Electricity production

Production from renewable energy sources  

In September, renewable energy sources operated at an average capacity of 7.8 GW, accounting for 38.9% of the energy mix. This represents an increase of 2.0% compared to August 2026 and 22.1% compared to September 2025.

Onshore wind farms generated electricity at an average capacity of 3.3 GW in September (42.0% of renewable energy generation). This is 46.9% more than in August 2026 and 27.3% more than in September 2025. The installed capacity of wind power plants (the latest available data from early August) stands at 11.6 GW, representing an increase of 413 MW, or 3.7%, y/y.

In July of this year, the first electricity from offshore wind turbines in Polish waters was fed into the grid. In September, they operated at an average capacity of 0.13 GW, which represents 3.8% of the capacity at which onshore wind turbines operated. They generated 0.09 TWh of electricity. The first offshore wind farm is still in the commissioning and testing phase, so it is not operating at full capacity. Its official launch is scheduled for the end of this year. The total capacity of offshore wind farms scheduled to come online by 2030 will be 5.9 GW.

PV installations operated at an average capacity of 3.1 GW in September (40.2% of renewable energy generation)—a 22.6% decrease m/m and a 10.6% increase y/y. For the past three years, the rate of capacity growth in photovoltaics has remained high, with large-scale installations, rather than prosumer installations, accounting for an increasingly larger share of new capacity. Installed PV capacity (the latest available data from early August) stands at 27.9 GW (a 15.8% y/y increase, or 3,814 MW annually), of which approximately 13.6 GW consists of prosumer installations (a 7.7% increase, or 980 MW annually).

Biomass installations operated at an average capacity of approximately 1.2 GW in September, while hydroelectric power plants operated at 0.1 GW.

The maximum hourly share of weather-dependent RES (wind and solar) in domestic electricity production was 65.0% in September, and the minimum was 2.2%

In situations where the total power supplied in a given hour exceeds current demand, it is necessary to utilize electricity storage facilities, export surplus energy, or even shut down renewable energy sources.

In September, the transmission system operator was forced to curtail renewable energy generation units for 197 hours (26% of the hours in the month) over the course of 25 days. These situations occurred mainly during the afternoon hours.

Electricity generation was curtailed by 126.1 GWh. Of this, 69.7 GWh came from large-scale photovoltaic installations (5.9% of potential production). Meanwhile, 56.4 GWh came from wind farms (2.3% of potential production).

Since the beginning of the year, production has been curtailed by 1,736.9 GWh, representing a 48.8% increase compared to the same period in 2025. The scale of curtailments this year had already exceeded the level for the entire year of 2025 by July.

The graphshows cumulative annual values (from the beginning of the year to the last day of the reported month) of non-market redispatching (so-called curtailment) of electricity from wind and solar farms (which has not yet affected prosumers). Curtailment, meaning the forced reduction of electricity production by the transmission system operator (PSE), has so far been implemented solely for balancing reasons — i.e. due to excess electricity generation relative to demand and limited storage or export capacity — rather than due to grid constraints.

The purpose of curtailing generation is to prevent the national power system (KSE) from losing its regulatory capacity, which could otherwise lead to a deterioration in network security and stability parameters.

It is worth noting that the volume of curtailed renewable energy would be lower if conventional power sources — coal and gas-fired power plants and CHP units — were more flexible, i.e. had lower technical minimums and could ramp up or down more quickly. The curtailment could also be reduced if the Polish power system had more energy storage facilities or made greater use of demand-side flexibility — that is, loads capable of increasing consumption when electricity prices are low (typically during high renewable output), such as electrolyzers or heating devices charging thermal storage systems.

The chart below shows how the structure of renewable energy curtailment changes, broken down by PV and wind power plants. Curtailment of wind power generation during the winter months occurs mainly at night, when power demand is at its lowest. However, with the sharp increase in photovoltaic generation in the following months, there is a significant energy surplus during midday hours. This makes it necessary to both curtail photovoltaic generation and increase the curtailment of wind power. A seasonal shift is evident, as photovoltaics begin to play a larger role in the energy mix, resulting in most curtailment occurring in the middle of the day.

Such a high level of curtailment of renewable energy generation is the result of the need to maintain the stability of the power system, the low flexibility of coal-fired power plants, and the need to keep them operating at their technical minimum.

Production from fossil fuels 

In September 2026, gas-fired power plants and combined heat and power plants (natural gas and coke oven gas) operated at an average capacity of 2.3 GW (a decrease of 8.4% m/m and 15.8% y/y) and generated 11.5% of the electricity.

The average capacity of hard coal-fired units increased by 10.1% compared to September of last year and by 4.2% compared to August of this year (to 6.3 GW). The average capacity of lignite-fired units reached 3.6 GW. This represents an increase of 1.2% y/y and 5.5% m/m. Coal-fired generation accounted for less than half of the electricity generated in September. In total, coal-fired units operated at an average capacity of 9.9 GW (49.3% of the energy mix). This represents an increase of 4.7% m/m and 6.7% y/y.

 The graph shows the electricity generation mix in Poland by different technologies using fossil fuels or renewable sources. The primary source of electricity is hard coal and lignite, but the share of natural gas and RES continues to grow. Depending on the season, wind power or photovoltaics provide the most energy among renewable sources. 

The changes in the structure of electricity generation that have taken place in recent years are unprecedented. Between September 2016 and September 2026, coal’s share in the energy mix decreased by 33.9 percentage points. At the same time, the steady expansion of renewable energy sources means that the gap between electricity generated from coal and that from renewables is narrowing at an ever-faster pace. In addition, large natural gas-fired units are beginning to play an increasingly significant role in the energy mix.

However, significant seasonal differences remain evident—in winter, the level of generation from renewable energy sources remains noticeably lower. This is primarily due to higher energy demand and the limited pace of onshore wind power development, which could significantly increase production during months with low solar generation. The slow development of new wind capacity results in greater reliance on conventional sources for winter generation.

The graph shows how the monthly shares of each source's electricity production in total production have changed over the past few years.

September 2026 - details

• The average hourly power demand in September 2026 was 17.7 GW (0.3 GW more than in September of the previous year), reaching a maximum of 21.8 GW (minimum: 12.3 GW).
• Electricity consumption totaled 12.7 TWh (1.6% more than last year), while gross generation totaled 14.4 TWh (8.6% more y/y).

The power demand in the Polish power system varies between 10 GW and 28 GW. The average value illustrates the system situation in a given month. By observing the monthly minima and maxima, it has so far been noticeable that the summer months are characterised by significant power demand variability and high demand peaks around midday. However, these profiles are now changing, due to the dynamic emergence of heat pumps, which increase demand during the winter months, and air conditioners and photovoltaic installations, whose greatest impact can be observed during the summer months. 

• Net electricity exports totaled 0.2 TWh, or 1.6% of domestic demand.
• Most of the imported electricity came from Germany (0.6 TWh). Meanwhile, the largest net exports were to the south: 0.7 TWh to the Czech Republic and 0.3 TWh to Slovakia.

In the graph we observe the physical cross-border exchange of electricity, i.e. from which country we import and to which country we export energy in a given period. Addition values indicate that imports were the main direction in a given month and a negative value indicates that energy was mainly exported. Physical exchanges can be forced by system conditions or result from trade flows. The direction of electricity trade is mainly influenced by the price difference in the markets (energy flows from a country with a lower price to a country with a higher price). Cross-border exchanges with Germany, the Czech Republic, Slovakia, Sweden and Lithuania take place within the Single Day-ahead Coupling, as well as inter-operator exchanges. The exchange with Ukraine, which became possible from May 2023 thanks to the ENTSO-E decision, takes place within the framework of unilateral monthly auctions announced by PSE. Previously, the exchange only took place unidirectionally from Ukraine to Poland on the Zamość-Dobrotwór connection. Energy exchange with Sweden and Lithuania takes place via a direct current connection (HVDC). The electricity systems of the other countries are synchronised, hence the exchange takes place using alternating current lines (HVAC) and these are physical (not commercial) flows. 

• Electricity generation from renewable energy sources accounted for 38.9% of the generation mix; this share increased by 4.3 percentage points compared to last year.
  
  

The graph shows the share of renewable electricity in total production for a given month and year. The share of renewables in consumption may differ minimally from the visible values due to imports and exports. Since 2015, an expansion of wind sources is visible (higher % of RES in autumn and winter), while a dynamic expansion of photovoltaics (higher % of RES in spring and summer) is visible since 2020. 

• Wind power plants generated 17% of electricity (2.4 TWh, or 42% of renewable energy production), while photovoltaics accounted for 15.7% (2.3 TWh - 40.2% of renewable energy), 0.6% came from hydroelectric power plants (0.1 TWh - 1.5% of renewable energy), and 5.7% from biomass (0.8 TWh—14.7% of renewable energy).
• The remaining 61.1% of electricity came from fossil fuels: 31.4% from hard coal (4.5 TWh), 17.9% from lignite (2.6 TWh), 10.4% from natural gas (1.5 TWh), and 1.3% from other fossil fuels (0.2 TWh).

In the graph we see the percentage shares of electricity production by source. 

• Coal prices for the power sector (PSCMI1 index) rose by 4.8% over the month, to 14.4 PLN/GJ (approx. 318 PLN/t). Coal for heating plants (PSCMI2 index) costs 18.1 PLN/GJ (approx. 415 PLN/t), which represents a 1.5% decrease compared to the previous month.
• The weighted average price of natural gas delivered in September rose by 13% compared to August, to 230.3 PLN/MWh, which is 37.9% higher than a year ago.

The chart shows coal, gas prices on Polish and international markets, converted to a common unit (PL/MWh of energy in fuel) for comparability.  
*For coal, the domestic market is represented by the PSCMI1 index and the international market by the ARGUS-McCloskey CIF ARA API 2 index.  
*Natural gas in the domestic market is the weighted average (from POLPX data) delivery price for the month, while the international market for pipeline gas is represented by the TTF exchange index and for LNG by the Henry Hub index. 
For completeness, the chart also shows the price of CO₂ emission allowances from the primary market (trading on EEX). 

• According to estimates by Forum Energii, the electricity sector’s emissions amounted to 472.7 kg CO₂/MWh, which is 4.7% less than a year ago and 1.6% more than in August of this year.

Knowing the structure of electricity generation allows carbon dioxide emissions from electricity generation to be calculated. CO₂ emissions are calculated on the basis of reference fuel benchmarks adopted by the Energy Forum and calibrated to the reported emissions of the previous year. 

• The average hourly price for next year (in the so-called “strip”—the BASE instrument) traded 12.5% higher than a month earlier, at an average of 568 PLN/MWh, while the price during peak hours (PEAK5) was 12.5% higher, at 611 PLN/MWh. The price of electricity on the SPOT market (RDN) rose by 14%, to 665.5 PLN/MWh.
• The weighted average price of CO₂ emission allowances (EUAs) on the primary market was 84.6 EUR/tCO2, i.e., 3.8% higher than a month earlier. In September, the Polish budget received 2.1 billion PLN from the sale of CO₂ emission allowances on the primary market (EEX exchange), and 10.3 billion PLN has been collected since the beginning of the year.

The graph shows a comparison of the weighted average monthly prices on the POLPX. The Commodity Forward Market covers approximately 80% of the energy sales volume on the Polish Power Exchange.  
The two most important instruments relate to the delivery of energy around the clock (BASE) and from 7 a.m. to 10 p.m. (PEAK5). The contracts are concluded with delivery in the future (max. 3 years). The vast majority of transactions on the exchange are for the purchase of energy with delivery in the coming calendar year (n+1). 
On the basis of the contracts concluded in a given month, the volume-weighted average BASE_n+1 and PEAK5_n+1 indexes were calculated. This reflects the long-term situation on the electricity market. 
In contrast, the TGeBase Index relates to the Day-Ahead Market (with next-day delivery) - it reflects the current market situation and is characterised by high volatility. The weighted monthly average is usually lower than the prices in the Forward Market and seasonal dependencies are negligible.

• The CDS (Clean Dark Spread), an indicator of the margin for coal-fired power plants, stood at 81.5 PLN/MWh in September, representing 14.6% of the weighted average wholesale price of electricity supplied that month. Over the course of the year, this indicator rose by approximately 58.1 PLN/MWh (it stood at 23.4 PLN/MWh at that time).

The graph shows the Clean Dark Spread calculated from: historical contracts (BASE, PEAK, OFFPEAK) weighted by the share of deliveries in a given month (POLPX Commodity Futures Market), spot market contracts (POLPX Day-Ahead Market), coal prices (PSCMI1) and CO₂ emission allowance prices (EEX primary market).  
The Clean Dark Spread (coal-fired power plant variable cost spread indicator) is the difference between the electricity price and the estimated variable costs associated with coal-fired power generation (fuel and emission allowances). The Clean Dark Spread is an indicator correlated with the profit of the generator, producing electricity from coal (in reality, it is still necessary to take into account transport costs, operating costs, incurred and planned investment costs, etc.). The analysis of the evolution of this value, together with the CSS, allows the estimation of the current financial situation of the generating companies.  
The beginning of the bands corresponding to fuel or entitlements under the horizontal axis is due to the negative value of the CDS. 

• The CSS (Clean Spark Spread), which is the equivalent of a CDS for gas-fired power plants, stood at 43.6 PLN/MWh this month. In September 2025, it was approximately 25.5 PLN/MWh higher (69 PLN/MWh at that time).

The graph shows the Clean Spark Spread calculated based on: historical contracts (BASE, PEAK, OFFPEAK) weighted by the share of deliveries in a given month (POLPX Commodity Forward Market), spot market contracts (POLPX Day-Ahead Market), natural gas prices (POLPX Commodity Forward Market) and CO₂ emission allowance prices (EEX primary market).  
Clean Spark Spread (gas power plants' variable cost spread indicator) is the difference between the price of electricity and the estimated variable costs associated with the production of electricity from natural gas (fuel and emission allowances). Clean Spark Spread is an indicator correlated with the profit of the generator producing electricity from natural gas (in reality, it is still necessary to take into account transport costs, operating costs, incurred and planned investment costs, etc.). The analysis of the evolution of this value, together with the CDS, makes it possible to estimate the current financial situation of generation companies.  
The beginning of the bands corresponding to fuel or entitlements under the horizontal axis is due to the negative value of the CSS. 

• The weighted average price of electricity supplied in a given month consists of: forward contracts entered into in the past and transactions on the spot market (RDN and RDB). The spot price of electricity was 665.5 PLN/MWh, raising the average price of supplied electricity to 558.6 PLN/MWh. If electricity had been supplied solely based on forward contracts concluded last year, this figure would have been 468 PLN/MWh.

The chart shows the price profiles of electricity traded in three ways: 
*RTT - Commodity Futures Market, where electricity is traded in contracts executed at a contracted future, in weekly, monthly, quarterly and annual contracts; 
*RDN+RDB spot market (Day-Ahead Market and Intraday Market), where electricity is traded for delivery today or tomorrow; 
*OTC (Over-the-Counter) - over-the-counter (OTC) trading, mostly contracts concluded within energy groups. 
The price of electricity delivered in a given month is the average of these three prices, weighted by the volumes of electricity delivered at that price (shown in the chart below). 

• A correlation can be observed between the share of renewable energy sources (RES) in electricity generation and the price of electricity on the spot market. The highest time-weighted average hourly electricity price on the RDN market was 2,602.4 PLN/MWh, with a RES share of 14.1%. In contrast, the lowest electricity price (–37.4 PLN/MWh) occurred during an hour when the share of RES was 69.6%. Furthermore, most hours with a high share of RES are characterized by a price below the weighted average.

The first chart shows the distribution of volume-weighted average prices on the Day-Ahead Market and the share of renewables (RES) on individual days of the month. As the share of RES increases, electricity prices tend to decrease.

In the second chart, each point represents a single day of the month, and the slope of the trend line illustrates the relationship between electricity prices and the share of RES in electricity generation.

• On the Polish Power Exchange, trading volume (the sum of the volumes of futures contracts concluded) totaled 11 TWh, which is 65.4% more than a year ago (6.7 TWh). This is still 45.1% less than the average for September in 2018–22 (when the exchange’s trading obligation was in effect), which was 20.1 TWh.

Knowing the structure of the origin of the delivered volumes makes it possible to determine what proportion of the weighted average price is the result of trading on spot markets, where there is a clear correlation between the structure of the hourly electricity production mix and the price (the greater the production of photovoltaic installations and wind farms, the lower the price). Contracts traded on forward markets, where it is the physical delivery of electricity that takes place many months in advance, allow the risk of future price changes to be priced in. 

• The estimated balance of costs for imports of coal, oil, gas, and fuels for June (latest data) amounted to 12 billion PLN. Over the previous 12 months, we paid a total of over 110 billion PLN for net imports.

The graph shows the nominal (excluding inflation) monthly cost of imports of energy raw materials and fuels into Poland. This is a net import, i.e. it also includes exports from Poland of these products. 
*The coal category includes: anthracite, lignite, hard coal (thermal and coking coal) and hard and lignite briquettes. 
*The oil category includes crude oil and natural gas condensates. 
*Gas includes both pipeline gas and LNG. 
*Under the fuel category are motor petrol, diesel, LPG (fuel, not reagent) and various types of aviation fuel.