a short circuit. Measuring its concentration in the oil is one thing. But only by knowing the temperature in the affected area and the pressure conditions can we calculate how much gas actually formed.

More importantly—does the amount indicate temporary overheating, or long-term degradation of cellulose?

The ideal gas equation lets us "go back in time"—drawing conclusions about causes based on the effects, i.e., the detected gases.

The transformer as a chemical reactor

Think of a transformer as a closed system, where every change in temperature or volume affects the state of gases.

Overheating increases T, which—if the volume is constant—increases P.

That’s why gas measurements must be correlated with temperature data. Without that, interpreting DGA would be like forecasting the weather by looking at clouds—too many unknowns.

2. Henry: how much does a gas “like” to dissolve?

Imagine a cold Coca-Cola straight from the fridge.

You open it and hear a hiss—that’s carbon dioxide escaping from the liquid. Now leave that same bottle in the sun. The result? The gas escapes faster, and the drink goes flat.

Exactly the same mechanism works in transformers. It’s governed by Henry’s law, one of the most underestimated yet essential phenomena in DGA interpretation.

What does Henry’s law say?

In its simplest form:

C = kH ⋅ P

C – concentration of gas dissolved in the liquid (mol/m³)
kH – Henry’s constant, depending on gas type and temperature
P – partial pressure of the gas above the liquid

In practice, this means that the higher the gas pressure, the more will dissolve in the oil. But! That’s only half the story—because Henry’s constant decreases with temperature, meaning the warmer it gets, the less gas can remain in the liquid.

How does this work in a transformer?

Imagine local overheating of cellulose insulation—CO and CO₂ are generated. These gases partly dissolve in oil and partly rise into the headspace. If the transformer’s temperature increases even slightly, the oil’s capacity to retain gas drops. As a result, more CO escapes into the “head,” and its concentration in the oil seemingly decreases—even though the degradation process may be intensifying.

Caution! This is a trap in interpretation. A lack of gas doesn’t always mean no damage—it might simply mean the gas has already escaped.

Every gas “prefers” something different

Different gases have different kH values:

• Hydrogen (H₂) – very poorly soluble, quickly escapes from oil

• Carbon dioxide (CO₂) – relatively soluble, “sticks around” longer

• Acetylene (C₂H₂) – short-lived, but detectable in arc faults

  Knowing these properties allows engineers to better assess whether a gas has just formed or if the sampling system recorded it with a delay.

Interpretation with physics in the background

In day-to-day DGA practice, it’s not only about knowing threshold values, but also understanding the physical context:

• Oil temperature – was it stable in recent days?

• Time since the event – did the gas have time to dissolve or separate?

• Do online readings differ from lab samples?

Henry’s law doesn’t give a ready-made answer, but it shows that gas isn’t just a number—it’s a physical phenomenon reacting to a dynamic environment. And that understanding builds an edge in transformer condition analysis.

3. What happens when temperature rises?

Temperature is not just the background to processes inside a transformer—it’s their primary catalyst. It determines whether chemical reactions ignite like a spark or remain dormant. For DGA interpretation, understanding the role of temperature is fundamental. It directly affects how many gases are formed, how quickly they move, and how long they remain dissolved in oil.

Heat as the trigger for gas formation

Inside the transformer, temperature conditions vary. Of critical importance are so-called hot spots—local points of elevated temperature, sometimes exceeding 200°C. This is where:

• Pyrolysis of cellulose insulation occurs (producing CO, CO₂)

• Thermal breakdown of oil takes place (producing CH₄, C₂H₆)

• Ethylene and acetylene form at extreme temperatures (above 500°C in arcing faults)

Rising temperature not only initiates gas-forming processes but also amplifies their intensity.

According to the Arrhenius equation:

k = A ⋅ e − Ea/RT

where:
k – reaction rate
A – frequency factor
Ea – activation energy
R – gas constant
T – temperature in Kelvin

The higher the temperature, the smaller the value of the exponential denominator, hence the faster the reaction. This means that even a slight increase in temperature (e.g., from 120 to 150°C) can exponentially accelerate gas production.

Temperature vs. gas solubility

High temperature not only creates gas—it also affects its behavior in oil. Back to Henry’s law: higher temperature means lower gas solubility in liquids. In practice, when the system heats up:

• More gas escapes from the oil to the headspace

• The dissolved gas concentration decreases—which may falsely suggest the “situation is improving”

• Partial pressure above the liquid increases—affecting further secondary reactions

Interpretation pitfalls

DGA performed while the transformer is operating (e.g., on a hot day) can yield different results than the same analysis done after cooling. That’s why each reading should be compared with temperature data: from online sensors, thermal history, or ideally—from hot spot temperature estimates (HST).

Without this, we risk a misinterpretation:

• Low gas concentration at high temperature does not necessarily mean no risk

• Sudden gas increase after cooling may reveal previously hidden processes

  ---

Relationships worth knowing

Effective DGA diagnostics requires knowing not only standards, but also physical interdependencies:

• Gas generation rate – increases exponentially with temperature

• Solubility – decreases with temperature

• Partial pressure – rises with temperature at constant volume

These three phenomena together create a dynamic system that cannot be understood solely through an alarm threshold table.

Only by accounting for the role of temperature can we see the full picture and anticipate possible fault development scenarios.

4. Dalton and the gas mixture

Unlike in a laboratory, inside a transformer we never deal with just one gas. Degradation processes produce a whole spectrum of compounds—from light hydrogen to complex hydrocarbons.

That’s why, instead of analyzing each gas in isolation, it’s important to understand how they behave collectively. Here, Dalton’s law becomes one of the key gas laws in the context of DGA.

What does Dalton’s law say?

Ptotal = P1 + P2+ ⋯ + Pn

This means that the total pressure of the gas above a liquid (such as in the transformer headspace) is the sum of the partial pressures of all its components.

Each gas contributes its “share” to the total pressure—proportional to the number of moles present in the mixture.

Why is this important? Because in a transformer, it’s this very gas mixture—and its changing proportions—that reveals the type and intensity of the fault.

The mixture as a fault fingerprint

By analyzing the gas mixture composition, we can identify dominant degradation mechanisms:

• A predominance of hydrogen (H₂) and methane (CH₄) suggests partial discharges,

• The presence of acetylene (C₂H₂) is a clear sign of arcing,

• High levels of CO and CO₂ indicate cellulose paper insulation degradation,

• Increased ethylene (C₂H₄) is typical for overheating.

Dalton’s law allows us to model how partial pressures vary over time.

This in turn helps detect whether any particular gas is increasing rapidly—potentially indicating an escalation of the fault before it becomes apparent in summary charts..

Gas escape dynamics

Each gas in the mixture has a different solubility coefficient (see Henry’s law), but Dalton’s law determines which gas escapes the liquid first.

Those with higher partial pressures (e.g., hydrogen) will reach equilibrium between the oil and gas phases faster—and disappear from the system more quickly.

This explains why laboratory samples don’t always reflect the full spectrum of gases that were present moments earlier.

The absence of a gas in the sample doesn’t necessarily mean it’s no longer present in the transformer—it may simply have diffused or been vented out earlier.

IInterpreting gas ratio changes

In practice, diagnostics often rely on gas ratio tests, such as the Dornenburg or Rogers methods. It is thanks to Dalton’s law that these methods make sense: they allow us to evaluate not only how much gas formed, but how the various components relate to one another.

A noticeable shift in the ratio of, say, C₂H₂ to CH₄ may indicate a change in the fault type—e.g., from overheating to arcing.

If, on the other hand, gas ratios remain stable while concentrations increase evenly—this suggests the same fault is simply progressing.

Practical conclusions

• Don’t analyze gases in isolation—the context of the mixture matters,

• Watch for ratio changes—they're more revealing than absolute values,

• If a gas disappears from the sample—check the pressure, temperature, and sampling history. It may have simply left the system.

Dalton’s law offers a holistic view of the gas system—not just as individual indicators, but as a dynamic system where every change has causes and consequences.

5. Diffusion – gas never sleeps

Gases in a transformer are not passive indicators of faults. They are active, mobile particles that—even after the fault processes stop—continue to “live their own lives”—slowly spreading through the system, reaching equilibrium, vanishing from samples or appearing where they weren’t before. This is governed by diffusion, precisely described by Fick’s first law.

What does Fick’s law say?

J = −D ⋅ dc/dx

Where:
J – diffusive flux (amount of moles moving through a surface per time unit),
D – diffusion coefficient (specific for each gas and medium),
dc/dx – concentration gradient (difference in gas concentration across space)

In short: gas moves from where there's more of it to where there's less—and the greater the difference, the faster the movement.

What does this mean in practice?

There is no such thing as a “constant gas composition” in a transformer—especially in systems with a large oil volume. Even if the fault occurs in a single spot (e.g., a local short), the generated gases will slowly spread throughout the entire system.

If a sample is taken from a different location than the fault origin—the results may be underestimated.

If analysis is delayed—the gas may have already escaped or diffused, blurring the alarm signal.

The importance of time – DGA isn’t always real-time

What we measure in a sample is a snapshot of the system at that moment. But diffusion means the system is constantly changing—even after the gas-forming reactions have ceased. In practice, this leads to several key recommendations:

• A measurement taken immediately after the fault gives a different profile than one taken a week later,

• The smaller the transformer, the faster diffusion equalizes concentrations,

• Online systems allow for dynamic tracking—classic lab analysis shows only the “averaged effect.”

Why does diffusion matter for interpretation?

Imagine a transformer where ethylene (C₂H₄) was generated due to overheating. As soon as the temperature drops, the gas-forming process stops—but the ethylene continues to move through the oil. If sampling is delayed, the gas will already be partially dispersed or even vented into the headspace.

The result? The measurement shows a lower concentration than what actually existed at the moment of the fault.

The same goes for hydrogen—very light, poorly soluble, and prone to rapid diffusion. If the measurement is not taken in time, hydrogen may be incorrectly interpreted as absent—even though it was one of the first fault indicators.

Practical conclusions

• Interpret DGA considering the time and location of the sample,

• Use online systems wherever possible—they give a more complete picture of the dynamics,

• Understand that the absence of gas doesn’t always mean no issue—it might be the result of diffusion or escape.

Fick’s law helps us better understand how the system “cleans itself” of gases—and how quickly fault information can fade.

It’s physics at work—continuously—even when everything seems to have returned to normal.

Let’s interpret the data that matters

In a world where the speed of decision-making matters more than the number of decisions made, access to reliable data becomes one of the most important advantages. But data alone is not enough.

Only proper interpretation—based on physics, process understanding, and real-world experience—creates value that allows us to protect, optimize, and plan the future of power infrastructure.

That’s why today, instead of asking whether DGA “shows something,” we ask: what exactly does it show, and how can we act smarter because of it?

At Energeks, we believe that every network device—from transformers to energy storage—deserves the same level of precision as the most advanced IT systems. Diagnostics doesn't have to be a guessing game—it can be science-based, predictable, and transparent. And that’s precisely what understanding gas laws enables.

As one of Europe’s leading suppliers of medium-voltage transformers and transformer stations, we support our clients daily in making decisions with long-term technical, financial, and environmental consequences.

That’s why our portfolio continues to grow:
➤ Modern transformers and complete transformer substations
➤ Energy storage systems, inverters, and EV charging infrastructure
➤ Technologies for photovoltaic farms and the renewable energy sector—efficient, safe, and future-ready

We proudly support investors, designers, municipalities, and technology integrators in creating solutions that work not only today—but also tomorrow.

Technology is the tool. People and values are the direction.

Get in touch with us if you’d like to discuss your challenge—we’re here to share our experience and find the best solutions together.

And if you’d like to become part of our knowledge and inspiration network—join us:
➤ Connect with the Energeks community on LinkedIn

Thank you for being with us—together we are building an infrastructure that not only works, but… learns, adapts, and grows alongside you.

Source:
Transformers Magazine vol.12

Silence. Calm. Safety.
A transformer that doesn’t smell of oil, doesn’t drip onto the floor, and doesn’t demand special maintenance rituals. A dry-type transformer is not an alternative. It’s a decision rooted in logic, in the demands of modern infrastructure, and in the awareness of today’s investors.

Who is this article for?
For designers, integrators, operators, and investors looking for reliable solutions in demanding environments — without compromise.

What will you find below?

• Why dry-type transformers win in so many projects

• Where oil-based technology can’t deliver

• What you gain as an investor

• A list of buildings where resin has replaced oil

Estimated reading time: 5 minutes

Reason 1: A dry-type transformer where oil fails

Picture a space where air doesn’t circulate freely, where fans have limited reach, and access to equipment is restricted. A multi-kilometer subway tunnel. A historic church with frescoes on the ceiling. A server room buried in the basement of a class A+ office building. All of these places share one critical challenge: zero tolerance for risk.

Add to that a relative humidity exceeding 80%, dust or suspended particles in the air, plus legal restrictions related to fire protection and a lack of space for oil-based safety systems. In such environments, is an oil-immersed transformer — requiring leak detection systems, retention tanks, and carefully managed ventilation — really the best choice?

Not always.

Oil transformer technology has its niche — primarily in open-air high-voltage substations (GPZ) or wind farms, where space and cooling conditions are favorable. In places where fire protection systems per PN-EN 61936-1 can be implemented, and a potential oil leak poses no threat to people or the environment.

But in many real-world projects — from hospitals and metro lines to heritage buildings and modern residential complexes — priorities shift:

• Human and asset safety — especially where vulnerable populations or crowds are present. Even the smallest risk of oil ignition is unacceptable.

• High reliability with no servicing — for locations that are difficult or impossible to access, long-term maintenance-free operation is essential.

• Limited space and ventilation — where cooling systems can’t be installed or compliance with oil transformer norms is simply not possible.

• Aggressive environmental conditions — like steam, salt (in coastal areas), or chemicals (in industrial zones) that can degrade traditional insulation systems.

This is where the dry-type transformer with resin insulation steps in. It doesn’t need oil-based cooling. It eliminates leak risks. It doesn’t require retention tanks. And it performs in environments where other technologies fail. Its sealed, durable design and low maintenance requirements make it the go-to engineering choice wherever traditional oil-filled models can’t keep up.

Reason 2: A dry-type transformer design built for advantage

In the engineering world, it’s not just about efficiency — it’s about reliability and adaptability. A dry-type transformer is like an athlete ready to compete without warming up — compact, focused, and ready to deliver from the start. Its biggest strength lies in a resin-based design that removes many of the typical weak points found in oil-filled units.

What does “dry” really mean?
It’s more than just oil-free.

A dry-type transformer uses no liquid insulation. Instead, it relies on epoxy or polyester resin applied directly to the windings. This not only eliminates the risk of fire — it redefines the way installations are planned. No retention basins, no leak detection systems, no emergency procedures needed.

In practice, this means:

• No leaks — even in the event of mechanical damage

• No vapor emissions — so no toxic fumes in enclosed spaces

• No fire hazard from fluids — lowering fire protection requirements in the facility

A technology that breathes easy

Dry transformer windings are typically made from copper or aluminum wire, then vacuum-impregnated or cast with layers of resin (VPI – Vacuum Pressure Impregnation or CRT – Cast Resin Technology). The result is a build that is:

• Moisture-resistant (up to 100% relative humidity)

• Mechanically robust — won’t crack or deform

• Electrically stable — with insulation strength up to 20–36 kV

Special versions are also available with anti-corrosion protection or electrostatic shielding, ideal for industrial environments with high salt or dust levels.

Silence that matters

Thanks to their compact build and vibration-dampening resin, dry transformers are significantly quieter than their oil-based counterparts. Noise levels typically stay below 50–60 dB, making them suitable for installations near people — in schools, offices, hospitals, or even museums.

This is a design that lets your building breathe — without noise, without oil smells, and without worries about system tightness.

A lightweight performer for demanding tasks

With a compact design and no need for external tanks or auxiliary systems, dry-type transformers weigh 20–30% less than oil transformers of the same rating. That’s a real advantage when installing on upper floors, inside vertical shafts, or in prefabricated energy containers.

Installation times can also be reduced by up to 40%, and fire safety approvals often become unnecessary.

Reason 3: What do you really gain?

For an investor, the key question isn’t “how much does it cost?” but rather “what does it give me?” A dry-type transformer doesn’t just align with modern infrastructure design philosophies — it increases your investment’s value, improves operational conditions, and elevates the technological appeal of the entire facility.

1. You gain greater design flexibility

A dry-type transformer doesn’t require special rooms with oil sumps or expensive leak detection systems. That gives you complete freedom in placement — it can be installed in an office basement, a school, a hospital, or beneath a stadium grandstand. This opens entirely new possibilities in how technical and usable spaces are arranged.

For a developer, that means: more square meters for lease or sale. For a designer: easier integration with existing infrastructure.

2. You gain a time advantage

Time is a resource you can’t get back. A dry-type transformer is a plug & power device — it doesn’t need extended startup processes, specialized leak tests, or long waits for fire protection approval.

In practice, that means you can:

• bring your facility online faster,

• shorten decision and commissioning chains,

• ensure energy continuity during the finishing stages.

The sooner your transformer is installed, the sooner you can launch what comes next — production, leasing, or customer service.

3. You gain safety as a selling point

In hospitals, shopping centers, universities, or metro systems, the absence of oil leak risks and enhanced fire resistance are not just regulatory issues. They’re real advantages in the eyes of users and business partners.

Developers who use dry-type transformers can proudly highlight:

• compliance with the highest safety standards,

• the building’s eco-friendly profile (no insulating liquids, no soil contamination risk),

• safe performance even under heavy load.

This translates to greater customer trust, a stronger reputation, and easier certification in systems like BREEAM or LEED.

4. You gain future-ready technology

A dry-type transformer is not a cheaper workaround — it’s a leap forward in technology. Especially in versions with online monitoring, humidity and temperature sensors, or digital communication.

As an investor, this lets you:

• build infrastructure ready for smart energy management (Smart Grid),

• integrate with EMS, BMS, or SCADA,

• boost long-term technical value without needing upgrades for years.

This is an investment that doesn’t just meet today’s standards — it anticipates tomorrow’s demands.

5. You gain peace of mind — and that’s priceless

A dry-type transformer runs quietly, reliably, and without needing regular inspections. It doesn’t leak. It doesn’t buzz. It doesn’t require a technician on call.

Thanks to that, you:

• reduce the number of unexpected service calls,

• improve system availability for users (zero downtime),

• focus your time and resources where they matter most — on growing your business, not maintaining equipment.

Operational calm and technical stability — these are the foundations of long-term infrastructure peace of mind.

Reason 4: Where do we install dry-type transformers? Not just underground

Though many designers associate dry-type transformers with installations buried below ground — metro tunnels, stations, underground parking garages — their use goes far beyond technical infrastructure. With their versatile construction, environmental resistance, and refined operation, they’re now found wherever uncompromising reliability and human safety are required.

Public transport – the silent heart of the city

In metro lines, trams, and urban transport hubs, where every square meter matters and delays can paralyze the system, dry-type transformers are the perfect match. They operate close to traction systems, in low-ventilation areas, underground, often in humid and dusty environments.

No oil sumps. No fire risk. Minimal servicing. That’s why urban rail systems around the world are moving away from oil-based solutions in favor of resin-insulated units.

Hospitals – where reliability equals life

In healthcare facilities, downtime means more than financial loss — it can threaten lives. That’s why dry-type transformers are now standard in modern hospitals and clinics. They operate silently, require minimal maintenance, and pose no ignition risk. Most importantly, they can work in direct proximity to people and sensitive medical devices.

They’re an invisible but vital part of hospital infrastructure, keeping equipment stable and letting medical teams focus on patient care.

Shopping malls and A+ office buildings – comfort that sells

In high-end commercial spaces, every aspect of user experience matters: acoustic comfort, safety, clean air, and reliable power. Dry-type transformers meet all these needs. They can be installed in basements, technical floors, or even inside utility walls — quietly, safely, and without the need for fire zones.

For building owners, this means greater rental flexibility, less structural disruption, and better chances of earning green building certifications.

Heritage and sacred buildings – when fire would be a cultural tragedy

In museums, churches, archives, and other heritage sites, every second counts when it comes to fire prevention. Dry-type transformers minimize fire risks at the source — they contain no liquids, so they can’t spill or ignite.

Their compactness and quiet performance also mean they can be discreetly installed without interfering with the structure. This is technology that protects the past while seamlessly coexisting with the present.

Industrial sites – where conditions don’t forgive mistakes

In chemical plants, processing facilities, steelworks, or manufacturing halls, transformer conditions can be extreme: moisture, heat, dust, corrosive substances. An industrial-grade dry-type transformer — with shielding, anti-corrosion coatings, and extra protections — operates where others would fail.

It’s an investment that keeps production moving and ensures continuous power even in the harshest environments.

A dry-type transformer is neither a trend nor a compromise. It’s a conscious decision made by forward-thinking investors who know that not every space should smell like oil — and not every project should be constrained by outdated limitations.

Need a transformer for a unique site? You’re in the right place — we’ll match you with the right technology that works from the very first start-up.

Reason 5: A pillar of modern installations

It doesn’t make noise, doesn’t seek attention, and doesn’t show up in the maintenance log every week. A dry-type transformer works silently in the background, but it’s its reliability that determines whether a facility runs without interruptions. In a world where every second of uptime matters, this type of transformer is like a seasoned athlete — strong, resilient, and invisible to the end user.

Stability you can build on

Silent doesn’t mean passive. A dry-type transformer is an active part of the infrastructure, operating non-stop for years without the need to refill cooling media, without the risk of leaks, and without making noise. Its design, based on resin insulation with high dielectric and thermal strength, allows it to run for decades without intervention — even in challenging environments.

That means:

• no downtime from cooling system failures

• no need to replace or regenerate oil

• minimal maintenance limited to visual checks and insulation resistance testing

As an investor, you’re not just buying a device — you’re buying peace of mind for years, knowing that even if you forget about the transformer, it will still do its job.

Ready to go – right away

Unlike oil-based systems, which often require long prep work after installation — including leak testing, oil filling, and safety system verification — a dry-type transformer is ready to operate immediately after connection. It’s the perfect solution for fast-track projects where timelines are measured in days, not weeks.

Thanks to its compact and sealed design, it can be transported and installed without risk of internal damage — eliminating last-minute surprises during commissioning.

An acoustic edge – more comfort, less noise

In today’s installations, where the transformer is often located close to people — in offices, schools, hospitals, or universities — every decibel counts. Dry-type transformers are known for their exceptionally low noise levels, often below 50 dB(A), making them leaders in their category for acoustic comfort.

This translates to:

• better work and learning environments, free from hums and vibrations

• more design flexibility — no need for special soundproof enclosures

• a better user experience, which positively affects building perception

It runs nonstop, because it’s built not to fail

Investors who choose dry-type transformers often point to one standout experience: the silence that brings reassurance. It’s not just the lack of noise — it’s the absence of stress from servicing, permissions, inspections, and unplanned shutdowns.

This is a unit that simply runs — whether you’re powering a shopping mall, hospital, or metro line. It doesn’t demand attention. It doesn’t trigger alerts. It delivers energy — and stays out of sight.

Curious why the dry-type transformer is gaining ground in safety and environmental resilience? Check out this article too:
👉 Dry-type transformer for indoor applications: Safety and flexibility

Dry-type transformer. The future already in operation

At Energeks, we believe the best decisions are those that anticipate problems before they arise. That’s why we deliver solutions that not only meet today’s challenges, but lay the groundwork for the future of energy systems — calm, safe, and resilient to change.

If you’re designing infrastructure that must perform reliably regardless of location, environmental conditions, or service availability, the dry-type transformer is your ally. From hospitals and malls to metro systems and historic monasteries — its job isn’t to blink with LEDs, but to quietly ensure continuity and stability, day after day, for decades. See what we can offer.

Every one of our projects is a blend of engineering expertise, real-world implementation experience, and listening to what users actually need — from engineers to facility operators.

Want to talk about applying dry-type transformers in your project? Or maybe exchange insights on urban or industrial power distribution?

Join our community on LinkedIn — where we share knowledge, implementation stories, and practical tips to help you build systems that stand up to time, weather, and emergencies.

At Energeks, we don’t just design equipment. We create a future people want to help build. And we’re here to help you make it real — no matter what stage your project is in.

Sources:

• IEEE Xplore – Dry-Type Power Transformers: Design, Operation, and Performance

• ScienceDirect – Evaluation of Thermal Performance in Cast-Resin Dry-Type Transformers

• MDPI Energies – Fire Performance Assessment of Dry-Type Transformers for Urban Applications

Energy that doesn’t rely on the wind, the sun, or the time of day. This is geothermal energy—one of the most stable yet underestimated renewable sources. Today, we no longer ask if we can scale it up.

The real question is: how fast can we do it?

For years, geothermal energy has remained in the shadow of flashier technologies—solar panels gleaming in the sun and wind turbines majestically spinning on the horizon. And yet, geothermal may prove to be the most valuable piece of the puzzle. It doesn’t stop working, doesn’t require energy storage, and isn’t affected by weather conditions. If we want a 100% renewable energy future, we must invest in it.

The technology is ready. Enhanced Geothermal Systems (EGS) are unlocking new possibilities. We’re talking about a breakthrough that could make geothermal a cornerstone of the global energy transition. Scalable, renewable, and reliable—exactly what we need in a world that can no longer afford energy compromises.

Reading time: 4.5 minutes.

What is geothermal energy and how does It work?

Geothermal energy is heat stored deep within the Earth. Where does it come from? It is a remnant of planetary formation and the continuous decay of radioactive elements within the Earth's crust.

This is not a new invention. As early as 1904, Italian engineer Piero Ginori Conti built the first geothermal power plant in Larderello. Today, more than 90 countries harness geothermal energy, with a total installed capacity exceeding 16 GW—enough to power 16 million households.

Geothermal power plants operate much like an espresso machine: hot water and steam from beneath the Earth’s surface drive turbines to generate electricity. But now, we’re taking it a step further—with AI and cutting-edge technologies, we can extract heat even from magma chambers.

In the following sections, we will explore global innovations and groundbreaking technologies redefining how humanity approaches geothermal energy. We’ll analyze the latest advancements, compare the strategies of industry leaders, and examine what the future holds for this rapidly evolving sector.

Breakthrough in Nevada – How Fervo energy is transforming geothermal energy

Just a few years ago, Enhanced Geothermal Systems (EGS) were considered a futuristic concept, requiring years of research and massive investments. Today, however, this energy model is becoming a reality. Fervo Energy, a U.S.-based company specializing in advanced geothermal systems, has proven that deep-earth energy can be efficient, scalable, and cost-competitive.

Fervo Nevada, Photo Credit: Fervo Energy

25 MW of Power – The first true success of EGS

In 2023, Fervo Energy launched one of the world’s first EGS installations in Nevada, with a capacity of 25 MW. This groundbreaking project currently powers around 20,000 homes. But this is just the beginning—engineers are already working on additional wells that could increase the plant’s capacity several times over.

What sets this project apart from traditional geothermal power plants? The key lies in cutting-edge technology—inspired by the oil and gas industry. Fervo Energy utilizes advanced horizontal drilling techniques and precise geothermal reservoir stimulation, making it possible to extract heat efficiently even in locations where it was previously considered impossible.

Advantage No. 1 of geothermal over other renewables: STABILITY

• Solar power – great on sunny days, but inefficient at night.

• Wind power – effective, but only when the wind is blowing.

• Geothermal energy? It works 24/7, 365 days a year.

The Fervo Energy plant does not require costly energy storage systems or additional backup power, making it one of the most reliable renewable energy sources available.

Is geothermal energy cost-competitive?

The cost of generating geothermal electricity is still slightly higher than solar or wind power, but it is on a downward trend. Currently, geothermal power costs range from $0.06 to $0.08 per kWh, meaning it is already competing with natural gas ($0.05–$0.07 per kWh).

According to a U.S. Department of Energy report, if drilling efficiency improves by just 30%, the cost of geothermal power could drop to $0.04 per kWh. That would make it cheaper than coal, gas, and even most wind farms.

For comparison:

• Solar power (without energy storage) – $0.03–$0.06 per kWh

• Onshore wind energy – $0.04–$0.07 per kWh

• Natural gas – $0.05–$0.07 per kWh

• Geothermal energy (potential future cost) – $0.04 per kWh

What does this mean in practice? If drilling costs continue to decline, geothermal will become one of the cheapest and most stable renewable energy sources.

Iceland – A Geothermal future laboratory

Iceland is a textbook example of how consistent energy policy and efficient use of natural resources can revolutionize the way a country produces and consumes energy. The volcanic activity of this small nation, home to just over 370,000 people, provides immense heat reserves, which Icelanders have been harnessing for decades to generate electricity and heat their homes. Over 90% of Iceland’s buildings are heated with geothermal energy, and 66% of the country’s electricity comes from the Earth's interior.

Iceland Geothermal Energy, Photo via reykjavikcars.com

How does Iceland utilize its geothermal resurces?

Thanks to its unique geology, Iceland has some of the world’s best geothermal conditions—with over 200 active geothermal systems and more than 600 hot springs scattered across the island. But having the resources is one thing—effectively using them is another.

The key factor behind Iceland’s success is government policy. As early as the 1970s, the Icelandic government strategically invested in geothermal energy as a foundation for energy independence. As a result:

• Over 90% of Icelandic buildings are heated with geothermal energy—the highest percentage in the world.

• 66% of the country’s electricity is generated from geothermal sources, with the remainder coming from hydropower.

• The cost of electricity? On average, just $0.035 per kWh—one of the lowest rates globally.

• Carbon emissions per capita are among the lowest in the developed world, despite Iceland’s harsh climate requiring intensive heating.

  ---

More than just electricity

For Iceland, geothermal energy is not just about power generation—it powers entire industries and daily life:

• District heating – A nationwide network of pipelines delivers hot water to cities and towns, eliminating the need for coal or gas. Reykjavik, the capital, is the largest city in the world heated entirely by geothermal energy.

• Geothermal greenhouses – Icelanders grow fruits and vegetables year-round, despite their harsh Arctic climate. Once heavily reliant on imports, the country now produces tomatoes, bell peppers, and even bananas in geothermal-heated greenhouses.

• Food industry – The drying of fish for export is done using geothermal energy, reducing dependence on fossil fuels.

• Tourism & wellness – The Blue Lagoon, one of the world's most famous geothermal spas, attracts over a million tourists annually. Iceland has turned hot springs into a national brand, developing a wellness tourism industry around geothermal resorts.

• Hydrogen production – Iceland is actively experimenting with using geothermal energy to produce hydrogen, positioning itself as a pioneer in renewable fuel production.

After decades of investment and research, Iceland has become an exporter of geothermal expertise and technology. Icelandic companies such as Mannvit, Reykjavik Geothermal, and HS Orka design geothermal power systems worldwide—from Kenya to Indonesia to California.

Icelandic engineers advise on some of the world's largest geothermal projects, and the government actively promotes geothermal resource management. One example is the United Nations University Geothermal Training Program (UNU-GTP), which has been training global geothermal experts since the 1970s, helping develop this energy source in emerging markets.

Iceland is one of the few places in the world where geothermal is not just part of the energy mix—it is the backbone of the country’s energy system. This small, rugged island, shaped by glaciers, volcanoes, and lava fields, has proven that even in extreme conditions, it is possible to build a stable, sustainable energy infrastructure that is virtually free of fossil fuels.

What can the rest of the world learn from Iceland?

Iceland proves that having resources is not enough—there must be a strategy for utilizing them. It was not geology, but energy policy and long-term investments that turned the country into a global leader in geothermal energy.

If other nations follow Iceland’s example—focusing on long-term planning, infrastructure expansion, and financial support—geothermal energy could become one of the key pillars of the global energy transition.

It wasn’t just natural resources or geological luck that led to Iceland’s success—the decisive factors were government commitment and the determination to build a stable, renewable infrastructure. Iceland prioritized a long-term strategy, geothermal subsidies, and extensive research on the efficiency of this energy source.

The result? A cost of $0.035 per kWh—one of the lowest electricity prices in the world. As a result, Iceland has not only eliminated its dependence on fossil fuels but has also become a global leader in exporting geothermal technology.

Iceland vs. the USA – two approaches to geothermal energy

Now let’s compare this with the United States. The USA has the world’s largest geothermal potential, far greater than Iceland, yet geothermal accounts for less than 1% of the country’s electricity production.

For comparison:

• The total geothermal potential in the USA is estimated at over 500 GW—more than the combined capacity of all its renewable energy sources today.

• Currently installed geothermal capacity in the USA is around 3.7 GW, a tiny fraction of its real potential.

• The cost of geothermal energy in the USA ranges from $0.06–0.08 per kWh, slightly higher than in Iceland but still competitive with natural gas.

So why isn’t the USA fully utilizing its geothermal resources?

1. Lack of strategic investments – For decades, geothermal development was neglected in favor of more visible and heavily subsidized technologies like solar and wind power.

2. High upfront costs – Drilling and geothermal infrastructure require large initial investments, which discourages private investors.

3. Lack of a developed transmission network – Geothermal hotspots are concentrated in western states like California, Nevada, and Utah, while the greatest energy demand is on the East Coast and Midwest. Without a modernized grid, even high-efficiency geothermal plants can’t supply distant metropolitan areas.

However, this is starting to change. Thanks to modern Enhanced Geothermal Systems (EGS) and AI-driven drilling optimization, the cost of geothermal electricity in the USA could drop to $0.04 per kWh—making it cheaper than any other renewable energy source.

It’s not about resources, but about approach

Comparing these two countries proves one thing: having resources is not enough—what matters is how you use them. Iceland has consistently invested in geothermal energy for decades, while the USA is only now beginning to take it seriously.

If American EGS projects—such as Fervo Energy’s breakthrough in Nevada—continue to succeed, we could witness a true geothermal revolution in the USA. In the long run, the United States has the potential to become a global leader in geothermal energy, but only if it follows Iceland’s strategic approach.

Geothermal energy in Podhale – an example for all of southern Poland

You don’t have to look far to see how geothermal energy can transform a region’s energy landscape. Podhale is the best example of how a stable, renewable heat source can not only power households but also significantly improve air quality and boost the local economy.

Currently, Geotermia Podhalańska supplies over 400 TJ of heat per year to thousands of buildings—from single-family homes to hotels, guesthouses, and public facilities. This eliminates the need for burning coal and gas, making a massive impact on emissions reduction. It is estimated that this system prevents more than 40,000 tons of CO₂ from being released into the atmosphere every year.

Podhale is one of Poland’s hottest geothermal zones—underground water temperatures reach 80–90°C, making it an ideal energy source for district heating systems. Water is extracted from a depth of several kilometers, used for heating, and then returned to its natural reservoirs, completing a closed-loop cycle. This allows for near-zero consumption of fossil fuels for heating, a crucial advantage in a region that has struggled with severe air pollution for years.

And this is just the beginning.

Photo Credit: Geotermia Podhalańska

Podhale is a pioneer, but geothermal energy shouldn’t stop at Zakopane

90% of Poland’s land area has geothermal potential, yet it remains largely untapped. In southern Poland, the conditions are particularly favorable, offering a massive opportunity for expansion.

• The Carpathians and the Sudetes hold vast geothermal water reserves that could supply cities and villages, reducing coal and gas dependency.

• Kraków, Nowy Sącz, Tarnów, and even Katowice could tap into geothermal energy sources, significantly cutting air pollution in Małopolska and Silesia.

• Smaller towns like Rabka-Zdrój and Krynica-Zdrój could power their sanatoriums and wellness resorts with clean energy from deep underground.

Today, geothermal energy in Poland is still seen as a "technology of the future", even though it’s already a standard in Iceland, Germany, and France. So why should southern Poland continue to wait?

If Poland wants to truly reduce its reliance on fossil fuels, geothermal energy must become a key part of its energy mix—especially in regions with high heat demand. Southern Poland is a perfect candidate for this transition—from major metropolitan areas to mountain towns, where geothermal power could replace expensive, high-emission fuels.

Podhale has proven that it works. Now, it’s time for other regions to follow suit.

What is blocking us? Obstacles to the geothermal revolution

We have the resources, we have the technology, and we have proof of its effectiveness. So why isn’t geothermal energy dominating the global energy mix?

Problem #1: The Cost of Drilling

Extracting energy from deep within the Earth isn’t cheap—at least not at this stage of technological development. Drilling accounts for up to 50% of the total budget of a geothermal investment, with costs ranging from $5 to $10 million per well. The key question is: how can we significantly lower these costs?

Modern drilling techniques inspired by the oil and gas industry might provide the answer. Advanced horizontal drilling methods and enhanced geothermal reservoir stimulation are already improving extraction efficiency. If we increase well productivity by just 30%, the cost of geothermal energy could drop to $0.04 per kWh, making it one of the cheapest renewable energy sources.

Problem #2: Transmission Infrastructure

Geothermal energy is not always found where demand is highest. In the USA, vast geothermal resources are concentrated in the western states—California, Nevada, and Utah—while the highest energy demand is on the East Coast and in the central states.

Without expanding the transmission network, even the most efficient geothermal plants won’t be able to supply distant metropolitan areas. This means not only multi-billion-dollar investments in infrastructure but also years of work to establish new energy connections.

For comparison: Iceland, despite having a much smaller power grid, has consistently expanded its geothermal network, adapting it to local needs. Meanwhile, in the U.S. and Europe, planning new transmission lines can take years, hindered by bureaucracy and a lack of political will.

The Biggest Obstacle #? Capital and Political Decisions

Investors are wary of risk. Geothermal projects require significant upfront investments, with returns taking years to materialize. Compared to solar farms, which can be built within months, geothermal energy demands long-term planning and stable financing.

And what are governments doing? They continue to focus subsidies on wind and solar, even though geothermal energy could perfectly complement these technologies by providing grid stability. In some countries, like Germany, support for geothermal energy is increasing, but it still falls short of the financial backing given to solar and wind power.

How can we change this?

If we want geothermal energy to become a real pillar of the energy transition, we must accelerate the development of EGS technology, lower drilling costs, and expand transmission infrastructure. But most importantly—we must convince investors and governments that a stable renewable energy source is worth every dollar.

This is not a question of "if"—it's a question of "how fast."

Geothermal energy is not the future—it is ready now. The technology works, the first large-scale projects are delivering promising results, and energy production costs are falling. What seemed like an engineering fantasy a decade ago is now shaping the future of global energy transformation.

But are we keeping up with this change?

This is not about technological capability, but about our decisions—political, investment, and strategic. The world faces two choices:

• We can continue pouring billions into intermittent, decentralized energy sources that require expensive storage and backup systems.

• Or we can bet on stability and predictability, using the Earth's natural heat, available 24/7, 365 days a year, for free.

  ---

It's time to change priorities

Currently, more than 70% of global renewable energy investments are directed towards solar and wind power, even though these technologies do not guarantee a continuous energy supply. Meanwhile, geothermal energy, which could solve this issue, receives only a fraction of financial support.

We can no longer ignore this disproportion. Energy stability cannot rely solely on storage systems and grid flexibility – we need sources that operate continuously.

Strategy for the next decade: Scaling up

• Reducing drilling costs – if new drilling technologies lower costs by 30%, geothermal energy will become cheaper than natural gas.

• Expanding transmission infrastructure – without it, even the most efficient geothermal plants won’t be able to supply energy to cities and industries.

• New energy policies – subsidies and support programs should include geothermal energy on an equal footing with other renewables.

• Public and private investments – in countries like Iceland and Germany, governments and energy companies are already recognizing the potential of this technology. The rest of the world should follow their lead.

Each year of delay means billions of dollars poured into solutions that will never provide the stability that geothermal energy can offer. Will we seize this moment before more countries double down on less stable energy sources? The transition won’t happen on its own – it requires courage, long-term planning, and decisive action. But one thing is certain: geothermal energy will no longer stay on the sidelines.

Now, only one thing matters: How fast can we scale it? What about you? How do you see the future of geothermal energy? Share your thoughts!

Sources:

Article Cover Photo: Hellisheiði, Geothermal Plant, CC: Pedro Alvarez/The-Observer via The Guardian

International Energy Agency (IEA) – Geothermal Power Report
🔗 https://www.iea.org/reports/geothermal-power

U.S. Department of Energy (DOE) – The Future of Enhanced Geothermal Systems (EGS)
🔗 https://www.energy.gov/eere/geothermal/enhanced-geothermal-systems

International Geothermal Association (IGA) – Global Geothermal Development Report
🔗 https://www.lovegeothermal.org/

Orkustofnun – National Energy Authority of Iceland – Iceland Geothermal Development
🔗 https://nea.is/geothermal