Winter rarely arrives with a bang.

It more often creeps in quietly.

First, a few chilly mornings.

Then dampness that doesn't disappear even at noon.

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

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

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

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

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

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

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

The common denominator was very often moisture.

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

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

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

Reading time: 12 minutes

Where does water vapor in a transformer tank come from

Air always contains water.

Even when it seems dry.

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

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

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

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

The dew point is often reached faster than we expect.

In winter, this mechanism works mercilessly.

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

At night, everything cools down.

The water vapor seeks the coldest surface.

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

Why winter acts as a catalyst for the problem

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

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

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

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

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

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

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

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

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

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

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

Ideal conditions for condensation.

What happens to water after it condenses

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

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

Transformer oil has a limited capacity to dissolve water.

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

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

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

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

Olej i wilgoć. Toksyczny duet

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

Rozpuszczalność wody w oleju transformatorowym silnie zależy od temperatury.

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

Przy 60° C ta wartość może wzrosnąć nawet trzykrotnie.

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

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

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

Przy 40 ppm spada często poniżej 40 kV.

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

Zimą zdradliwy jest efekt pozornej poprawy.

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

Do tego dochodzi przyspieszone starzenie oleju.

W obecności wody i podwyższonej temperatury rośnie tempo reakcji chemicznych.

Tworzą się kwasy. Zwiększa się liczba kwasowa.

Olej traci swoje właściwości szybciej, niż przewiduje IEEE.

Oil testing in winter - 3 key methods

In winter, interpreting oil test results requires particular caution.

Three tools become crucial.

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

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

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

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

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

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

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

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

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

Paper insulation. The weakest link

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

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

Electrical insulation paper ages by definition.

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

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

What does this mean in engineering practice?

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

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

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

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

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

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

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

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

But a hermetic transformer is not a magical vacuum capsule.

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

Constructions with an oil conservator work differently.

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

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

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

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

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

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

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

Because water vapor doesn't have a favorite technology.

It simply checks where it can enter without knocking.

Common installation mistakes

Moisture is rarely the fault of the equipment itself.

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

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

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

Symptoms that are easy to ignore

The first signals of moisture presence are subtle:

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

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

How to reduce the risk of condensation

It's impossible to completely eliminate moisture.

But it is possible to manage it.

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

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

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

A modern approach to MV transformers

Modern transformers are designed with such scenarios in mind.

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

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

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

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

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

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

SOURCES:

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

CIGRE Technical Brochures on transformer insulation ageing.

IEC publications on insulating liquids and moisture management.

Cover Photo: Freepik/2148635097

When voltage rises faster than expected

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

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

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

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

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

What you’ll find in this article:

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

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

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

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

Reading time: approx. 11 minutes

What does it mean when a transformer does more?

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

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

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

• respond to voltage fluctuations or overloads

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

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

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

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

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

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

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

The SPD works by redirecting the surge energy to ground.

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

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

What does a surge protection device do?

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

In practice, it:

• protects transformer windings and downstream components

• extends the life of the entire MV system

• prevents production downtime and losses

Key data:

• response time: <25 ns

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

• service life: >10 years under standard surge exposure

When to use:

• substations installed in open terrain

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

• grids with unstable voltage supply

• mobile or temporary substations

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

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

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

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

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

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

What does automation include?

• integrated PLC controller

• electrical parameter recorders

• oil and winding temperature sensors

• communication interface (Modbus, CAN, IEC 61850)

Typical functions:

• oil and winding temperature control

• remote switching

• load analysis

• predictive maintenance

Application example:

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

Where does it work best?

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

• solar and wind farms

• urban smart grids

• temporary container substations

Transformer with TOGA terminals and MIDEL oil for photovoltaic installations

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

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

Even more important is the choice of insulating fluid.

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

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

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

TOGA terminals:

• fast and safe plug-in cable connection

• minimized short-circuit risk during installation and maintenance

• better ergonomics in field and industrial setups

• easier inspection and servicing

MIDEL oil:

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

• biodegradable – over 98% breakdown within 28 days

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

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

Applications:

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

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

Technical and environmental benefits:

• reduced fire and contamination risk

• high reliability under variable weather conditions

• eco-conscious choice aligned with ESG and sustainability policies

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

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

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

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

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

Metal enclosure:

• increased mechanical durability and sealed construction

• protection against moisture, dust, and mechanical impacts

• ideal for prefabricated substations and urban infrastructure

• enables fast installation and simplified logistics

Applications:

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

• critical infrastructure – hospitals, public facilities, urban areas

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

Technical and operational advantages:

• low noise and vibration emissions

• reduced failure rates and extended maintenance intervals

• suitable for challenging environmental conditions

• compliant with PN-EN 60076 and Ecodesign directive

When a transformer becomes more than a box

A transformer is no longer just an auxiliary device.

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

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

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

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

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

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

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

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

Thank you for reading to the end.

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

Sources:

Shell MIDEL

Power Transformers - Ecodesign requirements apply to this product.

IEEE Smart Grid Research: Control Systems

One decision that can eat away your solar ROI

It was supposed to be a quick return on investment.

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

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

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

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

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

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

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

In this article, you’ll learn:

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

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

• Why a standard transformer might not work well with solar

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

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

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

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

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

Reading time: 12 minutes

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

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

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

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

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

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

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

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

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

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

In practice:

• It is the upper limit of a micro-installation

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

Which means:

• No more simplified connection procedures

• A full design and approval process is now required

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Conclusion

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

What kind of transformer does a PV system really need?

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

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

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

A PV transformer plays a different tune

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

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

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

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

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

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

What are the minimum specs for a PV transformer?

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

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

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

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

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

Can a standard transformer be used in a PV system?

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

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

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

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

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

PV without a transformer — wishful thinking or real option?

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

When can a PV system operate without a transformer?

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

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

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

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

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

• proper protection devices

• reactive power compensation

• harmonic filtering (e.g. active filters)

• continuous energy quality monitoring

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

What could replace a transformer in a PV system?

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

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

• harmonic distortion remains low (THDi < 4%)

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

• adaptation to variable load and reactive power demands

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

When is a transformer absolutely necessary?

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

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

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

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

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

Conclusion — can you build PV without a transformer?

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

• user safety

• grid operator approval

• the quality of injected power

• the long-term durability of your inverters

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

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

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

What transformer for a 50 kW PV system?

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

• 63 kVA

• 0.4/15.75 kV or 0.4/20 kV ratio

• ONAN cooling

• Voltage regulation ±2 x 2.5%

• Insulation class F

• No-load losses up to 350 W

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

What transformer for a 100 kW PV system?

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

• 125 kVA

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

• Core rated for THDi up to 8 to 10%

• Insulation class H for improved thermal endurance

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

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

What transformer for a 150 kW PV system?

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

• 160 to 200 kVA (most commonly 200 kVA)

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

• Amorphous or oversized conventional core

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

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

• Harmonic resilience: THDi up to 12%

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

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

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

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

• it should be oversized by 10 to 15 percent

• account for cable losses

• allow for short-term overloads on sunny days

• give room for future expansion

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

Step-by-step transformer selection for a PV farm

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

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

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

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

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

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

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

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

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

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

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

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

1. Transformer too small for real-world overproduction

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

Symptoms:

• inverter disconnections during peak sun

• transformer overloads and thermal alarms

• higher-than-expected load losses

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

2. Wrong voltage ratio

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

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

3. No resilience to harmonics

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

Consequences:

• overheating of core and windings

• higher iron and copper losses

• shorter insulation life span

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

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

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

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

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

5. No voltage regulation on the primary side

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

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

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

What to verify before you switch on your PV transformer

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

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

• Can the core and windings handle high THDi?

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

• Is there voltage regulation on the MV side?

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

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

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

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

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

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

Why it works:

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

• Better tolerance to overloads — ideal for high midday peaks

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

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

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

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

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

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

Key advantages:

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

• Environmental safety — easier to pass fire safety inspections

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

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

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

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

Oil or dry? Choose based on where it lives

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

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

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

• Overload tolerance
  Oil transformer: high
  Dry transformer: medium

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

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

• Humidity resistance
  Oil transformer: high
  Dry transformer: lower

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

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

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

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

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

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

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

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

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

If you want to:

• consult a transformer selection with one of our engineers

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

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

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

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

🔗 Follow Energeks on LinkedIn

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

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

Sources:

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

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

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

Photo Cover: Trinh Tran pexels/191284110-14613940

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

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

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

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

Why are we talking about gas laws?

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

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

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

What exactly is Dissolved Gas Analysis (DGA)?

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

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

Which gases are analyzed in DGA?

The most commonly monitored are seven key gases:

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

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

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

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

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

What are the standards and gas tests?

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

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

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

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

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

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

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

The state equation:

PV = nRT

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

What do the symbols mean?

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

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

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

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

n – number of moles of gas.

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

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

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

T – temperature. Often non-uniform in transformers.

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

How does it work in practice?

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

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

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

The transformer as a chemical reactor

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

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

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

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

Imagine a cold Coca-Cola straight from the fridge.

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

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

What does Henry’s law say?

In its simplest form:

C = kH ⋅ P

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

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

How does this work in a transformer?

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

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

Every gas “prefers” something different

Different gases have different kH values:

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

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

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

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

Interpretation with physics in the background

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

• Oil temperature – was it stable in recent days?

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

• Do online readings differ from lab samples?

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

3. What happens when temperature rises?

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

Heat as the trigger for gas formation

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

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

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

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

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

According to the Arrhenius equation:

k = A ⋅ e − Ea/RT

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

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

Temperature vs. gas solubility

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

• More gas escapes from the oil to the headspace

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

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

Interpretation pitfalls

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

Without this, we risk a misinterpretation:

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

• Sudden gas increase after cooling may reveal previously hidden processes

  ---

Relationships worth knowing

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

• Gas generation rate – increases exponentially with temperature

• Solubility – decreases with temperature

• Partial pressure – rises with temperature at constant volume

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

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

4. Dalton and the gas mixture

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

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

What does Dalton’s law say?

Ptotal = P1 + P2+ ⋯ + Pn

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

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

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

The mixture as a fault fingerprint

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

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

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

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

• Increased ethylene (C₂H₄) is typical for overheating.

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

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

Gas escape dynamics

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

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

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

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

IInterpreting gas ratio changes

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

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

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

Practical conclusions

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

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

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

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

5. Diffusion – gas never sleeps

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

What does Fick’s law say?

J = −D ⋅ dc/dx

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

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

What does this mean in practice?

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

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

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

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

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

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

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

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

Why does diffusion matter for interpretation?

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

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

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

Practical conclusions

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

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

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

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

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

Let’s interpret the data that matters

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

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

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

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

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

That’s why our portfolio continues to grow:
➤ Modern transformers and complete transformer substations
➤ Energy storage systems, inverters, and EV charging infrastructure
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Technology is the tool. People and values are the direction.

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

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

Source:
Transformers Magazine vol.12

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

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

What will you find below?

• Why dry-type transformers win in so many projects

• Where oil-based technology can’t deliver

• What you gain as an investor

• A list of buildings where resin has replaced oil

Estimated reading time: 5 minutes

Reason 1: A dry-type transformer where oil fails

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

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

Not always.

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

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

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

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

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

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

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

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

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

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

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

In practice, this means:

• No leaks — even in the event of mechanical damage

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

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

A technology that breathes easy

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

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

• Mechanically robust — won’t crack or deform

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

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

Silence that matters

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

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

A lightweight performer for demanding tasks

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

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

Reason 3: What do you really gain?

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

1. You gain greater design flexibility

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

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

2. You gain a time advantage

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

In practice, that means you can:

• bring your facility online faster,

• shorten decision and commissioning chains,

• ensure energy continuity during the finishing stages.

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

3. You gain safety as a selling point

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

Developers who use dry-type transformers can proudly highlight:

• compliance with the highest safety standards,

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

• safe performance even under heavy load.

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

4. You gain future-ready technology

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

As an investor, this lets you:

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

• integrate with EMS, BMS, or SCADA,

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

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

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

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

Thanks to that, you:

• reduce the number of unexpected service calls,

• improve system availability for users (zero downtime),

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

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

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

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

Public transport – the silent heart of the city

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

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

Hospitals – where reliability equals life

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

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

Shopping malls and A+ office buildings – comfort that sells

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

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

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

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

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

Industrial sites – where conditions don’t forgive mistakes

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

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

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

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

Reason 5: A pillar of modern installations

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

Stability you can build on

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

That means:

• no downtime from cooling system failures

• no need to replace or regenerate oil

• minimal maintenance limited to visual checks and insulation resistance testing

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

Ready to go – right away

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

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

An acoustic edge – more comfort, less noise

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

This translates to:

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

• more design flexibility — no need for special soundproof enclosures

• a better user experience, which positively affects building perception

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

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

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

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

Dry-type transformer. The future already in operation

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

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

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

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

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

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

Sources:

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

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

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

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

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

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

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

Reading time: 4.5 minutes.

What is geothermal energy and how does It work?

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

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

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

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

Breakthrough in Nevada – How Fervo energy is transforming geothermal energy

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

Fervo Nevada, Photo Credit: Fervo Energy

25 MW of Power – The first true success of EGS

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

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

Advantage No. 1 of geothermal over other renewables: STABILITY

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

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

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

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

Is geothermal energy cost-competitive?

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

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

For comparison:

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

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

• Natural gas – $0.05–$0.07 per kWh

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

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

Iceland – A Geothermal future laboratory

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

Iceland Geothermal Energy, Photo via reykjavikcars.com

How does Iceland utilize its geothermal resurces?

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

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

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

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

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

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

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More than just electricity

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

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

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

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

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

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

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

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

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

What can the rest of the world learn from Iceland?

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

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

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

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

Iceland vs. the USA – two approaches to geothermal energy

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

For comparison:

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

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

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

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

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

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

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

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

It’s not about resources, but about approach

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

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

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

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

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

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

And this is just the beginning.

Photo Credit: Geotermia Podhalańska

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

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

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

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

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

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

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

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

What is blocking us? Obstacles to the geothermal revolution

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

Problem #1: The Cost of Drilling

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

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

Problem #2: Transmission Infrastructure

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

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

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

The Biggest Obstacle #? Capital and Political Decisions

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

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

How can we change this?

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

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

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

But are we keeping up with this change?

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

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

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

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It's time to change priorities

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

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

Strategy for the next decade: Scaling up

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

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

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

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

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

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

Sources:

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

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

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

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

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

Grid connection is a critical moment that can determine the success or failure of an energy project. The operator’s decision decides whether a new solar farm, energy storage facility, or wind power plant will be able to deliver electricity to consumers. Unfortunately, more and more investors face administrative barriers, long queues for approvals, and a lack of transparency in the process.

What are the most common obstacles? Why do some projects get the green light while others are rejected, even if they meet technical requirements? In this article, we explore the biggest challenges of grid connection and present modern solutions that can streamline the process.

You will learn:
✔ Why the current capacity reservation system is inefficient,
✔ What mistakes investors make when submitting applications,
✔ How new technologies and regulatory changes can accelerate the grid connection process.

Reading time: 3 minutes – just enough to gain a clearer understanding of the mechanisms shaping the future of the energy transition.

1. Lack of unified evaluation criteria – the grid connection lottery

Imagine two identical projects—both have the same capacity, are located in similar areas, and use the same technology. One receives grid connection approval within a few months, while the other is rejected. Why? Because evaluation criteria can vary between different regions and grid operators.

In practice, this means that available grid capacity is not always allocated according to transparent and uniform rules. Applications are reviewed individually, but not necessarily based on the same guidelines. As a result, some projects gain priority even if they are not the most optimal solution for the system. This creates a situation where potentially critical investments may be overlooked or denied, despite meeting all technical requirements.

2. Blocking available capacity with non-viable projects – reserved but unused

Think about how many times you've reserved a table at a restaurant but never showed up. For you, it’s just a minor inconvenience, but for the restaurant, it means lost revenue and an empty table that could have been used by another customer. The same problem exists in the energy sector.

Some companies submit grid connection applications to "secure" access to the network, even if they are unsure whether they will proceed with the project. By doing so, they reserve grid capacity that could be used for other, more advanced investments. Since many grid operators do not have strict verification processes at early project stages, the network ends up blocked by "ghost" projects that may never materialize.

The issue is further exacerbated in countries where connection fees or deposits are low, allowing investors to submit multiple applications without significant financial risk. As a result, viable projects ready for execution are stuck in a long queue while available capacity is occupied by projects that will never move forward.

3. Long processing times – years in the waiting room

You walk into a government office and see dozens of people ahead of you in line. You’ll probably spend an hour, maybe two, waiting. Now, imagine that this queue represents the grid connection process, but instead of a few hours, the wait lasts several years.

Grid operators have limited resources and must review massive amounts of documentation—applications, project plans, and network impact assessments. Each project requires detailed evaluation, and at the same time, the number of applications is growing exponentially. As a result, the decision-making process doesn’t take months—it can take years.

To make matters worse, many applications are submitted “just in case.” Investors often apply to check whether they have a chance of securing a grid connection, without necessarily planning immediate implementation. This clogs the system even further, as operators must also process applications that will never move beyond the planning stage.

4. Limited transparency in the process – investors left in the dark

Imagine being handed a complex puzzle to solve, but no one tells you the rules. This is exactly what the grid connection process feels like for many investors.

A lack of clear information about which projects have already been approved, how much capacity is still available, and which applications are in the queue leaves investors operating in uncertainty. In many cases, they wait months—only to find out that there is no remaining grid capacity in their region.

The absence of publicly accessible lists of approved connections means that decisions are made under conditions of limited market visibility. Greater transparency in this area could significantly streamline the investment process, reduce waiting times, and improve the efficiency of capacity allocation in the system.

Modern solutions in the grid connection process – how to accelerate and optimize the energy transition?

Anyone who has ever submitted a grid connection application knows that the process can be long, complex, and full of uncertainties. However, many countries are implementing innovative solutions aimed at speeding up this process and making better use of existing infrastructure. These advancements enable investors to execute their projects faster and more efficiently while allowing grid operators to manage available resources more effectively.

1. Publishing information on connection conditions and signed agreements – no more operating in the dark

Imagine wanting to buy a plane ticket, but the airline doesn’t tell you whether seats are still available. You have to fill out a request, wait weeks for a response, and only then find out that all tickets are sold out. Sounds absurd? Yet, this is exactly how the grid connection process works in many parts of the world.

To address this issue, new regulations are being introduced to ensure public access to key information, including:
✔ Connection conditions for specific areas,
✔ Signed grid connection agreements,
✔ Allocated and available grid capacity.

With this transparency, investors no longer have to operate in uncertainty. They can check in advance whether they have a chance to connect their facility to the grid, and if not, they can seek alternative locations.

2. Expanding access to application data at different processing stages – reducing bottlenecks

Remember those visits to government offices where you had no idea how many people were ahead of you in line, and all the staff would say was, “Please wait”? The lack of status updates is frustrating and inefficient.

The grid connection process often feels the same—investors are left in the dark, unsure about the stage of their application or when they can expect a decision. To tackle this issue, new systems are being introduced that allow:
✔ Real-time tracking of application status,
✔ Access to lists of applications under review and those still in the queue,
✔ Transparency in rejection decisions and their justifications.

These improvements make the process more predictable, enabling companies to plan their actions more effectively and estimate realistic project timelines.

3. Implementing the "cable pooling" model – more energy, fewer constraints

Imagine several people traveling the same route, but instead of sharing one larger vehicle, each person buys their own car. The result? Unnecessary costs, increased fuel consumption, and traffic congestion.

A similar issue occurs in the energy sector, where each renewable energy project often requires a separate grid connection, even when located near other installations. This leads to excessive infrastructure strain and higher investment costs.

The solution to this problem is cable pooling, which allows multiple renewable energy projects—such as wind and solar farms—to share the same grid connection point and transmission line.

The benefits?

✔ Better utilization of existing infrastructure – instead of building new lines, available resources are optimized,
✔ Lower costs – shared infrastructure reduces expenses for investors,
✔ Shorter connection times – fewer administrative hurdles lead to faster project implementation.

Cable pooling is a step toward a more efficient energy system, enabling a greater share of renewables in the energy mix without the need for expensive grid expansion.

4. Auction-based grid connection model for renewables and energy storage – a new era of capacity allocation

Imagine you want to buy an apartment, but instead of submitting an application and waiting for approval, you participate in an auction where the highest bid wins. A similar approach in the grid connection process could significantly streamline the entire system.

In the traditional connection model, each applicant submits an individual request, and decisions are made based on the order of submission and available capacity. The problem is that this method often leads to inefficient resource allocation—investors submit applications just in case, blocking capacity they may never use.

The auction-based connection model works differently:
✔ Grid operators define how much capacity is available in a given area and under what conditions,
✔ Applicants compete in a bidding process for the right to connect,
✔ Auction winners sign grid connection agreements, ensuring that the allocated capacity is actually utilized.

Benefits

✔ Faster process – instead of waiting months for a decision, investors quickly know if they have secured capacity,
✔ Better resource allocation – eliminating speculative applications and maximizing the use of available connections,
✔ Funding for grid expansion – auction revenues can be reinvested in infrastructure upgrades, reducing costs for all users.

The auction-based grid connection model has the potential to revolutionize how new energy projects, especially in the renewable sector, are developed.

A modern approach to grid connections is the key to success

Changes in the connection process aim to streamline energy sector development and ensure better use of available resources. Solutions such as:
✔ Public access to grid connection conditions,
✔ Transparency in application status,
✔ Cable pooling – shared infrastructure use,
✔ Auction-based capacity allocation,

are making the energy sector more predictable, efficient, and adaptable to the evolving energy mix.

Are these solutions enough? That depends on how effectively they are implemented and on collaboration between grid operators, regulators, and investors. One thing is certain—without these improvements, the pace of the energy transition may slow down, and the full potential of renewables and energy storage may remain untapped.

New grid connection management models – how to avoid capacity blockage and improve the network?

Imagine a world where every parking space reservation comes with an obligation to actually use it. If you don’t park your car within the designated time, the system automatically releases the spot for someone else. This is the approach increasingly being implemented in power grids, ensuring that allocated grid capacity does not remain unused for years.

To improve connection management efficiency and prevent capacity from being blocked by non-viable projects, grid operators are introducing innovative control and optimization mechanisms. The goal is to create a flexible system where genuinely active projects take priority, and available grid infrastructure is used efficiently.

1. The milestone system – is your project real?

In the traditional model, investors could reserve grid capacity without being required to start construction. As a result, infrastructure remained blocked for years, often with no real progress on the investor's side. This meant that genuinely ready projects had to wait because capacity was already reserved by projects that never materialized.

A modern solution to this issue is the milestone system. How does it work?

• Once capacity is allocated, investors must demonstrate progress within set deadlines, such as obtaining construction permits, starting site work, or purchasing key components.

• If the project fails to meet these milestones within the required time, its reserved capacity is automatically released and reassigned to another investor.

• This mechanism prevents speculative reservations and ensures that only projects moving forward receive a grid connection guarantee.

For example, if a company plans to build a wind farm and reserves 200 MW of capacity but takes no concrete steps for two years, the milestone system cancels the reservation and reallocates it to another investor.

The result?

✔ Faster project execution,
✔ No more capacity being blocked by speculative investments,
✔ A more efficient and dynamic energy grid.

2. Transfer of grid connection agreements – flexibility in network management

Imagine a developer securing grid connection terms, but their project runs into difficulties—lack of funding, administrative hurdles, or a shift in company strategy. What happens next?

Until recently, there was only one outcome—the project stalled, and the allocated capacity remained unused. However, more and more grid operators are now introducing mechanisms that allow grid connection agreements to be transferred.

What does this mean in practice?

• An investor can sell or transfer their agreement to another company that is ready to move forward with the project more quickly.

• The system enables dynamic capacity management—if one entity cannot utilize its grid connection, another can take its place.

• Transfers often come with a fee, which helps prevent speculation and misuse of reserved grid capacity.

Thanks to this approach, grid operators can respond faster to market changes, and viable projects no longer have to wait for years just because someone else has secured capacity they don’t intend to use.

3. Integration with digital tools – real-time decision-making

Can grid connections be managed as efficiently as modern e-commerce logistics systems handle deliveries? The answer is yes—and an increasing number of grid operators are adopting digital tools that enable real-time analysis and decision-making.

In the traditional model, grid connection requests were reviewed based on paper documentation and manual assessments by specialists. This process could take months or even years, especially when thousands of applications were pending.

With the integration of advanced analytics and artificial intelligence (AI) into power systems, it is now possible to:

• Instantly check available capacity based on real-time grid data,

• Dynamically prioritize projects based on their progress and impact on grid stability,

• Automatically detect inactive reservations and free up capacity for new investments.

It works like an airline booking system—if a ticket isn’t used, the seat is released to the next passenger. By digitizing the grid connection process, a similar model can be introduced to enhance network efficiency and transparency.

The future of the energy sector – are we ready for change?

Modern grid connection management models are key to the efficient development of power systems. Mechanisms such as:
✔ The milestone system, which eliminates inactive capacity reservations,
✔ Transfer of grid connection agreements, allowing for dynamic capacity management,
✔ Digital analytics tools, accelerating decision-making processes,

are making grid connection procedures more fair, efficient, and adapted to the challenges of the energy transition.

Will these changes be enough? That depends on how widely they are implemented and whether regulations evolve to support them. One thing is clear—without optimizing the grid connection process, the expansion of renewable energy and the stability of power systems could be at risk.

In the coming years, we will see which countries and regions successfully navigate these challenges and introduce connection models that enable a seamless transition to a more sustainable energy future.

How to avoid grid connection rejection? Here’s what you can do to prevent the 5 most common mistakes

Not every application ends in success. The transmission system operator (TSO) may reject a request if it does not meet key requirements. Here are the most frequent reasons for rejection—and how to avoid them:

❌ 1. Lack of available connection capacity
If the local energy infrastructure is overloaded, the TSO may deny the request, especially in areas with a high concentration of new renewable energy sources.
🔹 How to avoid this?
→ Conduct a preliminary analysis of available capacity and consult with the TSO early in the planning phase to assess feasibility.

❌ 2. Incomplete documentation
Errors in application forms or missing required attachments are among the most common reasons for rejection.
🔹 How to avoid this?
→ Before submitting, double-check that all required elements are included. If unsure, consult a grid connection specialist.

❌ 3. Non-compliance with technical standards
Facilities that fail to meet grid standards (e.g., power quality issues, lack of proper protection systems) will not be connected.
🔹 How to avoid this?
→ Ensure that installations comply with TSO regulations and invest in stabilization systems to meet grid requirements.

❌ 4. Missing environmental and administrative permits
For instance, planning a renewable energy project in a protected area without securing the necessary approvals will result in an automatic rejection.
🔹 How to avoid this?
→ Secure all required permits and approvals before submitting the grid connection application.

❌ 5. No justification for transmission grid connection
Not every project requires direct connection to the transmission grid—many can be connected at the distribution level.
🔹 How to avoid this?
→ Evaluate whether a transmission grid connection is necessary, or if a distribution system operator (DSO) connection would be a more suitable solution.

Thorough planning and compliance are key to success. A well-prepared application minimizes the risk of rejection and speeds up the connection process.

If you want to learn more about optimizing grid connection procedures or consult your project with experts, contact the Energeks team—we’ll help you find the best solution for your investment.

Sources:

PSE S.A.

During the carefree days of childhood, on warm summer afternoons, my friends and I would often ride our bikes through fields where towering steel giants – transmission towers – proudly carried power lines above our heads.

We experienced something unusual: a subtle tingling on our skin, as if surrounded by something invisible, creating delicate sensations we could feel on our bodies. At times, in the stillness, a faint, eerie sound could be heard, as if the energy itself was speaking. Back then, we had no idea what was happening, but the experience left a lasting impression on me.

Today, as an engineer, I know that these phenomena result from electromagnetic fields (EMFs) generated by high-voltage power lines. These fields, though invisible, interact with their surroundings in various ways – sometimes causing the tingling sensation on the skin, other times emitting a faint sound known as corona discharge. This knowledge not only explains my childhood memories but also inspires a deeper understanding of the intricate and fascinating world of modern energy systems.

Reading time: 2 minutes – discover how electromagnetic fields and advanced transmission structures power the world and shape our reality!

Electromagnetic fields: The foundation of modern energy systems

Electromagnetic fields (EMFs) are present in every electrical device, from simple household appliances to complex energy transmission systems. In the case of high-voltage power lines, we encounter extremely intense EMFs, which are the result of both the flow of electricity and the potential difference between the wires and the ground. These fields are not only a byproduct of energy transmission but also one of the fundamental phenomena on which modern energy infrastructure is based.

Thanks to proper insulation and advanced structural designs, the electromagnetic fields generated by transmission lines can be controlled and minimized in a way that is safe for both humans and the environment. This is achieved through the use of advanced materials such as ceramic or polymer insulators, which reduce radiation emissions while maintaining wires at the proper height and distance from the ground.

From a technical perspective, electromagnetic fields in high-voltage power lines play a crucial role in optimizing energy transmission. High voltage allows for the reduction of transmission losses caused by the resistance of wires, which is particularly important over long distances. EMFs generated by high-voltage lines are also managed through innovative solutions such as corona discharge suppression systems, which minimize energy losses and reduce the impact of fields on the surrounding environment.

EMFs in the Context of Health and the Environment

The safety of electromagnetic fields is a widely researched and internationally regulated topic. Standards established by organizations like the International Commission on Non-Ionizing Radiation Protection (ICNIRP) ensure that EMF levels near transmission lines are far below values deemed harmful to human health. Additionally, precise computer simulations allow infrastructure designers to optimize the layout of towers and wires, minimizing their environmental impact.

The Role of EMFs in Energy Transformation

The ongoing energy transformation, driven by the integration of renewable energy sources such as wind and solar farms, increases the importance of high-voltage transmission lines. Electromagnetic fields generated by these lines enable the efficient transmission of energy from its production sites—often located in remote and hard-to-reach areas—to industrial and urban centers. A key challenge in this regard is striking a balance between transmission efficiency and minimizing the impact on people and nature.

Modern electrical engineering continually develops technologies that allow for even greater control over electromagnetic fields. One example is HVDC (High Voltage Direct Current) systems, which generate significantly lower EMFs than traditional alternating current lines. These innovations not only improve energy efficiency but also support the development of sustainable infrastructure.

Electromagnetic fields, though invisible, form one of the pillars of modern energy systems. They drive the global economy by enabling the transport of energy over vast distances in an efficient and safe manner. The challenge for the future lies in further advancing technologies that allow for better utilization of this phenomenon while protecting the environment and ensuring quality of life.

It is worth remembering that every high-voltage line and every transmission tower is a testament to how far humanity has come in understanding and harnessing the laws of nature for the benefit of technological progress.

Transmission towers: pillars of the global energy infrastructure

Transmission towers are more than just steel constructions – they are key components of the global transmission network, enabling the transport of energy over vast distances. Their variety is tailored to the specific terrain and energy needs.

Types of Transmission Towers:

• Lattice Towers (Steel): The most commonly seen in rural landscapes, these towers are lightweight yet durable. They carry lines with voltages ranging from 110 kV to 400 kV, making them the foundation of high-voltage networks.

• Tubular Towers: Frequently used in urban areas, their slim design takes up less space and minimizes their impact on the landscape. Thanks to their solid construction, they are resistant to strong winds and ice loads.

• Insulator Towers: Specially designed for challenging terrains, such as mountainous regions. They feature longer insulators that minimize the risk of breakdowns.

• Tension Towers: Used at line turns and locations requiring greater structural stability.

Each type of tower serves a specific purpose, contributing to the reliability of the electrical grid. From selecting appropriate materials to detailed overload simulations, the design process of these structures is advanced engineering at its finest.

The role of transmission towers in energy transformation and sustainable development

In the era of energy transformation, driven by the rapid growth of renewable energy sources such as wind and solar farms, transmission towers play a fundamental role in the global energy infrastructure. They enable the transmission of energy from remote energy farms, often located in hard-to-reach areas, to densely populated urban centers where electricity demand grows year after year. A prime example is Germany, where modernized transmission networks allow for the efficient transport of energy from wind farms in the north to industrial regions in the south. Thanks to advanced technologies used in the design of transmission towers, energy losses over long distances can be minimized, enhancing the efficiency of the entire power grid.

Additionally, modern transmission towers incorporate sustainable development aspects, such as the use of corrosion-resistant materials, which significantly extend their lifespan and reduce the need for frequent maintenance. Engineers design these structures to minimize electromagnetic emissions, making them safer for people and more environmentally friendly. Transmission towers have become not only a crucial part of the energy infrastructure but also a symbol of technological and ecological transformation, supporting global sustainable development goals.

February 14: World Energy Day

Today, on World Energy Day (#WorldEnergyDay), take a moment to look up and appreciate those towering "ladders to the sky" – transmission towers. From the ground, they might seem like quiet guardians of the landscape, but in reality, they are conducting an endless, invisible operation – delivering the energy that powers our daily lives.

Imagine each of these towers as a "checkpoint of energy," where electricity leaps from wire to wire to reach your home and power your favorite coffee maker. Without them? Well, your mornings could look quite different – darker, colder, and decidedly less caffeinated.

These steel giants are not just technological marvels but also true bridges connecting remote wind and solar farms to bustling city centers. They transport energy across hundreds of kilometers, spanning mountains, forests, and plains, like tireless messengers from the future. And the best part? They do it all without complaining about the weather.

Have you ever imagined a world without these "energy superheroes"? It might look more like medieval villages than modern metropolises. Instead of powered machines, we'd rely on horses and candles, and instead of Netflix – maybe a good story by the campfire. Sounds romantic? Perhaps, but only for a moment.

So next time you see a transmission tower, give it a mental "high five." It's thanks to these giants that you can turn on the lights, cook a meal, or even read this post. What do you think?

Do you have your own stories about energy? Share them with us!

Sources:

National Grid: "Transmission Towers: How They Work and Why They Matter"

Cover Photo: ENERGEKS, 2025

Did you know that modern railway operators are increasingly investing in renewable energy sources (RES) to not only reduce operational costs but also enhance passenger comfort and contribute to the decarbonization of transport? Thanks to advanced technologies, railways are becoming synonymous with eco-friendly and convenient transportation.

This short post will show you how sustainable development in the railway industry is becoming a reality through cutting-edge technologies – a quick read of just 1.5 minutes.

Railways in the Era of Energy Transformation

For years, railways have remained one of the most eco-friendly modes of mass transportation, accounting for only 0.4% of greenhouse gas emissions in the EU transport sector. In comparison, road transport generates over 71% of emissions in the same category. However, in the face of the climate crisis and ambitious goals of the European Green Deal, which aims for climate neutrality by 2050, railways must take additional steps to become even more sustainable.

The European Green Deal outlines ambitious CO₂ emission reduction targets, placing railways at the forefront. While railways are already among the most environmentally friendly forms of mass transit, electrification alone is not enough. The key lies in powering infrastructure with renewable energy sources.

Why is Electrification Alone Insufficient?

Currently, 75% of European railway lines are electrified, and electric trains account for 80% of transport operations. However, the energy used by traction networks still largely comes from fossil fuels. For instance, in 2020, only 32% of electricity in the EU was derived from renewable sources.

This makes the transition to renewable energy-powered railways a priority. The integration of wind farms, photovoltaic systems, and energy storage solutions not only reduces the carbon footprint but also enhances energy stability and cuts operational costs.

How Does the Integration of RES with Railway Infrastructure Work?

Powering railway infrastructure with renewable energy sources (RES) is a complex but highly efficient process that combines advanced energy technologies with transport engineering. RES, such as wind farms and photovoltaic installations, can supply both ground systems—platform lighting, signaling systems, air conditioning in station buildings—and rolling stock, thanks to energy delivered to the electric traction network.

Technologies and Their Applications

1. Wind and Photovoltaic Farms
   Railways can directly draw energy from wind or photovoltaic farms connected to local energy substations. In such cases, the energy generated by RES is fed into the traction network, powering trains in real time.
   Example: In the Netherlands, wind farms generate over 1.4 TWh of energy annually, sufficient to power 5,500 trains daily.

2. Energy Storage Systems
   Lithium-ion batteries, and in some cases, flow battery systems (redox flow), allow for the storage of surplus energy produced by RES during off-peak network demand (e.g., at night). This energy can later be used during peak demand hours, ensuring the stability of the energy system.
   Example: In Austria, energy storage systems in ÖBB networks can store up to 200 MWh, stabilizing the traction grid in the Vienna area.

3. Smart Grid
   The integration of traction networks with smart grid systems allows for efficient energy management, directing it where it is most needed and minimizing transmission losses. Thanks to advanced management systems (SCADA), railways can monitor energy usage and optimize its distribution.

   CC: Wysokie Napiecie

Pioneering Projects in Europe

1. The Netherlands – 100% Wind-Powered Rail
   Dutch Railways (NS) have become pioneers in fully integrating the railway system with wind farms. Farms like Gemini, producing 600 MW, power both the traction network and local railway infrastructure, effectively eliminating CO₂ emissions. The project saves over 1.2 million tons of CO₂ annually.

2. Belgium – Solar Tunnel
   The solar-powered railway project in Belgium includes the installation of photovoltaic panels on the roofs of railway tunnels, covering a total area of 16,000 m². This system generates 3.3 GWh annually, enough to power lighting and railway signaling along the Antwerp-Amsterdam route.

3. Spain – Smart Stations
   In Spain, Renfe has integrated photovoltaic systems at stations like Barcelona Sants, which generate 2 MW of energy, reducing CO₂ emissions by over 15,000 tons annually. Furthermore, these stations are equipped with smart energy management systems that automatically adjust consumption to current needs.

4. Poland – Green Railway
   Under the "Green Railway" project, PKP Energetyka is developing photovoltaic farms with a capacity of 300 MW and energy storage systems. This energy continuously powers traction networks, reducing CO₂ emissions by 800,000 tons annually.

Are Renewables on Tracks the Future of Profitable Railways?

Investing in renewable energy sources (RES) for railway infrastructure is no longer just an environmentally driven choice. It has become a practical tool for improving financial performance, increasing energy independence, and building a competitive advantage. Eco-friendly solutions in railways deliver tangible benefits at both operational and strategic levels.

1. Reducing Operational Costs: Energy That Pays Off

The cost of renewable energy—wind and solar—has been declining for over a decade, and generation costs from these sources are now lower than fossil fuels in most EU countries. For railway operators, this translates into significant savings on electricity expenditures.

Example: In the Czech Republic, as part of the "Green Rails" project, photovoltaic systems were installed at stations in Prague, reducing electricity costs by 30%. This translates to savings of approximately €500,000 annually, which can be reinvested in infrastructure modernization or innovative passenger solutions.

2. Energy Independence: Stability and Security of Supply

As a critical component of public transport, railways must operate without interruptions, regardless of energy price fluctuations or crises. Installing local energy storage systems, combined with renewable sources, ensures greater independence from the power grid.

Example: In Romania, the "Solar Tracks" project includes constructing lithium-ion energy storage systems with a capacity of 50 MWh along major rail lines. In the event of a power outage, trains can continue running for up to 6 hours, reducing the risk of disruptions and enhancing passenger confidence.

3. Building a Positive Image: Railways as Ambassadors of Sustainability

Green investments in the railway sector have become a hallmark of modern and responsible transport. Operators involved in RES projects gain recognition from passengers, businesses, and local communities as leaders in sustainable development.

Example: In Austria, the national railway operator ÖBB implemented the "Eco-Stations" project, equipping stations with photovoltaic panels that power lighting, air conditioning, and electric bike chargers. In its first year, this system reduced CO₂ emissions by 10,000 tons, equivalent to the annual energy consumption of 4,000 households.

CC: PKP Energetyka

Benefits in Numbers: Why Invest in Renewable Energy for Railways?

• Economy of Scale: The cost of solar and wind energy has dropped by 70% over the last decade.

• Energy Stability: Energy storage systems can provide uninterrupted power for 4–6 hours in case of grid failure.

• Carbon Footprint: Stations using renewable energy reduce CO₂ emissions by an average of 50% compared to traditional solutions.

• Passenger Trust: 82% of travelers state that they prefer operators promoting eco-friendly solutions.

  ---

• The energy transformation of railways is a bold response to the pressing challenges of the 21st century. Across Europe, nations are demonstrating how renewable energy sources (RES) can revolutionize transportation, building efficient, modern, and environmentally friendly infrastructure that sets a global standard.

  Integrating RES technologies into railway infrastructure delivers benefits that extend far beyond the tracks. Operational cost reductions, energy stability, and a green public image collectively enhance the appeal of railways to passengers and investors alike. These advancements highlight the sector's readiness to innovate and adapt.

  Such initiatives are positioning railways as champions of sustainable transport, powered by the energy of tomorrow. They are no longer just a mode of transit but a testament to how technology and sustainability can move hand in hand, inspiring a greener future for all.

  Sources:

European Environment Agency

Horizon - The EU Research and Innovation Magazine

Railjournal

Wysokie Napięcie