The Polish power market is defined by three components: a 26.5 GW legacy coal fleet, vertically integrated state‑owned portfolios, and a rapidly growing share of renewables, especially solar.

This system is now being stress‑tested. In 2025, Poland recorded over 300 hours of negative power prices, more than double Great Britain’s 149 hours, though still below Germany’s 575, underscoring how quickly variable renewables are reshaping price dynamics.

Poland's single-zone national electricity market has long been dominated by four state-controlled, vertically integrated groups. Each combines generation, distribution, and retail under one parent company, though the distribution arms are legally unbundled. That dominance is starting to erode as IPP-built solar PV and onshore wind capture a growing share of generation.

Key takeaways

• Four State-Owned Enterprises (SOEs) (PGE, Enea, Tauron, Energa/Orlen) generated 65% of Poland's electricity in 2024, down from 79% in 2022. Each owns generation, distribution, and retail across defined geographic territories.
• EU ETS carbon allowances now account for 63% of hard coal's short‑run marginal cost.
• Poland recorded over 300 hours of negative day‑ahead prices in 2025, driven by high solar generation.
• Day‑ahead prices averaged €109/MWh in 2025, 77% above those in France and 20% above those in Germany.

Four SOEs control 65% of generation

The first pillar is the SOE structure. Poland's electricity market was liberalised in 2007, but in practice, four state‑owned groups still control most of the value chain:

• PGE serves central and eastern Poland.
• Tauron operates in Silesia and the southern regions.
• Enea covers western Poland.
• Energa (now part of Orlen) manages northern territories.

PGE is the largest of the four SOEs. It operates 18.9 GW of capacity, anchored by the 5.1 GW Bełchatów lignite complex, the biggest thermal plant in Europe, and serves 5.8 million retail customers across central and eastern Poland.

Each group owns power plants, a distribution system operator (DSO), and a retail supply arm. Competition exists at the retail level in theory, but switching rates are low, at 0.23% annually.

Together, the four SOEs generated 65% of the electricity fed into the grid in 2024, down from 79% in 2022. The decline is explained by the growth of onshore wind and solar PV built by Independent Power Producers (IPPs) and prosumers.

Coal sets the price, carbon makes it expensive

The second pillar is coal. In most European markets, gas has historically set, and still usually sets, the power price; in Poland, that role is played by coal, much of it owned and operated by the four state‑owned utilities that dominate generation.

Poland’s day‑ahead electricity market operates through TGE (Towarowa Giełda Energii, the Polish Power Exchange), alongside EPEX SPOT and Nord Pool, and is coupled into the European single day‑ahead coupling via the EUPHEMIA algorithm.

Generators submit offers for each hour of the following day, and the market clears at the price of the most expensive unit needed to meet demand in that hour (the merit order).

On a typical summer weekday, midday solar output peaks at around 12 GW. Coal plants must either shut down and incur restart costs or bid below zero to remain dispatched at minimum stable generation. CfD (aukcyjny system wsparcia) backed solar also bids negative: the contract pays generators a fixed strike price regardless of the market clearing price. By evening, solar output drops, and coal again sets the price.

This market behaviour results in extremely volatile Polish power prices; in 2025 alone, Poland experienced over 300 hours of negative prices. For batteries, this volatility is a strong revenue signal.

In Poland, hard coal or lignite set the marginal price for most hours. The short-run marginal cost (SRMC) is the cost of producing one additional megawatt-hour of electricity from a plant that is already built, covering only fuel, carbon allowances, and variable operating costs.

The SRMC of hard coal generation in 2025 averaged €110/MWh: €37/MWh fuel (based on the PSCMI‑1 domestic coal index), €70/MWh EU ETS carbon allowances, and €4/MWh variable O&M. CO₂ made up 43% of coal SRMC in 2020; by 2025, that share had risen to 63%.

​Because coal sets the price in so many hours, and with fewer renewables to push prices down, Polish day‑ahead electricity prices rank among Europe's highest. The 2025 annual average was €109/MWh (77% above France, 20% above Germany), though still below Italy’s €116/MWh.

Most electricity never reaches the exchange

The third pillar is how power is traded. The day‑ahead auction produces a clearing price, but most Polish electricity is never actually traded on the exchange. Instead, it flows through internal contracts within each SOE group.

Each SOE's trading arm acts as the Balancing Responsible Party (BRP) for both its own generation and its own retail customers. For example, PGE Obrót buys electricity from PGE's coal‑fired plants under intra‑group contracts and simultaneously sells it to PGE's retail customers. If a generation–demand mismatch occurs, PGE can ramp up or down its own units to close the gap.

This internal matching means the SOEs rarely need to trade on the exchange; the BRP submits net schedules to Polskie Sieci Elektroenergetyczne (PSE) after positions are already balanced within the group.

How do IPPs sell their power?

SOEs still dominate Poland’s generation mix, but IPPs' share is growing rapidly. Between 2022 and 2024, the IPP and prosumer share grew from 21% to 31%. Solar installed capacity now exceeds 25 GW: roughly 13 GW of behind-the-meter systems across 1.5 million installations, and 12 GW of utility‑scale and commercial projects. The SOEs hold just 3.9 GW of renewable capacity between them, so almost all the growth is happening outside their portfolios.

In Poland, IPPs have two main routes to market.

• CfD auctions. Developers bid for a strike price. Output sells on the day‑ahead market at the clearing price. If the market price is below the strike, the CfD pays the difference; if above, the generator pays back the excess. Unlike Germany, which predominantly uses one‑sided CfDs under the EEG Act (where generators keep all upside).
• Corporate PPAs. Financial contracts at a fixed price with an industrial buyer or utility. The physical electricity still clears through the day‑ahead market; the contract settles the price difference financially.

18GW of coal already has a retirement date

Although growth in IPP renewable energy is far outpacing that of the SOEs, all four SOEs have published renewable deployment targets to 2035. The direction is consistent: less coal, more renewables, and a first entry into BESS. This planned growth in renewables is a direct consequence of the large number of coal units scheduled for retirement. Gas plants are also being built alongside renewables to provide firm power and fill the gaps left by variable generation.

Poland's 26.5 GW coal fleet is scheduled to shrink to 8.7 GW by 2049. PGE faces the largest retirements, with the 5.1 GW Bełchatów complex due to close by 2036.

What this means for flexibility investors

The features that define Poland's power market are also those that create the most opportunity for BESS.

• As coal retires and is replaced by variable renewables, state utilities will need to increasingly look to exchanges to meet their retail demand. Unlike their current stable and predictable coal-heavy portfolios, the new generation mix will bring greater uncertainty in profiles and higher imbalances that get diverted to exchanges. Volume previously matched internally will flow through the market, deepening the liquidity that BESS and other flexible assets need.
• Meanwhile, solar capacity is growing faster than coal is retiring. The midday surplus will widen before it narrows, and negative prices are here to stay – a strong and durable signal for flexibility investors.