The most common mistakes when installing a transformer concern the foundation, ventilation, service access, earthing, cable routes, protection systems, fire protection, oil retention and environmental conditions. Most of them can be eliminated at the design stage, before the multi‑tonne device arrives on site and politely refuses to cooperate with the prepared space.

A transformer can operate for decades. It cannot, however, move the foundation, widen the doors or persuade cables to suddenly bend according to the designer's wishes.

At Energeks, we have sold hundreds of transformers.

Our devices go, among other things, to projects supporting the infrastructure of Poland's largest distribution system operators, industrial plants and distributed generation installations.

We know that the most expensive corrections often begin with quite innocent statements:

"The room should be sufficient."

"The ventilation will somehow manage."

"The bushing is only slightly offset."

"Service will fit in somehow."

The problem is that centimetres can later turn into hours of downtime, and underestimated temperature, humidity or device weight can shorten the life of an installation designed for many years of operation.

In this article, we will walk through transformer installation from the ground up, literally.

We will start with the foundation and transport conditions, then check ventilation, temperature, humidity, noise and service access.

We will look at earthing, cable routes, bending radii and protection systems.

Finally, we will organise fire protection, oil retention, documentation and acceptance.

This article is for designers, investors, contractors, site managers and maintenance teams. After reading, you will more easily recognise decisions that look good on the drawing but require additional checking before installation.

Because a good transformer installation does not start with the crane.

It starts with a design that remembers that paper will accept anything, but the transformer already has its own dimensions, weight and opinion on ventilation.

Reading time: 11 min

1. Mistake one: treating the transformer space like ordinary free floor area

On the plan, everything looks tidy.

The transformer rectangle fits in the room. There is a door. There are walls. The clearances look "roughly right". And here begins the first classic.

A transformer does not need only the footprint of its own enclosure. It needs working space, ventilation space, service space, space for cable bending radii, space for safe access and space for the future.

It is a bit like fitting a large wardrobe into a flat. On the plan, the wardrobe fits perfectly. The problem begins when you need to open the doors, pull out a drawer, walk past it with a vacuum cleaner and still not bang your hip on the edge every morning. In power engineering, that "hip" is service, measurements, thermography, cleaning, terminal inspection, access to the nameplate and the ability to replace a component without dismantling half the station.

Manufacturers' documentation often contains specific requirements regarding distances from ventilation openings, walls or other obstacles. Eaton indicates that the required clearances may vary depending on the transformer construction and should be read from the markings and manufacturer's instructions, and in many ventilated devices, clearances at ventilation openings must be maintained.

An innocent design mistake is when someone leaves space "for the dimensions" but does not leave space "for the device's life". Then it turns out that the thermal imaging camera cannot see the critical point, the doors do not open fully, the cables enter at the wrong angle, and the terminals can only be reached with the expression of someone who has just lost a bet with geometry.

The best design does not only solve the question:

will the transformer fit?

It explains how to plan the installation so that the transformer can be safely placed, connected, commissioned, inspected, serviced and, in the future, also replaced…

And since even the best unit does not work forever, it is worth knowing when it pays to refurbish a transformer and when it is more sensible to replace it with a new one. We have devoted a separate article to this topic, which may interest you, dear reader:

Refurbish or replace? Your transformer's last chance!

2. Mistake two: ventilation calculated by intuition, not by thermal losses

A transformer works quietly, but it constantly gives off heat.

No‑load and load losses do not magically disappear into the air. They turn into temperature, and temperature is one of the most patient enemies of insulation.

The most innocent mistake sounds like: "the room is large, so it will be fine."

Not necessarily.

Ventilation in medium‑voltage stations serves primarily to remove heat generated by transformers and other equipment, and to support drying after periods of moisture. At the same time, excessive ventilation can also be a problem, because it can increase the risk of condensation, especially during sudden temperature changes.

MV station ventilation should be maintained at the minimum required level, and ventilation openings should support natural convection, with inlet and outlet arranged so that heat can actually leave the transformer space.

This is important, because many people think of ventilation as a grille in the wall. And the transformer thinks of ventilation as a thermal balance.

If the design does not take into account the transformer's losses, ambient conditions, solar exposure of the enclosure, switchgear operation, possible overload states, local temperature and air flow, the ventilation grille becomes a technical decoration. It looks nice, but does not necessarily do the job.

With dry‑type transformers, the problem is particularly insidious, because the absence of oil can give a false sense of simplicity. Meanwhile, dry transformers also require appropriate cooling conditions, air cleanliness and maintenance of the required clearances. If the openings are obstructed, the air flow path is accidental, and dust accumulates in the room, the device begins to operate in an environment that the designer did not plan, but which designed itself. Only worse.

Good ventilation is not a "bigger hole in the wall". Good ventilation is a conversation between physics, the manufacturer's documentation and the real conditions of the facility.

3. Mistake three: ignoring humidity, condensation and the station's microclimate

Humidity is not a small problem.

It is a problem that puts on an invisible suit and works quietly.

In the design, we often see walls, a roof, doors, grilles, a foundation and the equipment layout. We less often see the microclimate.

That is, what happens in the morning when the temperature changes rapidly.

What happens after heavy rainfall.

What happens in winter when the device is temporarily switched off.

What happens near the sea, industrial plants, fields, roads or areas with high dust levels.

Equipment manufacturers point out that air flow should not cause rapid temperature changes leading to the dew point being reached. In practice, this means that "more air" does not always mean "better".

Sometimes it means "more condensation on components that really do not like condensation" – the designer provides ventilation but does not account for moisture behaviour. The station must breathe, but it must not draw problems inside. Ventilation openings, louvres, baffles, the way switchgear is positioned relative to the transformer, anti‑condensation heating and dust protection are not aesthetic details. They are elements of maintaining the working environment.

For outdoor installations, exposure to sun, wind and precipitation also matters. An enclosure heated in summer acts like a metal thermos, only in a less amusing version. In winter, sudden temperature changes can create conditions for condensation, especially when equipment does not operate with a continuous load.

A well‑designed transformer installation does not fight the weather heroically. It anticipates it. That is a calmer and cheaper strategy.

4. Mistake four: a foundation that is "sufficient" but not for the real weight and operation

The foundation under a transformer is not a podium.

It is an element of the technical system.

It must carry the weight of the device.

It must maintain level.

It must work with the transport and unloading route.

It must enable drainage, earthing, possible liquid retention, cable routing and access to mounting points.

It must also not crack when theory ends and the crane, jack, rollers, trolley and real pressure begin.

An innocent mistake looks like this: the design assumes a load‑bearing capacity, but does not consider the installation process. Or the substrate is designed for a static state, but transient loads during internal transport are not checked. Or the foundation is strong but has incorrect slopes. Or assembly tolerances are not foreseen, and the transformer ends up positioned so that everything works, but every cable connection requires a small prayer to geometry.

For oil‑immersed transformers, there is also the issue of the oil containment basin, tightness, drainage and control of possible leaks. For dry‑type transformers, the stability of the substrate, the absence of excessive vibration transmission and the cleanliness of the surroundings are important. In both cases, the foundation is the first declaration of the project's quality.

Good practice is to design the foundation not only for "the transformer will stand here", but for the entire scenario: delivery, unloading, movement, positioning, connection, commissioning, inspections, service and replacement.

In power engineering, very often the project that wins is not the one that looks most elegant on the drawing. It is the one that gives the installation team the most common sense on site.

5. Mistake five: cable routes designed without respect for bending radii

Power cables are not pasta.

They cannot be "laid somehow" without consequences.

One of the most underestimated mistakes is the incorrect positioning of bushings, cable trenches and cable entry points to the transformer. On the drawing, a shift of 20 cm looks innocent.

In reality, it can mean too small a bending radius, stress on cable terminations, difficult installation, a greater risk of connection errors and poor access for inspection.

The transformer manufacturer specifies the permissible cable entry points, the requirements for space inside the enclosure and the method of making connections. Schneider Electric, in its instructions for dry‑type transformers, indicates, among other things, to use the designated entry areas of the enclosure, to use flexible routing where possible, and to use a calibrated torque wrench for electrical connections.

This is not bureaucracy. This is the mechanics of electrical contact.

A connection tightened too much can damage the component. One tightened too little can heat up. A poorly routed cable can work mechanically where it should be calm. A lack of space for laying the conductors can make the installer fight with the material instead of performing precise work.

An innocent design mistake: "we will put the bushing here because it fits nicely against the wall."

A better question is: "will the cable have its natural path, without stress, without struggle and with access for inspection?"

A well‑designed cable route looks a bit like good choreography. Nothing jerks. Nothing strains. Every movement makes sense.

Power cables are not pasta. ;) If their layout starts to resemble an Italian dinner, it is time to go back to the cable route design. CC: ENERGEKS 2026

6. Mistake six: earthing treated as a formality

Earthing is one of those topics where it is not worth being creative in the wrong sense.

Poorly designed earthing and equipotential bonding can cause problems with safety, protection operation, overvoltages, electromagnetic interference and the reliability of the entire installation. Yet in many projects, the topic is treated as the last item on the list: "earth in accordance with the standard."

Only the transformer does not read such mental shortcuts. It works in a specific network system, with a specific short‑circuit impedance, a specific neutral point, specific switchgear, specific fault conditions and specific shock protection.

IEC 61936‑1:2021 concerns the design and execution of power installations above 1 kV AC and indicates requirements to ensure safety and proper operation of the installation according to its intended purpose. This is a good example of systems thinking: the transformer is not a lonely island, but an element of an installation that should behave predictably even under fault conditions.

An innocent mistake is that the design shows an earthing point but does not show the full logic of the connections. It does not analyse the flow of fault currents. It does not take into account compatibility with surge protection. It does not anticipate the quality of equipotential bonding between the transformer enclosure, switchgear, structures, trenches and the earthing busbar.

Good earthing is not a line on a diagram. It is the behaviour of the installation at the worst possible moment.

7. Mistake seven: fire protection added after the location is chosen

For oil‑immersed transformers, the topic of fire and environmental protection must enter the design early.

Not when the building is already standing, the distances are fixed, and the investor asks whether "this can somehow be solved".

Transformer oil performs an insulating and cooling function, but in classic mineral solutions it can be a combustible material.

Oil‑immersed transformers are an important element of electrical infrastructure, and the oil used in such devices can pose a fire risk, therefore they require well‑thought‑out protection.

An innocent mistake sounds like: "we will put the transformer here because it is closest to the switchgear."

Closest does not always mean best.

The transformer location should take into account distances from buildings, partitions, escape routes, other equipment, material stores, auxiliary installations and critical infrastructure. For oil‑immersed transformers, oil retention and the ability to contain contaminants in the event of a leak are added.

IEEE Std 980 is a guide for the limitation and control of oil spills in substations, and its purpose includes designing solutions that help contain oil and limit environmental effects.

This is particularly important for photovoltaic farms, energy storage systems, industrial plants and stations where one transformer is not just a device but a node of the entire process. A fire or leak then does not mean only the repair of one component. It can mean downtime, environmental procedures, production loss, delays and difficult conversations with the insurer.

A good transformer location is not the choice of the shortest cable route. It is the choice of the safest working architecture.

8. Mistake eight: noise and vibrations left "for later"

A transformer hums. That is normal.

The problem begins when the design assumes that "normal" means "unimportant".

Noise and vibrations can travel through the building structure, cable trenches, rigid connections and sound‑reflecting surfaces. As a result, a transformer that itself meets the requirements can, after installation, become a source of nuisance because the surroundings act like a resonance box.

The transformer location affects the perceived sound level, and installation in a corner, a narrow corridor or near smooth surfaces can cause sound reflection and amplification. Measures to limit vibration transmission are also recommended, for example appropriate insulating pads, flexible cable routing and secure fixing of enclosure panels.

An innocent mistake: "we will put it in the corner, it will be less intrusive."

Sometimes it is precisely in the corner that it is more intrusive.

If the transformer is located near offices, control rooms, dwellings, property boundaries or people's workplaces, the acoustics topic should appear before installation. And it is not about dramatising. It is about respect for user comfort and avoiding costly corrections that later resemble treating a toothache by changing the chair.

Noise is designed with space. Vibrations are designed with detail. And operational peace is designed earlier, not after the first complaint.

9. Mistake nine: protection devices selected separately, without coordination with the entire installation

The transformer is patient, but it is not alone.

It works with the MV switchgear, the LV switchgear, protection devices, surge arresters, the metering system, automation, loads and the load character.

A design mistake looks innocent when each element "by itself" is correct. The protection is selected. The instrument transformers are selected. The cables are selected. The switchgear is selected. Only then it turns out that together they do not play like an orchestra, but like five people tuning instruments in a lift.

Protection coordination should take into account short‑circuit currents, transformer inrush current, selectivity, permissible overloads, the nature of the loads, the presence of inverters, energy storage systems, reactive power compensation, automation systems and the grid operator's requirements. In modern installations with photovoltaics, electric vehicle chargers and energy storage systems, the load is no longer a simple story of motors and lighting. It is a dynamic ecosystem.

This is the essence: transformer installation does not end with the transformer.

If the protection devices are designed without a conversation with the entire installation, they can act too nervously, too late or in the wrong place. And then even a very good transformer is drawn into problems it did not create.

10. Mistake ten: no acceptance and commissioning scenario at the design stage

Technical acceptance should not be a finale full of surprises.

It should be a confirmation of what the design foresaw from the beginning.

An innocent mistake: the documentation assumes installation but does not assume proper commissioning. There is no clear list of measurements. There is no provision for access to inspection points. The sequence of activities is not planned. It is not clear who is responsible for checking settings, who for tests, who for as‑built documentation, who for compliance with the DTR, and who for the decision to energise.

Eaton, in its material on best practices for dry‑type transformers, indicates that new transformers should be inspected on receipt for transport damage, and before energisation, among other things, auxiliary devices, tap selection, ratio connections, and the tightening and clearances of electrical connections should be verified.

This sounds simple. And that is precisely why it is sometimes omitted.

Transformer commissioning is not a ribbon‑cutting. It is the moment when the design, delivery, installation, measurements, protection and operation meet at one point. If everyone worked in separate silos before, commissioning will show it.

In a good design, at the documentation stage, it is already known what measurements will be needed, what conditions must be met, what protocols will be produced and which elements must be checked before voltage is applied. Thanks to this, commissioning is a calm process, not a technical escape room with a clock in the background.

11. Mistake eleven: no thought for future expansion

The cheapest time to foresee expansion is before construction.

After that, every additional metre, every bushing, every space reserve and every change to the cable route starts to cost more, because it conflicts with operating infrastructure.

In transformer projects, this mistake appears often. Today one transformer is enough. Today a given power is enough. Today there is no energy storage system. Today there are no chargers. Today the photovoltaic farm has a specific layout. Today the plant operates on its current load profile.

But the power industry is changing faster than before. Companies are electrifying processes. Electric vehicle charging stations are being added. Requirements for power quality are increasing. Energy storage systems, inverters, compensation, automation, monitoring and new operating models are appearing.

An innocent design mistake is that the installation is designed perfectly for today, but without a margin for tomorrow.

It is not always about oversizing the transformer. Sometimes it is about space reserve, an additional bushing, a sensibly planned station layout, the ability to add apparatus, a cable route without traps and an architecture that does not close the door on the investor.

A good design does not predict the future. It leaves reasonable space for it.

How to design a transformer installation so you do not pay twice

The best strategy is simple, though it requires discipline: design the transformer as part of the system, not as a device to be placed.

First, data must be collected.

Power, transformer type, losses, weight, dimensions, manufacturer's requirements, environmental conditions, service access, short‑circuit parameters, network configuration, load profile, operator requirements, expansion scenario and site constraints.

Then geometry must be checked.

Not only the footprint, but also access, door opening, cable routes, bending radii, trenches, bushings, grilles, service zones, crane or transport equipment access, and the possibility of replacing the device in the future.

Then heat must be calculated.

The transformer dissipates losses to the surroundings, so ventilation must be matched to the real conditions. It must be neither symbolic nor excessive. It should operate stably, without creating condensation problems.

The next step is safety.

Earthing, equipotential bonding, shock protection, protection devices, fire protection, oil retention, escape routes and access for emergency services cannot be an add‑on at the end.

Finally, documentation.

Manufacturer's instructions, protocols, measurements, settings, diagrams and as‑built documentation should be prepared so that operation does not have to guess what the designer meant.

A good transformer installation design has something very elegant about it: it does not shout.

It just works.

A good design lets the transformer work calmly

Transformer installation is not a stage that begins on the day of delivery.

The most innocent installation mistakes have a common feature: at the beginning they save a few minutes, and later they can take a few weeks. That is why it is worth, early enough, comparing the design with the manufacturer's documentation, the technical requirements, the site conditions and the planned method of operation.

The transformer really does not expect luxuries.

It needs a stable base, an adequate amount of air, good connections, well‑thought‑out protection and a little respect for physics. In return, it can reliably perform its work for many years.

Thank you for staying with us to the end.

Hundreds of transformers sold and participation in projects powering Poland's energy infrastructure confirm that good solutions start with proper selection and technical partnership.

Explore Energeks transformers, check the units available in stock, and join Energeks on LinkedIn, where we share technical knowledge, projects and what is currently happening in the power industry!

References:

1. Schneider Electric, Electrical Installation Guide (Schneider Electric)

2. Eaton, Best practices for the installation and inspection of dry type distribution and power transformers . (Eaton)

3. NFPA, Transformer Fire Protection (nfpa.org)

Heatwaves are returning. Transformers remember every one of them.

When the air temperature exceeds 35°C, most electrical devices simply work harder. Air conditioners draw more current. Refrigerators don't rest. Industry runs at full capacity because deadlines chase deadlines.

And the transformer stands in the corner of the switchgear station, in a container or in a building basement, and does its job. Without a word of complaint. Up to a point.

That point has a name: critical winding temperature.

When you exceed it, the transformer does not always shut down elegantly with an error message. Sometimes it just accelerates its ageing. Quietly. Invisibly. Day after day, throughout the hot summer.

This text is about what really happens to a transformer during a heatwave, why standard parameters can be misleading, and what exactly is worth checking before high temperature does it for you.

Reading time: about 9 minutes.

First, some physics without which the rest makes no sense

When a spectacular explosion of a power station appears in the media — like recent well‑known footage from the Enstedværket site near Aabenraa, a facility linked to Energinet infrastructure — it is easy to focus on the effect itself: the flash, the bang, the smoke, the scale of destruction.

Photo via LinkedIn on profile of Emil Mahler Larsen

But in power engineering, such images are only the finale.

The end of a process.

Before a failure, before protection trips, before an electric arc, fire or mechanical damage to equipment, physics always happens first. Sometimes over seconds. Sometimes over months. Sometimes over years.

And that is precisely why the conversation about transformer overheating in heatwaves is not seasonal scaremongering. It is a conversation about what happens inside the device long before the problem becomes spectacular.

A transformer produces heat. Not by accident, but by the very nature of its work.

Core losses. Copper or aluminium winding losses. Eddy currents. Leakage fluxes. All of this turns into heat that must go somewhere.

In oil‑immersed transformers, this heat is taken up by the oil, which circulates naturally or with pumps and releases energy to the surroundings through radiators or tank fins.

In dry‑type transformers — and we will focus on these here, because they stand in buildings, indoor substations, data centres and industrial halls — this heat is released to the air.

And here the problem begins.

Air in summer is warm.

Warm air absorbs heat less effectively than cold air.

A transformer that calmly operates with a winding temperature of 80°C in winter can reach 95–100°C in summer at the same load. Or more.

Every additional 10°C above the rated value translates into roughly twice as fast insulation ageing. This is not an opinion — it is the well‑researched Arrhenius law, used in electrical engineering for decades.

Insulation that should last 30 years, with regular exceedance of the permissible temperature, can end its life in half that time.

Reason 1: Ambient temperature higher than the design assumed

Most dry‑type transformers are designed for a maximum ambient temperature of 40°C. This is a standard value, often visible in the technical documentation.

What does this mean in practice?

That the manufacturer designed the cooling so that at 40°C in the room, the transformer does not exceed the permissible winding temperature.

When the ambient temperature exceeds 40°C — which in Poland's climate during the summers of 2024 and 2025 happened increasingly often — the transformer begins to operate outside its rated thermal capabilities.

There is no fault in that. It is simply physics.

If you have a dry‑type transformer and you do not know what the actual temperature is in its room on a hot day, you are in the situation of a driver who does not know the engine oil temperature on a climb up to the Tatra Mountains. The engine may get you there. But it may not come back intact.

What is worth doing: check what the actual ambient temperature is at the transformer on the hottest days. Not in the office. Not outside the building. At the transformer, at 3:00 PM, when the sun has been heating the walls and roof for several hours.

Reason 2: Room ventilation that cannot keep up

A dry‑type transformer cannot dissipate heat into a vacuum. It dissipates it into the air in the room. That air must go somewhere — and must be replaced by cooler air.

If the room ventilation is too weak, the air temperature at the transformer rises. The transformer dissipates heat into increasingly warmer air, which means it itself becomes increasingly warmer.

This is a vicious circle and can lead to overheating even at a load well below rated power.

Summer heat does one specific thing here: it heats the air outside the building, which is the source of cooling. If the ventilation intakes draw air from the south, and the sun heats the south wall of the building — the intake air temperature can be 5–10°C higher than the air temperature in the shade.

And that is before the air even reaches the transformer.

What is worth doing: assess whether the ventilation openings are well placed and whether the grilles are not blocked by dust, dirt‑clogged protective meshes or accidental storage of items. Check whether the airflow actually passes through the room, rather than circulating in a closed loop.

Reason 3: Load increases together with temperature

This is the paradox of summer that hurts double.

When it gets hot, the demand for electricity rises. Air conditioning. Ventilation. Cooling systems. Food industry at full speed. Refrigerators, freezers, server room cooling systems — everything wants its share of power.

This means that transformers are more loaded in summer than in winter.

And at the same time they have a worse ability to dissipate heat.

Higher load → more losses in windings → more heat to dissipate. Higher ambient temperature → worse cooling conditions → slower heat dissipation.

These two effects act at the same time and in the same direction.

A transformer in July therefore works under a double unfavourable condition. It produces more heat and dissipates it more slowly.

What is worth doing: check historical load data for the transformer from previous years during the summer months. If the load has increased in recent years (because more air conditioning, new equipment or facility expansion has been added), the thermal margin may have shrunk.

Reason 4: Temperature sensors that do not alarm in time

A modern dry‑type transformer should be equipped with winding temperature sensors. These can be PT100 or PTC sensors, which work with a thermal relay. The relay sends an alarm signal at the first threshold and disconnects the transformer at the second — critical — threshold.

Sounds good.

But in practice, three problems appear.

First: the sensor measures temperature at a specific point on the winding. If it is poorly placed or outdated, it may not reflect the actual temperature at the hottest point of the coil.

Second: some transformers, especially older or cheaper installations, have alarm settings set too high. The alarm appears when the insulation has already been operating in excessive heat conditions for weeks.

Third: the alarm signal goes to the building's BMS system or to a local panel. If no one is actively monitoring this in summer, the alarm may burn unnoticed for several hours.

What is worth doing: check when the sensor system was last calibrated and tested. Check the alarm settings in the documentation and compare them with the temperature for class F insulation (155°C) or class B (130°C). Ensure that the alarm reaches someone who responds — not just logged in a file.

Reason 5: Overload during the summer peak

Transformers have the ability for short‑term overload — even up to 120–150% of rated power for a specified time. This is a design option, useful for temporary demand peaks.

Only this capability is calculated on the assumption that the transformer operated for some time at low load before the overload and is relatively cold.

In summer, the transformer can be warm around the clock. Cool nights, which in winter gave it time to rebuild its thermal margin, may not provide sufficient cooling in summer.

When such a transformer enters a peak load state — say, during a hot afternoon when air conditioning is pulling full power — it starts from a higher base temperature. The margin to critical temperature is smaller. An overload that would be fine in winter can be risky in summer.

What is worth doing: if the transformer is often used close to its rated power limits, review the overload curves in the technical documentation and check how they change with ambient temperature. Manufacturers provide this data. It is worth reading before August, not after.

Reason 6: Dust and dirt in summer block cooling ducts

Dry‑type transformers dissipate heat through air ducts in the windings and between structural elements. These ducts must be clear.

In summer, when windows and doors are open more often, fans work more intensively, and nearby construction and renovation work generates more dust — the amount of dust in the air increases.

Dust settles on the windings and in the ducts. If the winding is of the open‑wound or VPI type, dust can gradually restrict airflow. The thicker the dust layer, the worse the cooling.

In cast‑resin transformers, the problem is smaller — the epoxy resin creates a closed shield around the windings. But here too, dust on the external surfaces blocks heat exchange.

Additionally, dust saturated with moisture can pose a risk to insulation — especially if it contains metallic particles or chemical substances from production.

What is worth doing: check the cleanliness of the transformer and its surroundings. If previous inspections showed excessive contamination, it may be worth planning cleaning before the summer peak, not after.

Reason 7: The transformer simply has years on it

Transformer insulation ages. This is not an opinion — it is a technical and economic fact worth taking into account.

With each year of operation, with each heatwave, with each overload and each heating and cooling cycle, the insulation loses its properties. It becomes brittle. Loses flexibility. Its dielectric strength decreases.

A transformer that is 15–20 years old and for half its life has operated in difficult thermal conditions may have insulation in a condition corresponding to a much older device.

No one sees this with the naked eye. The insulation may look good and at the same time be on the verge of breakdown.

Heat is not a problem in itself. Heat is a test.

If the insulation is in good condition, the test will pass without complications. If it is tired — heat may be the moment that finalises what began several years earlier.

What is worth doing: if the transformer is over 15 years old and has not undergone diagnostics in the last few seasons, it is worth considering insulation measurements. Insulation resistance measurement, absorption coefficient, and in the case of oil‑immersed transformers — oil analysis — are tools that give a real picture of the device's technical condition.

What to specifically do when a heatwave arrives

Below is a practical list of actions that make sense before and during high temperatures. There is nothing exotic here — only things that really affect the safety of transformer operation.

Before the summer season:

• Check the temperature in the transformer room from the previous summer, if you have such data. Compare it with the ambient temperature assumed in the documentation.

• Assess ventilation: are the grilles clear, is the airflow correct, is the intake air not coming from places excessively heated by the sun?

• Check the temperature sensor settings and test whether the alarm signal actually reaches the responsible person.

• Assess historical load — is the transformer being increasingly loaded year on year?

• If the transformer is over 15 years old, consider a diagnostic inspection before the season.

During a heatwave:

• Monitor the temperature in the transformer room regularly — not just once a week.

• If the transformer has forced cooling (AF fans), check whether the fans are working correctly and whether their operation is triggered at the right time.

• If you have the ability to temporarily distribute the load or reduce non‑productive loads during the temperature peak, consider it.

• Do not ignore a temperature alarm, even if it has always turned out to be false before. In summer, every alarm needs checking.

Dry‑type vs oil‑immersed transformer — does this change the situation?

Yes, but not as many think.

An oil‑immersed transformer has oil that carries heat away from the windings to the tank walls and radiators. This allows for higher thermal capacity and slower winding temperature rise during short‑term peaks.

But the oil also has its own critical temperature. At too high ambient temperature and too weak cooling — for example with blocked tank fins or a damaged cooling pump — an oil‑immersed transformer will also overheat.

A dry‑type transformer reacts faster to ambient temperature changes because it does not have the thermal buffer of oil. On the other hand, there is no risk of oil leakage, no risk of oil fire, and it is generally less complex to operate.

In both cases, the principle is the same: high ambient temperature reduces the transformer's ability to dissipate heat. And in both cases, ignoring this for several seasons leaves a mark on the insulation.

A few words about what is not worth doing

It is not worth relying solely on the fact that "it has always worked."

Transformers are unfailingly patient devices. They can operate in poor conditions for months and years without giving clear signals. And then the failure happens suddenly — often during the first major overload or an especially long heatwave.

It is also not worth assuming that since the transformer has a temperature sensor, the problem will solve itself. A sensor can warn — but it cannot improve ventilation, reduce load or repair insulation that is already tired.

And it is not worth comparing a transformer to a device where "if it breaks, we will buy a new one." MV transformers are investments for decades. Premature failure is not only the cost of buying a new device — it is downtime, installation cost, risk of burnouts in the installation, potential production loss and a lot of nerves at the station.

Heat is not an enemy of the transformer if you help it

A heatwave is a test of the power infrastructure.

Most transformers that are in good technical condition and operate in well‑designed conditions will get through the summer without problems. These are devices built for long‑term operation.

But those that are a dozen or so years old, operate in poorly ventilated rooms, are increasingly loaded and have not been regularly checked — have much less margin in summer.

The good news is simple: most of these problems can be checked, assessed and improved. Ventilation. Load. Cleanliness. Sensors. Insulation condition.

This is not complicated diagnostics. It is taking care of a device that serves the entire installation and has no replacement during a failure.

If you do not know what condition your transformer is in and how it will react to the next heatwave — this is a good time to find out.

Want to check your transformer before the season?

At Energeks, we help select transformers for real operating conditions and assess whether an existing device has the right margin for summer peaks.

If you are planning a transformer replacement, station modernisation or want to check whether the current unit has the right power reserve, see:

—> our range of dry‑type and oil‑immersed transformers

—> transformers available off‑the‑shelf in our warehouse

—> further technical analyses on the Energeks LinkedIn profile

In a well‑designed transformer station, summer should not be a lottery.

It should be just another working season.

sources:

Energinet — Ensted–Kiskelund / Enstedværket przy Aabenraa

IEC 60076-7:2018 — Loading guide for mineral-oil-immersed power transformers

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

On the table lie two offers.

In one, someone declares: copper, so premium.

In the other: aluminium, so economical.

Both sound confident.

Both try to win your attention with a single word.

And this is where the problem begins.

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

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

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

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

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

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

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

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

Concrete content awaits you inside.

First, we will dismantle the most common myths.

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

Finally, we will give you a practical decision filter.

Reading time: ~ 8 minutes

What really determines the quality of transformer windings?

Do not jump too quickly.

First, name the game.

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

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

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

Technology does not work that way.

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

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

European ecodesign regulations for transformers focus on minimum efficiency levels.

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

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

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

There is no point pretending the differences do not exist.

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

For annealed copper, the standard is 100% IACS.

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

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

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

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

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

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

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

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

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

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

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

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

Sounds impressive. Says little.

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

In recent years, efficiency requirements have become tougher.

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

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

What does this mean in practice?

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

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

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

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

Aluminium is not an automatic guarantee of worse efficiency.

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

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

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

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

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

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

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

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

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

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

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

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

The copper advocate cannot say: always better.

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

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

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

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

No.

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

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

And here it is worth pausing for a moment.

The problem is not aluminium itself.

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

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

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

When does aluminium in a transformer make sense?

This is where the conversation becomes really practical.

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

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

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

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

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

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

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

Instead of asking "do you have copper?",

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

And you will know who you are talking to.

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

Copper or aluminium in a transformer – which is better?

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

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

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

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

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

A mature decision looks different.

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

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

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

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

The best questions usually do not sound spectacular.

They sound calm and precise.

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

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

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

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

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

What you can expect from us

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

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

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

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

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

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

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

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

The most expensive thing is oversimplification.

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

With an attitude towards real mutual benefit.

You get a transformer that does its job for years.

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

And only then does the conversation truly make sense.

Sources:

1. European Commission, Power Transformers, Ecodesign Requirements

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

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

It can pretend for years that everything is under control.

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

A medium voltage transformer is a master of patience.

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

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

And that's precisely why it can be treacherous.

It doesn't break when things are really bad.

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

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

This text isn't about failures.

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

We see it more and more often.

Grids are working more intensively.

Load profiles are sharper.

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

The trusty old transformer copes and keeps working.

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

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

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

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

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

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

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

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

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

Reading time: about 9 minutes

When overload stops being flexible

Every medium voltage transformer has a certain tolerance.

The designer isn't naive.

They know life won't be a catalog table.

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

And for a long time, everything indeed works.

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

Flexible overload is an episode.

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

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

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

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

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

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

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

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

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

And today, context changes faster than ever.

Why short episodes have long consequences

Many investors think like this:

It was only 30 minutes.

Nothing happened.

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

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

Paper insulation in a transformer ages due to cellulose depolymerization.

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

We cannot reverse this process.

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

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

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

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

Harmonics cause additional losses in the core and windings.

Losses mean heat. Heat means accelerated aging.

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

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

Physics doesn't forget. It accumulates.

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

This isn't a zero-one decision.

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

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

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

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

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

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

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

The most important decision is moving away from catalog thinking.

Rated power isn't an absolute.

It's a reference point for specific conditions.

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

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

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

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

Decision number three is peak management.

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

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

Extending a transformer's life isn't heroism.

It's consistent data management.

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

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

Why aging accelerates non-linearly

Here we get to the heart of the matter.

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

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

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

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

That's why we talk about non-linearity.

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

Near the limit, they become abrupt.

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

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

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

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

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

We discuss them in detail in the article:

Refurbish or replace? Your transformer's last chance!

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

How much does operating outside rated parameters really cost

The cost isn't limited to the energy bill.

First, we shorten the device's technical life.

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

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

Second, the risk of unplanned downtime increases.

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

Third, power quality parameters deteriorate.

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

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

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

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

The myth of momentary overload

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

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

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

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

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

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

Why failures are the logical consequence of earlier choices

A failure is rarely a single event.

It's the result of a sequence of decisions.

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

Abandoning monitoring because nothing happened for years.

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

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

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

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

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

The transformer as part of a strategy, not a cost

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

Power, voltage, delivery date, price.

Ordered, installed, connected.

It's supposed to work.

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

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

It's the energy node of the entire installation.

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

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

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

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

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

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

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

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

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

It becomes part of the power control system.

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

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

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

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

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

Not because it "still fits somehow."

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

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

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

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

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

Does oil change extend a transformer's life?

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

That's why diagnostics must be comprehensive.

Is it worth installing online sensors in older units?

In many cases, yes.

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

Does oversizing always pay off?

Not always.

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

Summary and invitation

Transformer aging isn't linear.

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

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

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

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

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

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

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

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

References:

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

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

There is a moment of silence before the first ampere trembles.

On the screen glows a 3D visualization, where the core consists of thousands of thin laminations, and the windings resemble precisely laid ribbons.

This is where the life of an oil transformer begins, long before it reaches a substation and powers a residential district or a production line.

A good story isn't magic; it's engineering told in the right sequence.

That is exactly what we are doing today.

At Energeks, we work with medium-voltage transformers, prefabricated transformer substations, switchgear, and energy storage systems every day.

We combine practical experience with the requirements of standards and the expectations of investors.

This text is the result of numerous conversations with designers, technologists, and assembly teams.

We present the process in a way that helps make better decisions and predict outcomes at the concept stage.

If you design, purchase, order, or will be operating an oil transformer, understanding the production chain of cause and effect will save you time, money, and nerves.

In the end, you will know why a specific requirement in the technical specification translates into particular operations, risks, and performance parameters for decades.

Agenda:

• Design and digital visualization

• CRGO lamination core and step lap configuration

• Windings. Conductor selection and geometry

• Insulation system. Kraft paper and DDP

• Active part assembly and preparation for testing

• Tank. Corrugated or with radiators

• Surface treatment and anti-corrosion protection

• Drying of the active part and moisture control

• Vacuum oil filling and heat cycling

• Routine tests and readiness for shipment

Reading time: ~20 minutes - just right for some worthwhile reading during your afternoon coffee and biscuit break!

Design and digital visualization

Every transformer begins with an idea, which looks less like a magical spark and more like... Excel, CAD, and... coffee at three in the morning.

The process of designing an oil transformer is a precise puzzle where physics meets mathematics, and everything must fit inside a tank with specific dimensions and weight.

Before anyone even orders steel or copper, the design team creates a digital model of the transformer, also known as a digital twin.

In this model, they test how the magnetic field will behave under different loads, how heat flows, where mechanical stresses will occur, and what the no-load and load losses will be.

This is not just a "nice 3D visualization of a transformer"—it's a virtual testing laboratory that saves months of work and hundreds of thousands of EUR.

The designer must reconcile several worlds:

• The electrical world: parameters like voltages, ratios, and vector groups.

• The mechanical world: short-circuit forces and cooling.

• The material world: because CRGO steel has different properties than amorphous steel.

• And finally, the environmental world: ambient temperature, humidity, and altitude above sea level.

This is where the engineering dance between theory and practice begins.

For example: increasing the number of turns improves voltage stability but raises the winding resistance and thus the losses. Reducing the conductor cross-section lowers costs but impairs cooling. As always—the devil is in the details, and the angel is in the tolerance table.

In modern factories, the transformer design doesn't end on paper. Digital visualization allows for simulations in environments like ANSYS Maxwell or COMSOL Multiphysics, where one can check how the transformer will behave during a short-circuit, overheating, or a lightning impulse. It's a bit like training—it's better for the equipment to "take a beating" in the computer than in the power grid.

Thanks to such models, it's also easier to adapt the construction to a prefabricated transformer substation, where every centimeter counts. The designer can see in advance if the mounting holes, coolers, tap-changers, and accessories will fit without collisions. This is the magic of 3D transformer design—a virtual factory before the real one is built.

A well-designed digital transformer already has a full data package defined at the design stage:
Technical documentation, a bill of materials, a winding schedule, and a detailed cooling plan.

This shortens production time by up to 20% and minimizes the risk of errors.

CRGO lamination core and step-lap configuration

At the heart of every transformer lies its core – the magnetic core.

It doesn't glow or shine, but its quality determines whether the device will purr like a cat or hum like a refrigerator from the 1980s. The core is precisely what dictates no-load losses, noise levels, and overall energy efficiency.

And it all starts with a material known by a three-letter acronym every electrician memorizes:

CRGO – Cold Rolled Grain Oriented Steel.

This silicon steel, with grains oriented in a single direction, has a unique gift:

It conducts magnetic flux like a well-designed channel conducts water.

As a result, hysteresis losses (the energy consumed with every reversal of the magnetic field) are even 30–40% lower than in ordinary hot-rolled steel.

From an engineer's perspective, it's like an engine running at lower throttle but delivering the same power.

During the production of the transformer core, CRGO laminations are cut with laser or knife-edge precision to within tenths of a millimeter.

It is crucial that they have no burrs or micro-cracks, which could become sources of loss or vibration.

Here, not only geometry matters but also the stacking sequence. Modern designs use a so-called step-lap configuration – a technique of overlapping the lamination edges, resembling roof tiles.

The effect? Magnetic flux flows smoothly, without abrupt "jumps" between segments, which reduces noise and improves efficiency.

Imagine the core as a labyrinth where the magnetic field seeks the shortest path.

Every gap, every misalignment is like a hole in the path = energy escapes as heat and sound.

This is why the following are so critical:

• High-quality laminations (low core loss, e.g., 0.9–1.1 W/kg at 1.5 T and 50 Hz),
• Precision cutting and stacking,
• And solid joints between yokes and limbs that eliminate micro-gaps.

In large units, the core is assembled in segments: first the limbs, then the yoke, and the whole structure is clamped with steel frames.

Some manufacturers use bonded interlayer insulation systems that limit vibration and improve the coherence of the core package. Amorphous cores, which are even more energy-efficient though more difficult to process, are also becoming increasingly popular.

From a user's perspective, you can hear the difference between a "good" and a "bad" core.

Literally. A transformer with a perfect step-lap configuration and the right CRGO steel can be several decibels quieter, meaning in practice you can hold a normal conversation next to the operating equipment. For urban substations installed near buildings, this isn't a minor detail, but a condition for project acceptance.

An interesting fact

Some production lines use algorithms to optimize the core cutting angles based on the working flux density.

This is pure field mathematics: the better the grain orientation, the smaller the magnetic distortions and the lower the losses at high voltages. As a result, the transformer gains a few percentage points in efficiency without additional material costs.

This is how the foundation of the entire device is created – both literally and figuratively.

The CRGO lamination core is an engineering compromise between physics, economics, and the quiet that speaks of perfection.

Windings. Conductor selection and geometry

If the core is the transformer's heart, then the windings are its muscles – they carry the energy, and their shape, material, and insulation determine how effectively they do so. In theory, it's simple: we have a primary winding, a secondary winding, the right number of turns, and Faraday's law of induction. In practice, it's a world of hundreds of nuances that can determine whether the transformer survives its first short-circuit.

First, the choice of metal. Copper or aluminium?

Contrary to myths, it's not just about price.

Copper has higher conductivity (approx. 58 MS/m), but it's heavier and more expensive.

Aluminium (approx. 35 MS/m) requires a larger cross-section but facilitates cooling thanks to better temperature distribution. For transformers with powers up to a few MVA, the choice often depends on material availability and client requirements. You can find more about differences in conductivity and material properties in analyses by the International Copper Association, which has been researching the efficiency of copper in the power industry for years.

Shape and geometry – a dance between the magnetic field and oil

The low-voltage (LV) winding is most often made from paper-insulated rectangular strip or wire, wound in layers. The high-voltage (HV) winding – from round or rectangular wires, also in paper, but with a more complex geometry. All this is done to minimize the stray field and distribute temperature evenly in the oil.

The principle is simple: the shorter the current path, the smaller the losses. But engineers know that reality is rarely straightforward. HV windings often use helical, cylindrical, or disc-type arrangements, which allow for controlled magnetic field distribution and oil cooling through microchannels.

In laboratories, you can see how such a winding in cross-section somewhat resembles a multi-layer cake – except instead of cream, we have cellulose Kraft paper and epoxy resin.

Insulation secrets – cellulose and DDP in action

Every winding needs protection from voltage and temperature. This is where Kraft paper and its enhanced version, DDP (Diamond Dotted Paper), come into play. This is a material where micro-dots of resin are arranged in a regular grid – during the heating process, they create a "weld" between the winding layers. The result? A rigid structure resistant to vibration and discharges. The layer insulation made from DDP paper has another advantage: it allows for precise control of the so-called "creepage distance." A high value for this parameter reduces the risk of flashover, which is crucial at voltages of 15–36 kV.

Insider jokes

In the industry, they say that "a winding can be made beautifully, but only once" – because if something goes wrong during the winding process, there is no second chance. Too much pressure? Damaged insulation. Too little? Vibration. That's why winding machine operators often have the status of artists – they can feel the tape's resistance with their fingers before a sensor shows any deviation.

Anyone who has had the chance to see the winding of an oil transformer coil live knows it's like watching a watchmaker at work on an XXL scale.

Precision, rhythm, and focus – all so that the current can flow for decades in perfect rhythm

Manual winding of oil transformer coils using copper conductors and DDP paper insulation.

A key manufacturing stage ensuring transformer efficiency and long-term reliability.

Insulation system. Kraft paper and DDP

Insulation in a transformer is somewhat like skin in a living organism – invisible from the outside, but absolutely crucial for the life of the entire system.

Without it, even the most beautifully designed core and windings wouldn't stand a chance of surviving the first overvoltage. And just as human skin relies on elasticity, resistance, and regeneration, the most important properties in a transformer are dielectric strength, mechanical stability, and resistance to thermal aging.

The primary material that meets these requirements remains Kraft paper – a cellulose classic with an extremely long history.

It is made from wood fibers of high chemical purity, which ensures low ash content and excellent electrical strength. In transformers, it is used in the form of tapes, sleeves, and spacers. In contact with mineral or synthetic oil, the paper swells minimally, maintaining dimensional stability, and its micropores allow for the exchange of gases and oil.

But the world of insulation has taken a step further. In higher voltage windings, DDP (Diamond Dotted Paper) is used, coated with a regular grid of micro-dots of epoxy resin. When the winding enters a vacuum oven and reaches the appropriate temperature, the resin melts, fusing the paper layers into a rigid, homogeneous structure.

The result? Insulation that doesn't shift even under severe electromagnetic transients and vibrations. It is this "glue" that prevents the transformer from "humming" during the startup of large drives.

A properly designed insulation system isn't just about the paper. It also involves vacuum impregnation, which removes air bubbles, and protective layers made from pressed cellulose boards that absorb mechanical stresses. A key parameter remains the breakdown voltage – values in the range of 40–60 kV/mm indicate the quality of the material and the purity of its structure.

A well-chosen insulation system for an oil transformer is an investment in peace of mind for maintenance crews for the next 25–30 years. It determines whether the equipment can withstand not only voltage overloads but also thousands of heating and cooling cycles, which act like slow, yet relentless, fatigue tests.

A tidbit from high-voltage laboratories

Modern research on dielectrics shows that even a slight increase in the paper's moisture content from 1% to 3% can reduce its electrical strength by over 50%. This is why drying and controlling the water content in cellulose is a topic that will reappear later in this article.

Active part assembly and preparation for testing

At this point, the transformer begins to resemble more than just a collection of parts – it slowly becomes a living organism.

The active part assembly stage is an engineering orchestra, where every element has its place, its specific torque, and its tolerance. The precision of these actions determines whether the device will operate without vibrations or failures for decades to come.

The active part is the combination of the core, windings, yokes, spacers, and insulation – everything responsible for conducting and transforming energy.

First, the low-voltage and high-voltage windings are placed over the core limbs.

Some designs require additional electrostatic screens or grading rings, which distribute the electric field evenly along the entire length of the winding.

Once the windings are in place, it's time to assemble the yoke, the top part of the core. It's like closing the lid of a well-fitted watch. Here, wedges, clamping frames, and spring-loaded bolts are used to mechanically stabilize the structure.

The whole assembly must be rigid, but not overly so – a transformer needs a minimal degree of flexibility to withstand short-circuit forces without cracking the insulation.

Next, the tap changer (OLTC or NLTC) is installed – this is what enables voltage regulation on the high-voltage side, compensating for fluctuations in the grid. In large units, it is mounted in a separate oil compartment; in smaller ones, directly on the cover.

Each tap changer is tested electrically before the oil is filled, as access to it becomes difficult after final assembly.

Stability, tightness, and cleanliness

Three words that govern this phase. Every speck of dust, every under-torqued yoke, every poorly positioned wedge can turn a future transformer into a potential source of failure. This is why assembly takes place in clean, controlled conditions – often in halls with positive pressure to prevent dust ingress.

After the active part is assembled, it's time for preliminary tests.

These are "dry tests" that ensure everything is according to design:

• Winding resistance measurement,

• Vector group verification,

• Ratio measurement,

• Inter-system insulation check.

These tests are the first moment the transformer "speaks" – its parameters begin to form graphs and numbers.

Find out how we test our transformers at Energeks, insider knowledge you won't find on Google:

How do we test our transformers? A symphony of factory quality!

A short digression on vibrations and patience

In experienced assembly teams, a rule prevails:

"Don't rush the clamping – the transformer will reward you with quietness."

Properly torquing the yokes and selecting the right elastic elements ensure the device does not produce unwanted sounds during operation.

After all, sound is energy that could have been better utilized – for example, for transmitting current instead of an acoustic concert in a substation.

Where theory meets practice

It is at this stage that many young engineers understand for the first time that a transformer is not just a CAD project, but a physical machine with its own dynamics, weight, and rhythm.

In theory, every current transformer, coil, and screen can be described by equations.

In practice – you need an eye for detail and respect for mechanics.

For those who would like to explore the topics of short-circuit forces and the stability of the active part in greater depth, I recommend publications from Transformers Magazine, in which experienced designers analyse the influence of assembly on the mechanical overload resistance of transformers.

Tank. Corrugated or with radiators

Every transformer needs armor. Not to look combat-ready, but so its interior—full of windings, cores, and insulation—can peacefully bathe in oil and avoid interacting with the external environment.

This armor is the tank of the oil transformer, a steel vessel that provides cooling, tightness, and safety for the entire structure.

Simply put, the tank is the transformer's "shell of life." Its construction must withstand vibrations, temperature differences, and pressure, while remaining absolutely sealed for decades. This is why designers choose between two main types: the corrugated tank and the tank with radiators.

Corrugated tank – the master of compact solutions

A corrugated tank somewhat resembles an accordion made of steel sheet. Each of its "ribs" acts as a natural radiator, increasing the oil's cooling surface area. When the internal temperature rises, the oil expands, and the corrugated walls flex elastically, compensating for the volume changes.

No conservator, valves, or breather pipes are needed – everything happens within a hermetic space.

This solution is ideal for distribution transformers and applications where compactness and maintenance-free operation are key. The lack of a conservator reduces the risk of moisture ingress and oil oxidation, thus extending its lifespan. Fewer moving parts also mean quieter operation and a smaller service footprint – engineers like that, and accountants even more so.

Tank with radiators – industrial-grade classic

For larger units (typically above 2.5 MVA), corrugated walls are insufficient.

This is where plate radiators come into play – vertical panels welded to the sides of the tank. They work like car radiators: hot oil rises, flows through the panels, transfers heat to the air, and then descends, creating a natural circulation (ONAN – Oil Natural Air Natural) or a forced one (ONAF – Oil Natural Air Forced) with fans.

Radiators can also be easily replaced and expanded, making this system more serviceable.

The downside is greater weight and the need for regular checks of weld integrity, but it offers better thermal stability under heavy loads. High-class designs additionally feature safety valves, thermometers, oil level gauges, and Buchholz relays, which react to gases generated during internal faults.

From steel to tightness – the engineering of precision welding

The foundation of every tank is steel with high purity and controlled carbon content. After the sheets are cut, the tank is welded using MAG or TIG methods, and the welds are tested with non-destructive methods – most commonly ultrasound or penetrant testing. Factories also perform pressure tests: the tank is filled with compressed air or helium and immersed in water to observe for any bubbles. Simple, yet effective.

After leak tests, the tank is chemically cleaned and degreased. The interior is coated with a special varnish resistant to transformer oil, while the exterior receives an anti-corrosion coating system tailored to the environmental category – from C2 for urban areas to C5-M for marine environments.

The sustainable direction – recycling and hot-dip galvanizing

Modern production increasingly emphasizes tank corrosion resistance and material recyclability. Hot-dip galvanizing can increase the coating's lifespan up to five times, which is particularly important in coastal and industrial areas. Interestingly, some manufacturers are also testing powder coatings based on nano-ceramics – lighter but just as durable as classic zinc.

For those interested in the details, it's worth visiting the Hydrocarbon Engineering portal, where research on protective coatings and welding techniques for the power industry is published.

Vacuum oil filling and heat cycling

At this stage, the transformer resembles an astronaut before a mission – ready, sealed, dry, and waiting only for the medium that will allow it to live.

That medium is transformer oil, which serves two functions: cooling and insulating.

Without it, the transformer would be like an engine without oil – it would overheat, lose its parameters, and fail faster than it could receive a serial number.

Oil under vacuum – the physics of pure calm

The process of vacuum oil filling is an engineering spectacle of Swiss watch precision. The active part of the transformer, now enclosed in its tank, is placed in a chamber where a deep vacuum is first created – typically below 1 mbar.

Why? Because even microscopic air bubbles trapped in the windings or insulation could later cause partial discharges and local overheating.

When the pressure reaches the required level, the slow filling with oil begins, usually from the bottom. The oil penetrates every gap, displacing the air. Sometimes the entire process takes several hours – especially for large power transformers requiring thousands of liters of oil.

The fill rate is strictly controlled to prevent the formation of gas pockets or pressure differentials that could damage the delicate insulation.

After filling, the unit is left undisturbed, still under vacuum conditions, to allow all micro-bubbles of gas time to rise and dissipate. Only then can the transformer be said to be "impregnated" – ready for the first flow of current.

Heat cycling – a spa for the windings

After filling comes the heat cycling process, which has two goals: to stabilize the structure of the paper and resins and to reduce residual moisture to an absolute minimum.

The transformer is maintained at a temperature of around 80–90°C for several hours. During this time, the oil and insulation reach a state of thermal and moisture equilibrium.

This isn't a stage visible from the outside – but it's when the transformer "matures." Every layer of paper, every impregnation, acquires its final structure. After this process, a key quality parameter is measured: the oil's breakdown voltage.

A value above 60 kV for a 2.5 mm gap indicates a perfect insulation system.

Oil quality and purity control

High-grade transformer oil (e.g., mineral oil like Nynas, Shell Diala, or synthetic fluid like MIDEL) undergoes a series of tests before use: measurement of dielectric strength, viscosity, dissipation factor (tan δ), and dissolved gas content.

Some manufacturers use Chromatographic Dissolved Gas Analysis (DGA), which can detect even trace amounts of hydrogen, carbon monoxide, or methane – signals that something might later go wrong inside the transformer.

Learn more:

Gas laws in DGA transformers: 5 rules that will warn you of a failure

To maintain its parameters for years, the oil must be perfectly clean – even a single drop of water or a dust particle per liter can reduce the breakdown voltage by several thousand volts.

Therefore, after filling, the system is hermetically sealed, and all bushings, breathers, and plugs are secured against contact with air.

When oil becomes a witness to history

An interesting fact for enthusiasts: in service, transformer oil retains a memory of the unit's life. Analyzing its composition allows experts to read how long the equipment operated under overload, if it experienced a short-circuit, and even what temperatures it reached in recent years.

In maintenance laboratories, it's from the oil that the first signs of insulation aging are read – long before any smoke appears from the tank.

Now that the transformer is sealed, filled and cooling down after heating, the final stage of its journey through the factory remains – routine tests and final checks that will determine whether it can be shipped out into the world and power its first network.

Routine tests and readiness for shipment

An oil transformer may look ready – closed, filled with oil, and shining with fresh paint. But until it passes its tests, it's merely a candidate for a transformer, not a full-fledged participant in the power grid. In the world of electrical power, final tests are like a state exam: there's no room for a second attempt.

Routine tests – or "mandatory exams of everyday life"

According to the IEC 60076 standard, every transformer must undergo a set of so-called routine tests before leaving the factory. Their goal is to verify that the device operates exactly as designed – without compromises, shortcuts, or guesswork.

• Winding resistance measurement – A test that detects interturn short circuits, connection discontinuities, and assembly errors. Even a small resistance difference between phases can reveal a loose terminal.

• Vector group and ratio verification – Checking that the voltage on the secondary side has the exact ratio specified in the design. This test immediately detects mistakes in the winding direction of the coils.

• No-load and load loss measurement – A true barometer of the quality of the core and windings. If values exceed norms, it indicates excessive magnetic losses (core) or resistive losses (windings).

• Impedance voltage measurement – A test simulating a short-circuit on the secondary side, checking the mechanical and electromagnetic stability of the system.

• Dielectric tests – One of the most critical tests, checking the insulation's resistance to impulse voltages and long-term operating voltage.

Every measurement is recorded and compared with the design values. A transformer that passes everything within tolerance receives a Factory Acceptance Test (FAT) certificate.

Additional tests for demanding applications

Depending on the voltage class and customer requirements, type tests (on reference units) or special tests are also conducted, for example:

• Sound level measurement to confirm compliance with environmental requirements (for urban units, this is often a condition for acceptance).

• Measurement of magnetic circuit losses at different temperatures.

• Partial Discharge (PD) test, assessing the cleanliness of the insulation and the quality of impregnation.

These tests are particularly important for transformers intended for use in sensitive networks or in prefabricated substations where the level of interference must be minimal.

Engineering Aesthetics: Preparation for Shipment

After passing all tests, the transformer enters a stage underappreciated in textbooks but highly valued by installation crews – preparation for transport.

This includes:

• Draining excess oil and filling hermetic tanks with nitrogen.

• Sealing all openings and securing transport fittings.

• Installing lifting lugs, sensors, and the rating plate.

• A final visual inspection of coatings and welds.

At this stage, the transformer looks ready for a parade: painted, labeled, tested, and packed in a steel transport frame. But before it hits the road, engineers perform a final vibration and leveling check to ensure nothing loosens or shifts during transit.

Documentation – The Transformer's DNA

Along with the unit, the customer receives a complete set of documents:

• Technical and operational documentation.

• Measurement and test reports.

• Oil test results.

• Material certificates for components used.

• Certificates for weld quality and anti-corrosion coatings.

This is the transformer's DNA – a record of its entire "life" from design to the final test. In practice, this documentation determines whether the unit will be approved for operation by the Distribution System Operator (DSO).

More on transformer testing standards and certification can be found in publications from the IEC Webstore, where current editions of the IEC 60076 standards and guidelines for routine and special tests are available.

And so its factory journey ends – the transformer, which has been through design, core, windings, tank, drying, oil, and tests, is ready to hear the hum of the grid for the first time and to see the world not through an engineer's microscope, but through the current that begins to flow within it.

Conclusion

The production of an oil transformer is a fascinating journey from an idea to a finished source of energy – a journey where engineering meets patience, and precision meets practice. Every stage – from design to final testing – is a testament to the fact that reliability is not born by chance, but from consistency and a respect for detail.

For years, we have supported designers, contractors, and grid operators in selecting solutions that will stand the test of time and operating conditions. We help choose the right type of transformer, optimize cooling, select oil and insulation systems for specific environments, and plan maintenance over the entire lifecycle of the equipment.

If you are working on a project where reliability, energy efficiency, and compliance with Ecodesign Tier 2 are crucial, we are here to translate technical requirements into real-world solutions.

Discover Energeks’ middle voltage transformers solutions, including:

• MarkoEco2 Ecodesign Tier 2 Oil Transformers – Selection of power rating, parameters, and cooling for specific environmental conditions.

• TeoEco2 Tier 2 Cast Resin Transformers – For facilities with high safety requirements and limited space.

• Units available immediately, full documentation, 60-month warranty – for selected medium voltage models.

If you want to stay updated with our technical analyses, practical tips, and case studies from construction sites, join the Energeks community on LinkedIn. It's a place where we share knowledge without marketing fluff – substantively, practically, and with respect for the industry we help build.

Thank you for your trust and the opportunity to be part of projects where sense, precision, and safety are as important as innovation. If you need to clarify technical requirements, select a model, or prepare an acceptance checklist for your investment – just send us a message.

Let's do it together.

References:

1. IEC 60076 1-3 – Power Transformers. International Electrotechnical Commission

2. CIGRÉ Technical Brochures

3. MDPI Energies - MDPI researches

4. Siemens Energy - Power Engineering Guide

Imagine your photovoltaic installation working at full power in the middle of the day, while the production line in the hall next door is on hold. Kilowatt hours slip away, sent to the grid at rates that do not generate a real return.

In the evening, when machines start up and demand grows, you buy electricity from the socket at a higher price than you sold it. Most industrial companies know this paradox all too well.

This is where an energy storage system comes in, like a "safety accumulator" that turns your PV installation into a true tool for cost optimization and process stability.

Why are we writing about this? We have been integrating PV systems with energy storage in industrial facilities for years and we know that the devil is in the details.

A poorly chosen energy storage system will not only fail to solve problems but can become an expensive burden.

This text is for industrial facility managers, installation designers and investors who want to know: can an existing PV installation be combined with an energy storage system?

What are the technical, regulatory and economic requirements?

After reading you will know not only how to connect PV with storage but, above all, whether it is worth it and in which business model it will generate real gains and a competitive advantage.

Agenda:

• Why PV and energy storage integration in industry is a game-changer?

• Can an energy storage system be added to an existing PV installation and under what conditions?

• Technical aspects of integration: inverters, measurement systems, protections.

• Regulatory requirements and the role of the distribution system operator (DSO).

• Business models and return on investment – the numbers that matter.

• Situational models: food industry, logistics and metallurgy.

• Four most common mistakes when integrating PV with energy storage (and how to avoid them).

• The future: energy storage systems as a standard in industry.

Reading time: approx. 12 minutes.

1. Why PV and energy storage integration in industry is a game-changer?

In the industrial world there is no room for chance. Every kilowatt of energy here is like currency that is counted more carefully than in an airport exchange office. Photovoltaics deliver cheap power but operate on their own schedule. When the sun shines, there is production. When it sets, the party is over. For a production line that needs electricity at 3 a.m., that is not very useful.

This is where an industrial energy storage system enters the stage – like a well-mannered waiter who not only collects the surplus from the table at lunchtime but serves the dishes when you are actually hungry.

Thanks to this:

• On-demand self-consumption becomes reality. Energy from your own PV system goes exactly where and when you need it without losses and frustration. This is why industry reports often highlight the term "industrial solar plus storage integration."

• Peak cost reduction is no longer theory. In tariffs for large industrial consumers whether in Poland, Germany or Spain it is not just about kilowatt hours but about contracted capacity. An AC coupled storage system acts like a shock absorber taking the hit during peak hours and avoiding penalties worth tens of thousands.

• Production continuity is secured. Some industrial processes such as glass melting, meat cooling or paint lines cannot tolerate interruptions. Storage works like an industrial-scale UPS and guarantees safety that even the best grid contract cannot provide.

• Grid support and system services are an increasingly attractive business model. In the UK or California industrial plants already earn money by providing services like frequency response. In other words you get paid because your storage system "breathes" with the grid.

Does it sound futuristic?

Not really. The numbers are very real. BloombergNEF reports that the cost of lithium-ion batteries has fallen by 80% since 2013.

And that is not the end. The IEA Renewables 2023 report predicts that by 2030 the global installed capacity of energy storage will quadruple reaching more than 1 terawatt hour.

For comparison that is enough energy to power the entire European railway system for almost two years. Or to give every person on the planet dozens of hours of Netflix without interruption.

Integrating PV with energy storage in industry is therefore not a luxury or a "green whim."

It is a real game-changer that turns chaotic sunlight into predictable and controlled power – exactly what factories that count every kilowatt hour need.

2. Can an energy storage system be added to an existing PV installation and under what conditions?

This is one of the questions we hear most often in industrial halls and at investor meetings:

“We already have a PV installation. Can we really connect an energy storage system to it, or do we have to rebuild everything from scratch?”

The answer is: yes, you can. But the whole truth comes after the "but."

In practice it is a bit like upgrading a car. You can add a turbocharger, but not every engine and gearbox will handle such an upgrade.

Key factors:

• Type of PV inverter
  If your facility uses hybrid inverters, the road is straightforward. The storage system integrates with them directly via the DC interface. But if you have a standard string or central inverter, you will need an additional battery inverter and an AC coupled configuration. This solution is used in over 70% of retrofitted industrial installations worldwide because it offers flexibility without replacing the entire infrastructure.

• Connection system
  In many factories the PV installation is connected to the main medium voltage switchboard. Adding storage often means rebuilding one field, and sometimes installing a new switchboard with dedicated protection. This is where retrofit energy storage integration with existing PV plants in industrial facilities becomes a practical reality.

• Conditions from the distribution system operator (DSO)
  Operators take different approaches, but the common denominator is simple: if the storage system affects power flows in the grid, you must update the connection conditions. In Germany, the procedure is mandatory for storage systems above 135 kW, in Spain the threshold is 100 kW, and in Poland 50 kW. Average waiting time for new conditions? From 2 to 6 months depending on the region.

• Connection capacity and short-circuit analysis
  Storage systems not only accumulate power but also discharge it with significant output. This requires analyzing short-circuit flows and adjusting protection systems. In practice, every project above 500 kWh today requires simulation in software such as DIgSILENT PowerFactory or ETAP.

To illustrate: according to Fraunhofer ISE, in 2023 more than 40% of energy storage projects in Europe were retrofits of existing PV installations.

So integration is possible, but it always requires a technical audit and often paperwork.

The good news? In 80% of cases you can "finish the coffee with the same cup," meaning you can add storage without replacing the entire PV system. The bad? In the remaining 20% the cup breaks and you need a new one, which means modernizing part of the infrastructure.

In short, to answer the question “can you connect an energy storage system to an existing PV installation?” – yes… as long as you give engineers the time and tools to check whether your system is ready for such integration.

You may be interested also:

How to choose an energy storage system for PV: 5 answers that change everything

3. Technical aspects of integration – engineering in practice

Adding an energy storage system to a PV installation in an industrial plant may sound like simple math: here is a panel, there is a battery, connect a cable and you are done. Reality? It is more like a Tetris puzzle, where every block has to fit perfectly, otherwise the whole tower collapses.

AC coupling or DC coupling?

This is the first question raised in any design office.

For retrofitting existing industrial PV installations the most common choice is an AC coupled storage system. The storage is connected on the AC side, to the same switchboard where the PV inverters are installed. This makes it possible to add batteries to an already operating installation without major changes. One must remember, however, that every additional conversion (DC–AC–DC–AC) causes losses of up to 6–10%.

For new projects hybrid inverters with DC coupled storage systems are increasingly used. This solution reduces conversion losses to as little as 2–3% and significantly improves overall efficiency. In practice, integrating PV with energy storage via a hybrid inverter is now the standard in newly built industrial plants, especially where the goal is to maximize self-consumption and achieve fast ROI.

BMS – the brain of the operation

Every industrial storage system has its own Battery Management System (BMS). It works like a personal trainer: making sure cells do not overheat, charge evenly and do not fall into a dangerous "energy crash." Without a functioning BMS, even the most efficient lithium-ion cells can fail faster than a teenager’s phone during a gaming session.

Protection and standards

Safety cannot be forgotten. When an industrial-scale 1 MWh storage system “sneezes,” the effect is far more dramatic than a kettle shorting out in the office. This is why the following are required:

• overcurrent switches and isolators,

• fire suppression systems (often gas-based, such as Novec 1230),

• certification compliant with PN-EN 50549, IEC 62933 or UL 9540A, depending on the market.

EMS – who calls the shots

At the end of the chain is the Energy Management System (EMS). It decides when the storage system charges and when it discharges. In practice, EMS is the digital conductor of the orchestra that must coordinate:

• PV production,

• the plant’s consumption profile,

• energy prices (if the system operates with arbitrage),

• sometimes also instructions from the capacity market or ancillary services.

Without EMS the storage operates chaotically and instead of saving money, it can actually increase costs.

Cooling

For small systems (around 50 kWh) ventilation is sufficient. But industrial systems of 1–5 MWh require HVAC with active cooling and humidity control. According to DNV GL research, proper cooling can extend the lifetime of lithium-ion cells by 25–30%. Without it, batteries degrade faster than a server in an overheated server room.

Integrating PV with industrial energy storage is more than just connecting cables. It is precise orchestration of inverters, protection systems, EMS and cooling. Every detail from equipment type to safety standards determines whether your system will deliver savings for 15 years or turn into an expensive toy after two seasons.

4. Regulatory requirements and the role of the DSO – paperwork that decides the system launch

Adding an energy storage system to a PV installation in industry is not only a technical challenge.

In many cases the bigger problem turns out to be… paperwork. The distribution system operator (DSO) must know that the plant connected to the grid will not turn into a "wild horse." That is why regulatory procedures are essential.

United Kingdom – flexibility but also responsibility

In the UK operators (DSOs) take a more market-driven approach. Adding storage to PV requires registration under a G99 application (for systems above 16 A per phase). Formalities include:

• providing technical data of the inverter and battery,

• agreeing on fault ride-through procedures,

• simulations of the impact on grid frequency and voltage.

The advantage? In many regions the process can be accelerated if the storage system can provide ancillary services such as frequency regulation within the National Grid program. In that case approval can be granted in as little as 6 weeks.

Poland – thresholds and procedures

In Poland every PV installation above 50 kW must be approved by the DSO. Adding storage means:

• updating connection conditions,

• providing single-line diagrams,

• certificates of compliance of inverters and storage with PN-EN 50549,

• conducting commissioning tests including power quality measurements and simulations of behavior during voltage loss.

The average waiting time for a DSO decision is 3 to 6 months. The most common problem is documentation. If diagrams are incomplete the process starts over.

Germany – Ordnung muss sein

In Germany the Mittelspannungsrichtlinie (MV Directive) applies and requires registration of every storage system above 135 kW. In practice this means:

• the need to conduct a grid impact analysis,

• consultation with a certified expert (Sachverständiger),

• mandatory tests of automatic disconnection during voltage loss.

Interesting fact: according to Fraunhofer ISE, more than 30% of applications are rejected due to incomplete forms not because the system is unsuitable but because someone filled in the paperwork incorrectly.

Spain – faster but with a catch

Spain has a rapidly growing PV and storage market, but operators require approval already for systems above 100 kW. The procedure is simpler than in Germany but there is a balancing condition. The company must demonstrate that adding storage will not cause uncontrolled feed-in to the grid.

In practice this means using EMS systems with a zero feed-in function that limit export when there is no demand in the facility.

What does this mean?

Although regulatory differences between Poland, Germany, Spain and the UK are significant the common denominator is clear: without DSO approval the system will not start.

Each market has its own thresholds (50 kW, 100 kW, 135 kW…), but the idea remains the same. A storage system is not just an "accumulator" it is an active participant in the power system.

That is why when preparing a project it is worth planning time for procedures. Often they decide whether the investment goes live in one year or in two.

Worth to read:

Earning light: how Germany is building an energy edge with power storage

5. Business models and return on investment – why CFOs should love energy storage

When the term "energy storage" comes up in a boardroom, reactions are often polarized. The technical team nods with enthusiasm, while the CFO frowns and asks: “How much will it cost and when will it pay back?” Fortunately this is no longer a science fiction topic. Today you can answer that question very concretely.

Self-consumption as the foundation of ROI

In industrial plants the key business model is increasing self-consumption of PV energy.

If a 500 kWp installation produces 550 MWh annually and the facility consumes most of its energy in the evening, then without storage as much as 30–40% of the energy is exported to the grid.

With feed-in tariffs 40–60% lower than the price of purchasing energy from the grid, the financial balance quickly becomes unattractive.

A 1 MWh storage system can raise self-consumption from 60% to as much as 90–92%. In practice this means annual savings of €65,000–€85,000 in a medium-sized plant in Central Europe. ROI? 5–6 years, and with rising energy prices even shorter.

Reduction of contracted capacity and peak charges

In logistics or heavy industry the biggest cost is not always energy itself but charges for peak demand. Each time contracted power is exceeded (for example in tariff categories such as C21 or B23) penalties can run into tens of thousands of euros per month.

Here storage acts like a shock absorber – it evens out the peaks by injecting energy into the facility’s grid exactly when demand exceeds the limit. This brings a rapid financial effect.

In logistics centers ROI can drop to 3–4 years, because you avoid penalties that were previously unavoidable.

New revenue streams – arbitrage and system services

In more advanced markets such as Germany, the UK or Spain, industrial storage systems earn money not only on self-consumption and peak shaving. A third revenue stream is emerging: price arbitrage and ancillary services.

• Price arbitrage – the EMS charges batteries when electricity is cheapest (for example at night in dynamic tariffs) and discharges them when prices rise. In the UK the difference between nighttime and daytime peak prices can reach 200–300%, which can shorten ROI by an additional year.

• System services (frequency response, demand response) – in Germany a plant with storage can sign a contract with the grid operator and receive payment for frequency stabilization.

  Typical rates are €20,000 to €50,000 per year for each MW of available capacity.

  ---

  6. Situational models – energy in numbers that everyone can feel

  Big numbers often sound abstract. 1 MWp? 2 MWh? For most people that looks like codes from a vacuum cleaner manual. That is why it is worth looking at them through the lens of everyday struggles – the same ones we all know, only on an industrial scale.

  Food industry – a cold store that cannot stop

  Imagine your home refrigerator. When the power goes out, after an hour the butter starts melting and the ice cream turns into watery soup. Now scale that problem up to a hall full of cold stores and freezers holding hundreds of tons of food. Every hour without energy equals hundreds of thousands of euros in losses.

  A PV installation with 1 MWp capacity produces over 1.1 GWh annually – which seems a lot, but without storage a significant portion flows into the grid. Adding a 2 MWh storage system increased self-consumption by 25%. The effect? Annual savings of about €90,000.

• In short:

  • PV installation: 1 MWp

  • Production: 1.1 GWh/year

  • Storage: 2 MWh

  • Effect: +25% self-consumption, €90,000 annual savings

  • ROI: 6 years

  That is like someone paying your household electricity bills for six years straight and throwing in fiber internet on top.

  Logistics center – nerves over peak demand

  We all know the moment when you turn on the washing machine, oven and kettle at once – and suddenly the fuse blows. Now imagine that in a logistics hub where dozens of forklifts are charging while a parcel sorting system is running. One such “peak” in demand and the bill jumps by tens of thousands of euros per month, because the operator charges a penalty for exceeding contracted capacity.

  The solution turned out to be a 1 MWh storage system. It acts like a shock absorber – charging when the system is calm and discharging during sudden peaks. The effect? Penalties reduced by 70% and €75,000 in annual savings. ROI: 3.5 years.

• In short:

  • PV installation: 800 kWp

  • Storage: 1 MWh

  • Effect: 70% reduction in peak demand penalties, €75,000 annual savings

  • ROI: 3.5 years

  Is like your apartment paying off the mortgage on a new kitchen by itself, just because you stopped overloading the electrical system.

  Metallurgy – when power must never falter

  Melting metals is a process much like baking bread. If you turn off the oven halfway through because of a power cut, there is no saving the result. In metallurgy every voltage drop means not only lost production but also the risk of damaging furnaces worth millions.

  Here a 5 MWh storage system not only increased reliability but also improved power quality – reducing harmonics and cutting reactive power losses. On top of that the plant started earning from ancillary services by helping the operator stabilize grid frequency. The result? More than €220,000 per year in combined savings and additional revenue, with ROI in 5 years.

• In short:

  • PV installation: 2.5 MWp

  • Storage: 5 MWh

  • Effect: improved power quality, reduced harmonics, lower reactive power losses, + ancillary services revenue

  • Total: over €220,000 annual savings and earnings

  • ROI: 5 years

  Like your oven not only baking bread but also getting a bank transfer for keeping the neighbor’s kitchen warm.

  Conclusions?

  Numbers may sound like industry equations, but in reality they show a simple truth: an industrial energy storage system works both as a safety buffer and as a savings calculator. In everyday life, ordinary people know the same frustrations – power not available when needed, bills higher than expected, and equipment that cannot handle interruptions. On an industrial scale the stakes are not melted ice cream but million-euro costs and competitive advantage.

  ---

7. Four most common mistakes when integrating PV with energy storage (and how to avoid them)

Integrating PV and industrial energy storage is a long-term investment, but just a few wrong decisions can turn it into an expensive lesson. Here is a list of mistakes that repeat across the world – from Poland to Germany to Spain – and how to avoid them.

1. Storage system too small

This is the most common trap. Companies often choose a 200–300 kWh system because it seems “just right,” but the actual needs of the plant are several times larger. The result? The storage discharges in an hour and does not fulfill its purpose. It is like buying a tiny phone powerbank – after one charge you are back at the socket.

How to avoid it? Analyze your energy consumption profile over at least 12 months. Choose a storage size that covers at least 2–3 hours of plant operation at average load.

2. No EMS (Energy Management System)

Without an intelligent controller the storage charges when the sun shines and discharges when… it is not necessarily profitable. Instead of saving money, the company can generate additional losses.

How to avoid it? Invest in an EMS that considers PV production forecasts, energy prices and the plant’s consumption profile. It is the heart of the entire system – without it you only have an expensive battery, not a tool for optimization.

3. Underestimating battery cooling

Lithium-ion cells do not like heat. Every 10°C increase in temperature shortens their lifespan by up to half. For systems above 500 kWh active cooling and humidity control are essential. Without it the battery wears out faster than an office air conditioner in summer.

How to avoid it? Plan for dedicated HVAC and regular servicing. This is not an extra cost but an investment in 20–30% longer storage lifetime.

4. Ignoring formalities with the distribution system operator (DSO)

Many investors skip this step, hoping it will “work itself out.” Later it turns out that system launch is blocked by missing operator approval. Sometimes you wait six months longer, and ROI shifts by years.

How to avoid it? Include regulatory procedures in the project timeline. Each country has its own thresholds (Poland – 50 kW, Spain – 100 kW, Germany – 135 kW). The sooner you start discussions with the DSO, the fewer headaches at the end.

These four mistakes – wrong system size, no EMS, weak cooling and missing DSO formalities – account for more than 70% of problems in industrial storage projects. With the right audit and planning you can avoid them and build a system that runs smoothly for the next 15–20 years.

8. The future of energy storage – standard, not luxury

Just a decade ago industrial energy storage systems were seen as a futuristic gadget for pioneers. Today it is clear: they are not a luxury but a cornerstone of competitiveness. The IEA forecasts that by 2030 the global installed capacity of storage will quadruple, and BloombergNEF points out that the cost of storing 1 kWh of energy will fall by another 40% compared to 2020.

This means that in a few years the question will no longer be “should we install storage?” but “how large should the system be and how should it be integrated?”

In Germany every third new PV installation in the industrial sector is already being designed with batteries included. In Spain support programs accelerate the adoption of solar plus storage systems, and in the UK plants are earning from ancillary services faster than analysts expected.

The trend is irreversible. Companies that do not start thinking about integration now will wake up in a few years with higher bills and less flexibility in the market.

From inverters to EMS to the quality of grid infrastructure – every element matters.

At Energeks we keep it simple. Our role is not only to help integrate storage with PV installations but also to make sure that all the energy you produce and store actually works for your business.

That is why we rely on our Tier 2 Ecodesign oil-filled and cast resin transformers – practically lossless, ensuring that nothing leaks away in cables or cores. This matters to us because we know every kilowatt counts, and in your facility what matters is not theory but real results.

The future of industry is not about technology but about decisions.

Energy storage and modern medium voltage transformers are no longer a “premium option” but tools that determine safety and profitability.

If you are an investor, designer or industrial facility manager and you want to:

• increase PV self-consumption,

• secure process continuity,

• gain a competitive edge with Tier 2 technology,

we are open to partnership and collaboration. We believe the most is achieved not alone but by working together – with clients, designers, operators and suppliers.

Thank you for your time and attention in reading this article.

If the integration of PV and energy storage is relevant to you, we invite you to start a conversation. Together we can build a system that not only works but drives your business results – without losses, without compromises, in the spirit of future-oriented energy.

Join our community on LinkedIn, where we regularly share knowledge, analysis and stories from the industry. We are eager to hear your perspective and experiences – because the real value lies in exchange.

Sources:

IEA – Renewables 2023 Report
https://www.iea.org/reports/renewables-2023

BloombergNEF – Energy Storage Market Outlook 2024
https://about.bnef.com/energy-storage

Fraunhofer ISE – Energy Storage Integration in Industry
https://www.ise.fraunhofer.de/en/research-topics/energy-storage.html

Cover Photo: Young777/2172501561

No-load losses in Tier 2 transformers. Iron, heat and capacitors, the hidden cost nobody sees.

Imagine a kitchen tap dripping once every few seconds.

For a week you ignore the noise. After a month you stop hearing it.

After a year you find out that you paid a water bill that doesn’t match your real usage.

No-load losses in transformers work in a similar way. A transformer connected to the grid consumes energy even when there is no load on the low-voltage side. It is the breathing of the core. It is the magnetization of the laminations. It is heat that quietly escapes and turns into the operating cost of the installation.

Tier 2 tightened the requirements on losses and made it possible to finally measure these differences objectively. This is good news for investors, contractors, designers and asset managers, provided they know which numbers matter and how to read them. In this text we serve it on a plate.

If you are looking for specifics, here you will find formulas, regulatory thresholds, examples of numerical calculations and practical tips on how to read catalog sheets and test reports according to IEC.

We will show you when a difference of a few hundred watts in P0 is worth the effort, and when it is better to invest in better steel, a larger core or a different insulating medium, because the whole TCO will drop already in the first years of operation.

We will also explain the role of capacitors. Let me spoil the ending right away. Capacitors do not reduce the no-load losses of the core, but they can lower currents in the grid and improve the balance of load losses as well as contractual penalties for cosφ.

What you will find inside.

First, briefly and in plain language, I explain what no-load losses are and where they come from.

Then we organize the Tier 2 requirements in the European Union and show what the permissible loss tables really change.

Next we move to money. We calculate how much each additional kilowatt of P0 costs in a year and over a horizon of twenty-five years.

Finally, we check where and when capacitors make a difference and how to select them so as not to fall into resonance and not worsen the situation.

Reading time. About 10 minutes

What no-load losses are and why they always occur

Let us start with the basics.

No-load losses P0 are the power lost by a transformer when it is energized at its rated voltage, while the secondary winding carries no load.

Put simply, this is the price you pay for the very fact that the core is being magnetized by a field at fifty hertz. P0 is mainly composed of losses in the magnetic core laminations.

There are two main mechanisms at play.

First, hysteresis, which is the energy required to take the material through its magnetization cycle. Second, eddy currents, tiny circulating currents induced in the plane of the steel sheets, which dissipate energy as heat.

In practice, P0 remains largely constant from no load to full load under sinusoidal supply, because the core essentially sees the same voltage and frequency. This is why P0 is often colloquially called iron losses. The measurement definition for P0 under no-load conditions and rated voltage can be found in IEC 60076 Parts 1 and 7.

Why this is a fixed cost

Because in real life transformers are rarely switched off.

In medium-voltage substations, PV farms, data centers and industrial switchgears, they run around the clock. That means 8760 hours per year, during which every additional 100 watts of P0 consumes 876 kilowatt-hours of energy.

Over a 25-year horizon, this amounts to 21,900 kilowatt-hours from just that tiny fraction of a kilowatt.

Now let’s put a European number on it. If the combined energy and distribution price is about €0.12 per kilowatt-hour (roughly €0.08–0.20 across EU countries in 2025, depending on sector and contract), then an extra 100 watts of P0 costs around €2,628 over the transformer’s lifecycle.

That means one extra kilowatt of no-load losses equals 8760 kilowatt-hours annually – a merciless factor. For comparison, that is the yearly consumption of a typical European household of 2–3 people.

Where differences in P0 between transformers come from

The shortest answer: from the quality and grade of steel, the technology of cutting and stacking the core, the core size, and the working flux density chosen by the designer.

Higher-quality material and a larger core mean lower no-load losses, but they also imply greater mass and a higher purchase price. The real decision therefore is not about buying cheaper or more expensive, but how to optimize the total cost of ownership (TCO) for the specific load profile.

With Tier 2, manufacturers were required to lower loss thresholds. As a result, many modern transformers achieve P0 values clearly below the tabular limits. We will explore those limits in the next section.

How do capacitors relate to P0?

This is the question that tempts many to search for a shortcut.

Unfortunately, capacitors have no influence on the core losses, because P0 is determined by the material, geometry, applied voltage and frequency. Reactive power compensation lowers currents in lines and windings, which can improve the balance of load losses and reduce penalties for cosφ, but it does not reduce the P0 component.

We will return to the role of capacitors in more detail in a dedicated section, together with resonance risks and sizing guidelines.

A practical control question

Suppose the price difference between two transformers is €3,000–€4,000, but the more expensive version has 300 watts less P0. Which option is cheaper after five years in a continuously operating installation?

In many cases, by the third year the higher-efficiency transformer breaks even, and by the fifth year it begins to generate real savings.

That is why, in Europe’s current energy landscape – with electricity costs rising and climate policies tightening – Tier 2 no-load loss optimization is no longer just a technical matter, but a financial and strategic one.

Tier 2 in practice. What the EU loss tables changed and how to use them

The Ecodesign regulations for transformers in the European Union brought long-awaited order to the topic of transformer losses.

First came the initial stage, Tier 1, effective from 1 July 2015. Then, from 1 July 2021, stricter limits known as Tier 2 were introduced. These include maximum permissible no-load losses (P0) and load losses (Pk) for medium-power transformers up to 3150 kVA, with a distinction between oil-immersed and dry-type designs.

The regulation also requires that documentation specifies the rated power, P0, Pk, and the Peak Efficiency Index (PEI) where applicable. This makes it easier to compare offers directly against the normative tables instead of relying solely on marketing declarations.

How to read the tables and not get lost in the symbols

Take, for example, a three-phase transformer rated 2000 kVA with a high-voltage winding up to 24 kV and a low-voltage winding up to 1.1 kV.

For this configuration, the Tier 2 table for oil-immersed units shows maximum no-load losses of about 1.305 kW. For dry-type designs of the same power, the corresponding Tier 2 table allows P0 of about 2.34 kW.

In practice, permissible values vary with voltage combinations and specific cases. For instance, for 36 kV windings or dual-voltage designs, correction factors apply that increase the permissible limits.

It is therefore crucial to compare offers within the same voltage class and under the same design assumptions. Otherwise, you are comparing apples to pears.

What about units above 3150 kVA?

For larger transformers, the regulation focuses primarily on minimum PEI values. This does not mean that P0 stops being important.

On the contrary. PEI depends on both P0 and Pk, as well as on the load point at which efficiency is maximized.

Documentation should include both the PEI and the load level at which it occurs. If in doubt, demand from the manufacturer a complete data sheet with test results and calculation methods in accordance with IEC standards.

From regulation to money

Now comes the most pleasant part, because numbers simplify decisions.

Let us assume you are comparing two transformers in the same voltage class and with the same rating. One has P0 = 2.0 kW, the other P0 = 2.6 kW. Both are within the permissible Tier 2 limits for the configuration, but the second is 0.6 kW worse.

The difference in energy consumption due to no-load losses is 0.6 kW × 8760 hours = 5256 kWh annually.

At a total price of around €0.12 per kilowatt-hour (average combined energy and distribution cost across EU member states), you are paying about €631 every year just for that difference. Over 25 years, that adds up to roughly €15,780.

Even if the transformer with better steel is heavier and costs more in transport, the total cost of ownership (TCO) often drops significantly, especially where transformers are never switched off. It sounds simple – because it is – but only with Tier 2 did these comparisons become repeatable and quantifiable.

Why investors sometimes overvalue Pk at the expense of P0

Load losses Pk are most painful on sunny days and during production peaks, so they appear more visibly in reports. P0, on the other hand, keeps adding costs silently every day, including during idle periods and off-season.

If the installation runs continuously, every excess in P0 is a guaranteed expense.

It therefore makes sense to split the strategy. For facilities with highly variable loads, you should optimize Pk together with voltage regulation and cooling. For facilities operating seven days a week, you need to pay more attention to P0, because it dictates the baseline bill.

IEC documents define the measurement of P0 in a repeatable way, and Ecodesign enforces transparency of data in catalogues and nameplates.

A note on data quality

It happens that some offers list values like P0 ≤ 2600 W. Such a statement does not tell you what the manufacturer actually achieves in testing. Always demand figures with decimals and type-test reports according to IEC 60076.

This is not nitpicking against manufacturers, but standard purchasing practice for assets that will stay with you for decades.

Why a 5 kW difference means hundreds of thousands of euros over 25 years

No-load losses and the investor’s wallet

From the perspective of an investor or asset manager, every figure in the loss table translates directly into money. Imagine a 2000 kVA transformer with no-load losses of 15 kW. Another manufacturer offers a similar transformer, but with P0 = 20 kW. On paper, 5 kilowatts may look like a minor detail. In practice, it means an extra 5 kW drawn continuously for 8760 hours per year – that is 43,800 kilowatt-hours of energy that no one used but someone must pay for.

A 25-year calculation

At an average European electricity price of €0.12 per kWh (energy plus distribution), the annual cost difference is €5,256. Over 25 years, that adds up to €131,400.

This is not an abstraction. It is the equivalent of a new electric vehicle, an additional solar tracker for panels in a PV farm, or even a year’s maintenance budget for an entire transformer substation.

Why do tenders often overlook this?

Because most of the attention focuses on the transformer’s purchase price, transport, or foundation costs. No-load losses get lost in the table among dozens of other parameters. On top of that, sales teams often state values like “≤20 kW” without giving the actual measured figure.

It is like buying a car with a brochure that says, “consumption no more than 10 l/100 km”. In reality, it could be 7 or 9.9. Both are technically within the spec, but over years the cost difference becomes enormous.

The takeaway

A small difference in P0 is not a detail – it is money leaking systematically. Anyone comparing offers should convert watts into euros over a 20–30 year horizon before making a decision.

The role of capacitors – hidden ally or unnecessary ballast?

Capacitors and no-load losses

Let’s bust a myth first. Capacitors do not reduce core no-load losses. P0 is determined by the physics of iron, not by reactive power flows. The only way to reduce P0 is by improving the core material, its mass, or the manufacturing technology.

Where capacitors really make a difference

Capacitors play a key role in reactive power compensation. They improve the power factor (cosφ), which lowers currents in cables and transformer windings. This, in turn, reduces load losses (Pk), which are proportional to the square of the current. In other words, capacitors won’t touch P0, but they can significantly improve the loss balance of the whole installation.

How much capacitor power is needed?

That depends on the load profile and type of consumers. If a medium-voltage substation supplies equipment with a large share of induction motors, compensation may require several hundred kvar. In PV farms or energy storage facilities, values are usually smaller but still relevant – often in the range of 50–200 kvar. The rule of thumb is clear: capacitors should be sized to keep cosφ at the level required by the distribution system operator, typically above 0.95.

The resonance trap

Care must be taken to ensure that compensation does not enter resonance with network harmonics. Sometimes capacitors, instead of helping, worsen the situation by causing overvoltages or overheating. This is why modern substations often use detuned capacitor banks with reactors, or even active power factor correction systems.

Capacitors and investment strategy

So, are capacitors worth investing in? Yes – but not as a magic solution for P0. Their role is to reduce load-related losses, improve energy quality, and avoid penalties from the grid operator. In a well-designed system, capacitors can lower total energy losses by 5–10%, improving the transformer’s economic efficiency, particularly under heavy inductive loads.

How to read transformers technical data sheets and manufacturer offers

“≤30 kW” versus “exactly 28.7 kW”

At first glance, both notations look correct. The problem is that the “≤” symbol gives the manufacturer a wide margin – in reality, the transformer may have no-load losses of either 19 or 29.9 kW. In both cases it complies with the standard, but the difference in operating costs amounts to tens of thousands of euros. That is why you should always demand a precise value with a decimal point. This is not a whim – it is standard engineering practice.

IEC type test reports

A catalogue is one thing, but an IEC 60076-compliant type test report is another. The report shows the actual measured loss values, not just the manufacturer’s declarations. In tenders and technical acceptance procedures, it is worth requesting such documents. It is similar to demanding certified fuel consumption tests from a car manufacturer – only then can you be sure the data is real.

Language and marketing traps

In offers you will find terms such as “optimized core”, “innovative design” or “energy-efficient construction”. They sound good, but until you see a hard P0 figure, it is just marketing. Always look at the loss table, not the adjectives.

How to compare offers step by step

• Select transformers with the same rated power and voltages.

• Place P0 and Pk values in a table with accuracy to the watt.

• Multiply the differences by 8760 hours per year and the electricity tariff.

• Project the result over 25–30 years of operation.

• Compare the total with the purchase price difference between transformers.

This simple algorithm shows that “more expensive at the start” very often means “cheaper over the entire lifecycle”.

The myth of the heavier transformer – does heavier always mean better?

More iron = fewer losses?

In many technical discussions there is a myth that the heavier the transformer, the better it is. There is some truth in this. A larger core with more laminations allows for lower flux density and lower no-load losses. But a heavier transformer also means higher costs for transport, foundations, and installation.

A comparative example

Suppose we have two 2500 kVA transformers. The first weighs 6.5 tonnes and has no-load losses of 5.8 kW. The second weighs 7.5 tonnes and its P0 is 5.1 kW. The 0.7 kW difference means about 6130 kWh saved annually. At a European average price of €0.12 per kWh, this equals about €735 per year. Over 25 years, that is roughly €18,375.

The question is: will the extra transport and foundation cost for the heavier transformer outweigh these savings? Often not – but you have to do the calculation.

When lighter beats heavier

If a project requires installation in a hard-to-reach location, where transport and cranes are extremely costly, a lighter transformer may be preferable despite higher losses. This is especially true in prefabricated transformer substations, where mobility and limited space matter – in such cases, weight becomes a real factor.

Heavier does not always mean better. Instead of evaluating by tonnes, you should evaluate by the balance of total cost of ownership (CAPEX plus OPEX). Then it becomes clear that sometimes it pays to add 100 kg of steel, and sometimes it is smarter to optimize logistics and foundation costs.

No-load losses are not a detail, but a strategic decision

No-load losses in transformers are not just “a tiny number in the datasheet”. They are a fixed cost that runs day and night, regardless of the load. Tier 2 standards have enforced greater transparency, but only a conscious approach by the investor, designer, and asset manager turns those numbers into real savings.

We have shown that just 1 kW of no-load losses equals nearly 9 MWh per year.

Over a 25-year perspective, this means hundreds of thousands in currency that can either stay in the budget or silently vanish into electricity bills. We also discussed the role of capacitors. They are not a tool for reducing P0, but a key element in reactive power compensation and in stabilizing the entire installation.

Well-designed capacitor banks reduce load losses, help avoid penalties from the grid operator, and improve the economic performance of the transformer.

For the investor, the key lesson is simple: look at the total cost of ownership (TCO), not just the purchase price.

Datasheets must be read critically, IEC test reports demanded, and watts converted into money. The transformer’s weight, price, or size is only part of the puzzle. Only by summing up all elements do you get the true picture.

Our approach

At Energeks, we have been designing and delivering medium-voltage transformers, prefabricated substations, and switchgears for years. In our portfolio you will find Tier 2 medium-voltage oil-immersed transformers as well as dry-type transformers, all designed to optimize no-load and load losses throughout the entire lifecycle. We support our partners at every stage of project execution – from concept, through transformer selection, to commissioning and service.

If you are looking for a partner who will not only deliver a transformer but also help you realistically calculate and optimize costs over decades – let’s talk.

Join the Energeks community of energy enthusiasts and professionals on LinkedIn

Sources:

EUR-Lex. Commission Regulation EU No 548/2014/ Loss Tables Tier 1 i Tier 2.

IEC 60076. Definitions of no-load loss measurement and test principles.

Schneider Electric. Transformer reactive power compensation and the role of capacitors.

A transformer can no longer "just work."

In the past, it was enough for a transformer to simply operate. It ran without failure, hummed quietly in the background, and no one really asked questions. But times have changed. Today, power equipment must not only be reliable but also energy-efficient.

And a transformer that consumes electricity at night just to stay on standby must now justify itself. To the client. To the auditor. To the planet.

The EU’s Ecodesign Tier 2 directive is not a bureaucratic whim. It’s a real paradigm shift: if something wastes energy, it has no right to exist. Since July 2021, new rules have been in force and they’ve changed the game for all transformer manufacturers.

And for investors and designers? It’s a test of attention to detail: what are you really buying, and how much does it actually cost over the product’s lifetime?

In this article, we’ll cover:

• what a Tier 2 compliant transformer is

• what the requirements and standards are

• how it differs from previous models

• what it delivers in practice and in your budget

• how to translate energy savings into something more tangible than “kWh”

Reading time: 8 minutes

What a Tier 2 compliant transformer is

In short? It’s about reducing energy losses in standby mode and under load. A transformer compliant with Tier 2 must meet stricter energy efficiency requirements defined by Commission Regulation (EU) 2019/1783.

That means:

• significantly lower no-load losses, i.e. the energy consumed when the transformer is energized but not transmitting power

• optimized load losses, related to current flow through windings and voltage drop

• a special core design – often based on high magnetic induction and low-loss steels, such as HI-B (High-Grade Grain-Oriented) or amorphous metals (metglass), which have 70–80% lower magnetic losses compared to standard materials

What does this mean in practice?

Take, for example, a 1000 kVA MV transformer. An older Tier 1 compliant design may generate 12,000 kWh of no-load losses annually. This means that even when it’s not transferring energy – it’s using electricity. Like a refrigerator running with nothing inside.

The Tier 2 version reduces those losses to 8,000 kWh per year – saving 4,000 kWh. At an average price of 0.80 PLN/kWh, that’s 3,200 PLN annually. In euros? Around €740 per year. Over 30 years? €22,200 in avoided losses. And we’re talking about just one transformer.

What does that mean in real-world terms?

We like to convert savings into something tangible:

• 4,000 kWh is about 5 months of electricity for an average household (in the EU, annual consumption is around 8,000 kWh)

• €22,200 is enough to build a multi-use sports field for students in a rural municipality

• or: more than 42,000 loaves of bread (€0.50/loaf)

• or: 8 years of free LED lighting for a high school

So?

If your company operates ten transformers, switching to Tier 2 means potential savings of €220,000 – enough to sponsor an entire village with green energy

Why a Tier 2 transformer is more efficient

• Lower magnetizing current – thanks to reduced magnetic hysteresis in HI-B steels, the transformer needs less energy to “wake up”

• Better passive cooling – lower losses = less heat = less work for the cooling system

• Larger winding cross-sections = lower resistance = reduced Joule losses

This isn’t innovation for the sake of trendiness. It’s engineering done right – once and for all. Because true efficiency isn’t about miracles. It’s about good decisions and long-term thinking.

What are the specific Ecodesign requirements

EU Regulation 2019/1783 does not beat around the bush: since July 1, 2021, all new transformers placed on the EU market must meet the Ecodesign Tier 2 requirements. What does that mean? Time to say goodbye to “energy chewers” that just sit and hum while consuming electricity like an old bathroom heater.

What exactly does the regulation say?

The requirements are precise – these are not “recommendations” or “goals to consider,” but hard limits:

• No-load and load losses – must be below the Tier 2 limit values, depending on the transformer type (oil-immersed, dry-type, distribution).

• Core and winding design – you can’t “do it the old way” anymore. Modern materials are required (e.g., B23R080-grade steel, amorphous metals), and often more copper mass too.

• CE marking and declaration of conformity – without these, the product cannot be legally placed on the market.

• Ban on using cooling fans to meet the limits – only passive efficiency counts, no artificial "fine-tuning."

• Technical documentation – must include detailed performance and loss data measured according to EN 50708-1-1.

  ---

How does it look in practice?

If you're designing a transformer station, you need to know during the tender or ordering phase whether a model meets these limits. Because you can’t “tighten efficiency” later like a bolt. It all starts with the core geometry and number of turns.

What’s more – the documentation must include specific parameters measured at 75°C. And no – they cannot be “rounded up.” That’s why many manufacturers redesigned their transformers from scratch instead of “lifting” old constructions.

How much does this save in euros?

With an average loss reduction of 3,000–5,000 kWh annually (compared to older models), and a cost of €0.20/kWh, the savings amount to €600–1,000 per transformer per year. And that’s just one!

For a medium-sized industrial plant with five transformers? That’s up to €5,000 saved annually – the cost of a new forklift, equipment for a production hall, or... full funding for an energy monitoring system.

Is it worth investing in “invisible savings”?

Imagine you have a fleet of company cars, and each one consumes 1 liter of fuel per day... idling. No one’s driving, no work is being done, but the tank is draining. Over a year, that’s hundreds of liters. And what – you turn a blind eye because “that’s how it’s always been”?

Tier 2 is the decision not to look away. To stop wasting electricity on idle operation.

To make sure every kilowatt-hour makes sense. Not out of obligation – out of common sense.

What standards must be met (and what do they actually mean)

The Ecodesign Tier 2 requirements don’t exist in a vacuum. They’re based on very specific technical standards that determine whether a transformer can legally be placed on the EU market. And no – this isn’t a matter of the manufacturer’s “good will.” It’s strict certification that cannot be bypassed. And for a designer or investor? A clear warning: if a device lacks full documentation compliant with the standard – don’t even touch it with a stick.

Three key standards you need to know

• EN 50708-1-1 – the core standard for power transformers. It defines acceptable losses, test procedures, reference temperature (75°C), measurement accuracy, and design requirements. The backbone of Tier 2.

• EN 50588-1 – covers distribution transformers up to 3150 kVA. Regulates how to test efficiency, including lab conditions, temperature compensation, and the effect of rated voltage. Applies especially to dry-type and MV transformers in compact substations.

• ISO 50001 – the energy management standard. It doesn’t deal with transformer construction, but if you want your entire installation to be ESG or Green Deal compliant – a Tier 2 transformer is simply a must.

  ---

What does “standard compliance” mean in practice?

The standards specify:

• how to calculate losses (reference conditions, calibrated instruments),

• how to convert data for catalogues (e.g., to 20°C or 75°C),

• how to present technical data (you can’t list power at a voltage other than nominal without annotation),

• how to document test results – lab reports must include margin of error, certification, and the measurement pathway.

In other words: a transformer that doesn’t have verified compliance is not only a financial risk – it’s a risk for the entire investment. In an audit, this is the first thing they check: documentation from tests compliant with EN 50708. No docs? Out.

Standards are not just paperwork – they mean real gains

Some treat a “standard” like an unnecessary PDF attachment.

But do you know what non-compliance means?

• You might not get funding (many grant programs require Tier 2 transformers).

• Your insurer may refuse compensation after a failure – because the device wasn’t certified.

• The entire investment could be rejected at handover.

And that’s serious money: tens of thousands of euros in delayed payments, schedule delays, penalty fees.

Do you really need to know EN 50708?

It’s like traffic rules.

You don’t need to know all of them to drive. But if you don’t know what “no left turn” means, you’ll get a ticket sooner or later.

If you’re an investor, site manager, or project engineer – knowing EN 50708 won’t make you an energy law expert. But it will save your skin during project acceptance.

And that’s just smart business.

What is the difference between Tier 1 and Tier 2 in practice?

On paper? It’s just a different column in the loss limits table.

But in reality?

It’s like driving a car from the 90s versus a modern electric vehicle.

Both will take you from point A to B.

But one will guzzle fuel and growl, while the other does it quietly, efficiently, and economically.

Example: MV transformer 400 kVA 15/0.4 kV

A transformer compliant with Tier 1 (the older standard valid until 2021) generates no-load losses of about 550 W and load losses of 4,200 W. Over a year, this translates to roughly 39,700 kilowatt-hours of lost energy. At an average price of 0.20 euros per kWh, this means an annual loss cost of about 7,940 euros.

By comparison, a 400 kVA 15/0.4 kV transformer compliant with Ecodesign Tier 2 requirements has lower losses: 400 W in no-load state and 3,700 W under load. Annual losses are about 34,400 kilowatt-hours, translating to a cost of around 6,880 euros per year.

Annual gain? 1,060 euros. Roughly the cost of a new LV switchboard for a workshop hall.

Or five years of LED lighting in an office.

Example: MV transformer 630 kVA 15/0.4 kV

A 630 kVA Tier 1 transformer has no-load losses of about 800 W and load losses reaching 7,000 W. Per year, that’s around 62,500 kilowatt-hours of lost energy. At 0.20 euros per kWh, total loss cost is approximately 12,500 euros.

A 630 kVA transformer meeting Tier 2 requirements performs better:

600 W no-load losses and 6,200 W load losses. Annually, this equals about 55,000 kilowatt-hours of loss, with a cost of around 11,000 euros.

Gain? 1,500 euros per year. Enough to cover the cost of yearly inspections and oil testing in an entire transformer station.

Example: MV transformer 1600 kVA 15/0.4 kV

A large 1600 kVA Tier 1 transformer has no-load losses of about 1,800 W and load losses of 17,000 W. Annually, this means about 140,000 kilowatt-hours of energy lost as heat. At 0.20 euros per kWh, that’s a loss cost of 28,000 euros per year.

A 1600 kVA Tier 2 transformer reduces these values to 1,400 W in no-load state and 15,500 W under load. Annual losses amount to about 127,000 kilowatt-hours, with a cost of around 25,400 euros.

2,600 euros per year – that’s the gain. And over 30 years? 78,000 euros. Enough to afford a decent energy storage system for an entire production hall.

Where does the difference hide?

Magnetic sheets: Tier 1 uses standard grain-oriented steel, sometimes with lower induction. Tier 2 typically employs HI-B or even amorphous cores – reducing losses by 30–70%.

Windings: Tier 2 often uses thicker copper wire, lowering resistance and thermal losses. The transformer is heavier – but significantly more efficient.

Geometric design: Tier 2 requires more precise construction – better magnetic dispersion, reduced connection losses, optimized cooling.

Purchase price vs life cycle cost (LCC): Tier 1 units used to be 5–10% cheaper upfront. But after just a few years of operation, Tier 2 pulls ahead – and leaves its predecessor behind.

How does Ecodesign affect efficiency and profitability?

When we say "transformer profitability," most people think: "Well, the purchase cost, maybe transport, installation, and... that’s it." But that’s the real issue. The actual money doesn’t disappear during purchase. It quietly evaporates during operation – through unnecessary energy losses.

And that’s exactly what the EU’s Ecodesign Tier 2 regulation aims to fix.

What does higher efficiency bring?

A transformer compliant with Ecodesign Tier 2 is by design:

• more energy-optimized,

• loses less heat (hence less energy),

• has a longer lifespan thanks to lower operating temperatures,

• requires no additional cooling (lower maintenance costs),

• and generates a lower Total Cost of Ownership (TCO).

This isn’t opinion – it’s fact.

A transformer with 20% lower losses pays for itself in 3–6 years, and from then on… it works for you. For free.

Additional benefits: less visible but just as important

• Fewer failures – lower operating temperatures reduce the risk of overheating.

• Better compatibility with automation and inverters – Tier 2 offers more stable voltage parameters, improving energy quality.

  • Higher ESG rankings – for companies that publish sustainability reports, every saved kilowatt-hour improves their image – and investor score.

What would you do with €5,000 a year?

• Install 20 new LED lamps in the production hall.

• Fund annual maintenance for your entire machine park.

• Or simply hire an energy technician part-time – to monitor other loss sources.

These aren’t "green daydreams" – they’re hard numbers. And the more energy you produce, transmit, or store – the more it pays off.

Transformers are like tires: even bad ones keep you moving… but they’re burning your money.

A transformer that works with purpose

If you’ve made it this far – thank you. That means transformer efficiency matters to you. And rightly so.

Because modern energy is no longer about "buy and forget." It’s about conscious choices that deliver returns not only financially, but also environmentally. Tier 2 is not just a regulation – it’s a direction. And at Energeks, we know how to turn that direction into concrete solutions.

At Energeks, we design medium-voltage transformers that:

• comply with Tier 2 requirements,

• genuinely reduce energy losses,

• are ready for integration with PV systems, storage, and e-mobility,

• and most importantly – work for you, not against your bottom line.

If you’d like to learn how to choose a Tier 2 transformer for your investment, check out our offer:
See Energeks transformers.

Thank you for being with us.

Join our community on LinkedIn.
That’s where we share knowledge, solutions, and… a human approach to engineering.

Sources:

European Commission – Ecodesign for Transformers (Regulation (EU) 2019/1783)

International Energy Agency – The Role of Efficient Transformers in Grid Decarbonisation

CENELEC – EN 50708 Series for Power Transformers

Current electricity costs for industry in the EU are 2 to 3 times higher than in the US.

Is Europe still able to catch up with the competition?

That is why it is worth asking:

Is the Green Deal a realistic path to the future, or a luxury that we, as an industrial continent, simply cannot afford?

In this article:

• we will examine how the Green Deal affects energy costs and the competitiveness of European industry

• we will show which sectors suffer the most and why

• we will compare the EU’s approach to the practices in the US and China, as well as the other side of the coin

• we will present possible adaptation paths based on technology, not ideology

Estimated reading time: 10 minutes

What was the Green Deal supposed to be, and what has become of it by 2025?

The Green Deal, or more precisely the European Green Deal, was meant to be more than an economic strategy. It was intended as Europe’s response to the climate, economic and resource crisis. A global mega-project that would connect climate goals with reindustrialisation of the continent.

A new Declaration of Independence in energy, digital and technological terms. In its ideal form, the Green Deal was to create thousands of jobs, spark an investment boom in clean technologies and position Europe as a global leader in the race to climate neutrality.

Sounds great? On paper, absolutely. But paper can handle anything.

In practice, by 2025, the Green Deal increasingly resembles not a recovery plan, but a regulatory trap. Because transformation, although necessary, is costly.

And industry feels it the most. Especially the energy, steel, chemical and automotive sectors – those that operate on low margins, high volume and are extremely sensitive to energy costs.

Today, European industry pays 2 to 3 times more for electricity than its American competitors. For gas, even 4 to 5 times more. And this is not a temporary anomaly. It is the new normal, driven largely by the regulatory framework of the Green Deal.

And here comes the question that many politicians are still afraid to ask aloud: by following this path, is Europe actually increasing its competitiveness?

Or by ambitiously taking the lead in the climate race, is it leaving its own industry behind, exposing it to capital flight, plant closures and the import of "dirty" products from outside the EU?

Because this is already happening. But no one wants to talk about it publicly.

The Green Deal and energy costs. Who pays the price, and how much?

The Green Deal was supposed to be a modernisation boost. Today, it is increasingly becoming a stress test. For many companies, it is an equation with no good outcome. Costs are rising faster than the ability to absorb them, and global competitors are not waiting. The question European industry is asking today is no longer "if", but "how much longer can we hold on".

Energy prices that cannot be ignored

The average industrial electricity price in the European Union in 2024 was around 0.20 EUR per kilowatt-hour. In the United States, it ranged from 0.08 to 0.10 EUR, in China even less, often below 0.07 EUR. In Germany and Italy, prices reached 0.25 EUR, and sometimes more, especially in volatile spot markets. On top of that comes regulatory uncertainty.

Industry needs predictability, not a table of changing coefficients.

To all of this we must add the ETS system. In 2023, the cost of CO2 emission allowances reached 100 EUR per tonne. This mainly affected the steel, cement, smelting and chemical sectors. Starting in 2027, the ETS 2 system is expected to include additional sectors, including transport and construction. In practice, this means that not only large corporations, but also small and medium-sized manufacturing plants will need to factor in not only the cost of raw materials and energy, but also emissions and increasing administrative burdens.

European competitiveness on the defensive

Energy costs directly translate into a loss of competitiveness. For many companies, profit margins are becoming too thin to maintain production in Europe. Investments are vanishing, uncertainty is growing. In 2023, BASF announced a gradual reduction of its operations in Germany and relocation of some production to Asia and North America. ArcelorMittal suspended parts of its steel production, and Alcoa halted plans for aluminium plant expansion in Europe. The reason? High costs and a lack of clarity about the direction of climate policy.

Here lies a hard truth. Due to regulatory overreach, Europe is beginning to lose the industrial race. And not for technological reasons. We have the know-how, the talent, the innovation. But we do not have the cost structure that allows companies to compete globally.

The green paradox and the price of silence

Europe wants to be a leader in climate action. But if it does so at the expense of its own economy, there is a risk that emissions will simply be exported beyond EU borders. Production moves to countries that do not apply the same environmental standards. The result? Global emissions do not fall, while Europe pays an increasingly high price. Not for the transformation itself. But for the lack of balance.

That is why we need to ask out loud today: is the Green Deal in its current form a tool for growth, or rather an expensive luxury that only the biggest players can afford.

Which sectors suffer the most, and what does it mean for people, not just statistics

The energy transition is not only about infrastructure, technologies and legislation. It is also the everyday life of hundreds of thousands of people: workers, engineers, line operators, shift supervisors, owners of family-run companies. Their lives are the first to change when a factory scales down production, when investments are frozen, when energy prices rise faster than the margin on a manufactured part.

And it is precisely in sectors like automotive, steel and aluminium that this pressure is felt the most.

Automotive: a concrete wall of regulations

Over the past two years, European carmakers have found themselves in a particularly difficult position. After years of investment in electromobility, they are now confronted with much stricter emissions standards. The limit for new internal combustion vehicles by 2030 is set at 55 grams of CO2 per kilometre. By comparison, the average emissions of new cars in the EU in 2023 was 95 grams. That means a reduction of more than 40 percent in just a few years. With current technologies, this can only mean one thing: a costly and accelerated shift to electrification, regardless of whether the market and infrastructure are ready.

For large companies, this is a strategic challenge. For smaller suppliers, it is often an existential threat. According to the European Association of Automotive Suppliers, as early as 2024 nearly 275 thousand jobs in the supply sector are at risk, mainly in companies with fewer than 250 employees. In countries such as Poland, the Czech Republic, Romania and Hungary, these companies are the backbone of local economies.

Steel and aluminium: the industrial foundation under pressure

Steel and aluminium production is inherently energy-intensive. Smelting and rolling processes require stable and affordable electricity and gas supplies. Unfortunately, in Europe, these two components have become the most volatile cost factors. For example, the cost of energy can account for up to 40 percent of the total cost of producing one tonne of aluminium. When energy prices double or triple within a year, the economics of the entire plant stop making sense.

It is no surprise that in the past two years we have seen more closures and reductions in production capacity. In 2023, primary aluminium production in Europe fell by 25 percent compared to 2018 levels. In the steel sector, cuts ranged from 10 to 15 percent depending on the country. These figures are not just statistics. They represent thousands of jobs disappearing from industrial regions. And we are talking about strategic industries, essential for infrastructure, defence and renewable technology development.

Execution, not vision. Where to look for a way out

No one in their right mind denies the need for a green transition. But vision is one thing. Execution is another. It is this gap that generates frustration in the industrial sector. Because companies want to change, invest, implement new solutions. But they need the right conditions: stable energy prices, access to financing, technical infrastructure and predictable regulation.

There are already signs of hope. Hybrid systems that combine local energy storage, photovoltaics and gas or biogas generators can stabilise production and reduce reliance on expensive wholesale markets. Initiatives are emerging to share energy between plants in industrial clusters. More and more companies are investing in their own renewable sources, as well as improving energy efficiency in their processes.

But that is not enough if the system-wide approach to energy policy does not change. What is needed is not abandoning climate goals, but recalibrating the pace and method of implementation. Through dialogue, not decree. With an understanding of both potential and constraints.

USA and China: pragmatism instead of declarations

The energy transition does not happen in a vacuum. While in Europe the Green Deal has been designed as a comprehensive strategy for the economy and the climate, in other parts of the world the priorities are distributed differently. Both the United States and China are pursuing their environmental goals, but they are doing so in a way that is subordinate to national interests and industrial stability. For them, ecology is a tool for building advantage, not a risk to industry. And that makes a difference.

USA: climate matters, but competitiveness comes first

In 2022, the Biden administration launched the Inflation Reduction Act, the largest package of support in history for a net-zero economy. This includes 369 billion dollars in grants, tax breaks and investment guarantees for the energy, electromobility and component manufacturing sectors. Importantly, this support was not tied to a CO2 pricing system. American companies do not pay additional taxes for emissions and are not subject to an ETS mechanism, yet they still invest in renewables, energy storage and charging infrastructure. Because it makes economic sense.

An example? In Texas, an industrial cluster was developed based on local solar sources and a large-scale battery installation to supply a factory producing electric vehicle components. The entire project was completed with the help of federal guarantees and preferential loans. That is what pragmatism looks like in practice.

China: scale, speed and full control

China's energy transformation strategy is based on three pillars: maximizing domestic production of renewable energy components, maintaining energy security in parallel, and full state support. In 2022, China installed over 300 gigawatts of new renewable capacity. For comparison, all of Poland reached 10 gigawatts in the same period. This reflects not only a difference in volume, but in cost. The larger the scale, the lower the unit cost. And that translates into export competitiveness.

Crucially, China is not shutting down its coal-fired power plants overnight. They retain them as a buffer for system stability. At the same time, they are developing their own supply chains for batteries, inverters and charging stations. They operate systematically, with a 20-year horizon. As a result, Chinese companies can now offer complete solutions to global markets faster and cheaper than their European counterparts.

Germany: between idea and reality

Germany, long a leader in energy transition in Europe, has found itself in a difficult position. After phasing out nuclear power and limiting gas imports from Russia, the country had to accelerate the development of renewables and grid infrastructure. At the same time, the industrial sector began to feel the impact of rising energy costs and difficulties maintaining production capacity. In 2023, several steel and aluminium plants were closed. More and more companies are openly discussing the need to relocate some operations to countries with lower operating costs.

German research institutes, such as Fraunhofer ISE, are warning that without strategic investment in new energy technologies and transmission networks, Germany may lose part of its industrial potential. At the same time, there is an ongoing debate about whether the current Energiewende model requires adjustment. Not in terms of abandoning goals, but in seeking a better balance between climate ambition and economic resilience.

Conclusion: collision between narrative and reality

Europe has created an ambitious, multi-layered model of transformation. But other market players have opted for simpler and more direct mechanisms. The result? While the EU leads in climate responsibility narratives, the US and China lead in execution. Fast, large-scale, and cost-effective.

It is not about Europe giving up on its goals. It is about aligning implementation with the real conditions of the industrial sector. Because competitiveness is shaped not by declarations, but by the ability to deliver on time, at the right cost, and with manageable risk.

When pace outstrips the system. Where pragmatism ends and risk begins

The US and China are often cited as examples of a more flexible approach to the energy transition. They focus on competitiveness, scale, and local production of components. But even there, tensions emerge – both figuratively and literally. Because no strategy, however pragmatic, can function without infrastructure.

China: more does not always mean better

In 2023, China reached a record-breaking pace in renewable energy development – installing more than 350 gigawatts of new wind and solar capacity. No other country has matched this speed. But along with it came a challenge previously discussed mainly in Europe: transmission bottlenecks and a lack of integration with the grid.

According to Bloomberg New Energy Finance, the level of curtailment – the situation where excess renewable energy cannot be absorbed by the grid – reached as high as 20 percent in some provinces. That means one in five kilowatt-hours of clean energy was wasted. Not because it was not produced, but because the system was not ready.

China is adjusting infrastructure quickly, but this example shows that technological advantage without a cohesive grid and storage can backfire on both climate and economic goals. Even the best intentions can fail if the rhythm of development is not in sync with the rhythm of the system.

USA: competitiveness collides with availability

In the United States, despite the enormous resources of the Inflation Reduction Act, barriers remain in the form of complex permitting procedures for transmission infrastructure and local opposition to new installations. In practice, this means many energy storage and large renewable projects are delayed by two or three years, not due to lack of funding, but due to procedural and technical bottlenecks.

Grid operators in California and Texas increasingly report issues with energy oversupply at midday and shortages in the evening. Without rapid development of load management systems and intelligent distribution, local blackouts become a real threat. The technology exists. The intentions are there. But the nervous system – the grid and operational infrastructure – is falling behind.

The lesson: adaptation is not a race, it is synchronization

Europe often compares itself to the US and China, citing their investment advantages and regulatory flexibility. But comparisons without context can be misleading. Because even in those countries where the pace is faster and support is stronger, there are serious challenges with integrating renewables, oversizing sources, and ensuring physical transmission capacity.

That is why, instead of copying other models one to one, it is worth observing their mistakes. And asking not only how fast they build, but how they ensure each investment works reliably and harmoniously within the system.

This is exactly where Europe, despite its costs and constraints, can still gain an advantage. Not through speed, but through coherence.

By designing the energy transition not for headlines, but for what actually works.

Adaptation without illusion. What can industry do to stay in the game

The energy transition requires courage, but above all it demands operational efficiency. In public debate, we too often hear two extremes – either admiration for the vision of a green future, or catastrophism in the style of "nothing can be done." The truth, as usual, lies in the middle. It is not ideology that determines who survives, but the ability to adapt quickly and reasonably. In terms of technology, cost and operations. This raises the essential question: what solutions can companies implement today to regain control over energy costs and operational stability?

Energy storage is not a trend, it is a safety buffer

One of the most important development directions is local energy storage. No longer just a supplementary option, but a fundamental buffer for production continuity. Energy storage allows companies to reduce their exposure to wholesale market price peaks, stabilise their consumption profile and integrate renewables without the risk of outages.

The most efficient systems are hybrid installations: a storage unit operating alongside a local photovoltaic farm and, if needed, a gas or biogas generator. These solutions make it possible to store energy when it is cheapest or generated from in-house sources, and use it during peak demand periods. The result? Monthly energy bills up to 30 percent lower in some consumption profiles.

Process optimisation. Not everything needs replacing, much can be improved

Not every company can afford to immediately invest in new energy sources. But practice shows that significant savings can be achieved through careful review of existing production processes. Motor upgrades, energy management systems, rebalancing production lines to run more evenly – these actions deliver measurable results within months, not years.

At one machine component factory in Austria, a simple rule was introduced: every production line must have its energy profile reviewed weekly. Based on this data, some cycles were rescheduled to night hours, start-up sequences were optimised, and heating in production halls was automated. Implementation cost: under 100 thousand euros. Annual savings: over 300 thousand euros.

Flexibility as the new competitive edge

In an environment of volatile prices and regulation, the ability to react quickly is becoming a strategic advantage. And it is not only about technology, but also about organisational culture. Companies that deploy consumption forecasting tools, manage energy contracts actively, and maintain contingency scenarios for energy crises are more resilient in turbulent conditions.

One German aluminium producer avoided shutting down its smelter in 2023 only because it had already implemented flexible contracts with the grid operator and its own real-time energy monitoring system. As a result, it could respond immediately to price alerts and adjust shift schedules without compromising product quality.

Industrial energy clusters. Cheaper and safer together

More and more companies are also exploring shared energy use models through industrial clusters. The idea is simple – several neighbouring industrial plants jointly invest in renewables, storage and control infrastructure. They benefit from scale, share costs and risks, and gain flexibility and independence from market fluctuations.

In Denmark, one such cluster has operated since 2021 near Esbjerg. Three companies from the chemical, food and logistics sectors built a shared solar park and storage system. Each of them reduced their annual energy costs by around 20 percent, and the return on investment was 4.5 years.

Adaptation is a process. It does not require perfection, only decision

There is no single path. There are different starting points, budgets and needs. But the common denominator is readiness to change. You do not have to be the biggest player in the market to build resilience. It is enough to start improving what is already within reach. In technology, in management, in mindset.

Because the energy transition is not about everything becoming green tomorrow. It is about doing something today, so we do not remain stuck where we are.

Industry today needs room for smart decisions

In today’s industrial world, where every energy decision affects real jobs, production capacity and competitive advantage, silence no longer means inaction.

Maturity does not need grand declarations. It needs effective decisions. The kind that create space for development without chaos. The kind that do not disturb peace, but build it – through technology, precision and trust in the people who know what they are doing.

The Green Deal, in its idea, was meant to be an opportunity.

And it still can be.

But only if, instead of political slogans, we give industry access to real tools.

If we start talking about the transition the way it actually happens on the factory floor, not in a brochure.

If we accept that competitiveness and responsibility can go hand in hand, as long as they are based on solid knowledge, cooperation and the courage to implement solutions step by step – not in an instantly perfect version.

If today you are at a point where you need to decide whether to invest, wait, or recalculate everything once again – you are not alone. We understand the reality of these decisions. How much the numbers matter, not just the declarations. How hard it is to keep pace with change and still stay responsible – to people, to processes, to infrastructure.

That is why we share knowledge. That is why we listen. That is why we are here – not to sell you ready-made products, but to build, together, solutions that actually work.

If you want to talk about infrastructure upgrades, energy storage or possible scenarios for your company, we are here to support you. Explore what we can offer you today.

And if you are looking for inspiration, implementation stories and a place for honest, pressure-free discussion – join our Energeks community on LinkedIn.

It is made for people who are not looking for quick answers, but for the right questions.

Thank you for your time and your engagement.

Sources:

DNV: ENERGY TRANSITION OUTLOOK 2024

Bloomberg – China’s Renewables Surge Leaves Europe Playing Catch-Up

INSTITUTE FOR ENERGY ECONOMICS AND FINANCIAL ANALYSIS: New paradigms of global solar supply chain