November 2025 - Coal and gas - the dominant duo in energy mix

Electricity production

Production from renewable energy sources  

In November, 3.6 TWh (23.7%) of the electricity produced came from renewable sources. This represents a decrease of 33.2% compared to October this year and 0.3% compared to November 2024. This is one of the weakest RES results this year and is due to seasonally lower PV production and exceptionally poor wind conditions. This is the third year in a row that the share of RES production in November has been 23.7%.

According to estimates by Forum Energii, wind farms produced 1.8 TWh of electricity in November this year (51.5% of RES generation). This is 22.8% less than in November 2024 and 40.7% less than in the record-breaking October this year. The rate of growth in wind power capacity is slowing down, raising concerns about energy availability during the winter months. The installed capacity of wind farms at the beginning of November (latest data) was 11.2 GW, an increase of 5.9% y/y or 619 MW in a year.

On the other hand, PV installations produced 0.7 TWh (19.3% of RES generation) in November, which represents a 44.7% month-on-month decline in production, but a 92.4% year-on-year increase. The rate of growth in PV capacity has been equally dynamic for the last three years. However, most of the new capacity is now generated by large-scale photovoltaics rather than prosumer installations. Installed PV capacity at the beginning of October (latest data) was 24.9 GW (an increase of 22.8% y/y or 4,607 MW per year), of which approximately 12.8 GW were prosumer installations (an increase of 9.2% y/y or 1,085.7 MW per year).

Biomass installations produced approx. 0.9 TWh in November, and hydroelectric power plants 0.1 TWh.

The maximum hourly share of weather-dependent RES (wind and solar) in domestic electricity production reached 43.4% in November, and the minimum was 0.7%. Meanwhile, the largest hourly share of these sources in electricity consumption was 64.6%.

In the Polish power system, the share of RES in electricity consumption (i.e. the ratio of RES generation to total production from all sources plus imports and storage) is usually higher than the share of RES in production. In situations where the total power supplied in a given hour is higher than the current demand, it is necessary to use electricity storage facilities, export surplus energy, or even shut down RES sources.

In November, the system operator was forced to curtail RES generation units for 63 hours (9% of hours in the month) over 10 days. These situations occurred mainly around midday and at night.

The generation of 30.6 GWh of electricity was curtailed, which is 79.0% less than in October this year. 17.8 GWh of curtailments concerned photovoltaics (5.4% of potential production), of which 10.7 GWh took place on 1 November 2025. For the rest of the month, curtailment mainly affected wind sources – a total of 12.8 GWh (0.7% of potential production) in November. Total curtailment of RES sources in 2025 already amounted to over 1.3 TWh. By comparison, 731.4 GWh was curtailed in the whole of 2024.

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.

For most of the year, curtailment mainly affects large-scale photovoltaic installations. In winter, wind farms produce more electricity, so a change in the curtailment structure can be expected at that time. However, due to poor wind conditions in November, both wind energy production and curtailment were low. The chart below shows how the structure of RES curtailment changes between PV and wind power plants. A seasonal change is visible, when wind begins to play a greater role in the mix, while photovoltaic production declines.

Such a high level of reduction in renewable energy generation is a 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 minimum technical capacity.

Production from fossil fuels 

In November 2025, gas-fired power plants and combined heat and power plants produced 2.8 TWh of electricity (an increase of 14.6% m/m and 12.4% y/y). Gas has once again confirmed its role in the Polish power industry, as electricity generated from gas fuels accounted for 18.4% of the energy mix, the highest share in history.

Hard coal production fell by 4.9% compared to November last year, but increased by 14.5% compared to October this year (to 5.8 TWh). Production from lignite reached 2.8 TWh. This is a decrease of 3.2% y/y and an increase of 8.2% m/m. Once again, most of the electricity in Poland came from coal, i.e. 8.7 TWh (57.5% of the mix). The last time this happened was in March this year. This is an increase of 12.7% m/m, but still a decrease in production of 4.3% 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 November 2015 and November 2025, the share of coal in the mix decreased by 21.7 percentage points. The systematic development of renewable sources means that the difference between energy production from coal and from RES is decreasing at an ever faster rate. In addition, large natural gas units are beginning to play an increasingly important role.

However, significant seasonal differences are still visible – in winter, the level of generation from renewable energy sources remains significantly lower. This is mainly due to higher demand and the limited pace of development of onshore wind energy, which could significantly increase production in months with low solar generation. The slow development of new wind power capacity translates into greater dependence of winter generation on conventional sources.

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

November 2025 - details

• The average monthly power demand in November 2025 was 19.4 GW (0.1 GW more than in November last year), reaching a maximum of 26 GW (minimum – 12.1 GW).
• Electricity consumption amounted to 14.0 TWh (0.7% more than last year), while gross production amounted to 15.1 TWh (0.6% less 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 amounted to 0.3 TWh, i.e. 2.1% of domestic demand.
• Most of the imported electricity came from Germany (1.1 TWh) and Sweden (0.4 TWh). In turn, the largest net exports were to the south, i.e. 0.6 TWh to the Czech Republic and 0.4 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 23.7% of the generation mix, an increase of less than 0.1 p.p. 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 farms generated 12.2% of electricity (1.8 TWh, or 51.5% of RES production), photovoltaics accounted for 4.6% (0.7 TWh – 19.3% of RES), 1% came from hydroelectric power plants (0.1 TWh – 4% of RES), and 6% from biomass (0.9 TWh – 25.2% of RES).
• The remaining 76.3% of electricity came from fossil fuels: 38.6% from hard coal (5.8 TWh), lignite 18.9% (2.8 TWh), natural gas 17% (2.6 TWh), and other fossil fuels 1.8% (0.3 TWh).

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

• Coal prices for the power industry (PSCMI1 index) fell by 6.9% over the month, to PLN 14.3/GJ (approx. PLN 305/t). Coal for heating plants (PSCMI2 index) costs PLN 18.7/GJ (approx. PLN 431/t), which represents a 3.4% decrease compared to the previous month.
• The weighted average price of natural gas supplied in November fell by 2.1% compared to October, to PLN 173/MWh, i.e. 19.1% less 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). 

• Emissions from the electricity sector amounted to an estimated 8.5 million tonnes of CO₂, i.e. 2.4% less than a year ago and 12.1% more than in October 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. 

• Uniform delivery at every hour of the day next year (in the so-called strip – BASE instrument) was traded 3.4% higher, at an average of PLN 450.6/MWh, and during peak hours (PEAK5) 2.7% higher, at PLN 508/MWh. The valuation of supplies on the SPOT market (RDN) increased by 20.2% to PLN 537.9/MWh.
• The weighted average price of CO₂ emission allowances (EUA) on the primary market was EUR 80.6/tCO₂, i.e. 3.4% more than a month earlier. In November, PLN 1.5 billion was transferred to the Polish budget as a result of the sale of CO₂ emission allowances on the primary market (EEX exchange), and PLN 15.6 billion has been transferred 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.

• CDS (Clean Dark Spread), which is an indicator of the margin of coal-fired power plants, amounted to PLN 35.1/MWh in November, representing 7.3% of the weighted average wholesale price of electricity supplied in that month. During the year, this indicator fell by approximately PLN 71.5/MWh (it was PLN 106.6/MWh at that time). According to the current forecast, CDS in 2025 will average PLN 18/MWh, representing 4.0% of the weighted average wholesale price of electricity supplied.

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. 

• CSS (Clean Spark Spread), which is the equivalent of CDS for gas-fired power plants, amounted to PLN 73.1/MWh this month. In November 2024, it was higher by approx. PLN 39.9/MWh (PLN 113/MWh at that time). According to the current forecast, CSS in 2025 will average PLN 36.2/MWh, representing 8.0% of the weighted average wholesale price of electricity supplied.

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 concluded in the past and spot market transactions (RDN and RDB). On the spot market, the price of electricity was PLN 537.9/MWh, raising the average price of electricity supplied to PLN 482.1/MWh. If electricity had been supplied solely on the basis of forward contracts concluded last year, this value would have been PLN 449.3/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). 

• There is a correlation between the share of renewable energy sources in electricity production and the price of electricity on the spot market. The highest weighted average hourly price of energy on the RDN market was PLN 1,614.5/MWh, with a 12.0% share of renewable energy sources. In turn, the lowest electricity price (PLN 32.3/MWh) occurred at a time when the share of RES was 51.8%. In addition, most hours with a high share of RES are characterised 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 (the total volume of futures contracts concluded) amounted to 6.4 TWh, which is 4.6% less than a year ago (6.7 TWh). This is still 58.8% less than the average for November in 2018-22, which is 15.5 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 balance of costs for imports of coal, oil, gas and fuels for June (latest data) amounted to PLN 6.2 billion. Over the previous 12 months, we paid a total of over PLN 103 billion for net imports. It should be noted that since the embargo on LPG imports from Russia was introduced at the end of 2024, imports from this direction were expected to fall to zero. However, there was a noticeable jump in imports of hydrocarbons from this direction, which can be used for fuel production. By July 2025, these costs amounted to approximately PLN 401.4 million. According to the 19th package of sanctions, this gap should be closed by the end of January 2026.

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.