March 2026 - Chaos on the fuel market

Electricity production

Production from renewable energy sources  

In March, renewable sources operated at an average capacity of 5.6 GW, accounting for 26.9% of the energy mix. This represents an increase of 10.5% compared to February 2026, but a decrease of 10.8% compared to March 2025.

Wind farms operated at an average capacity of 2.2 GW in March 2026 (40.4% of renewable energy capacity). This is 17.7% less than in February 2026 and 16.1% less than in March 2025. This is due to exceptionally low wind speeds for March. Installed capacity in wind farms (latest available data from early March) stands at 11.2 GW, representing an increase of 323 MW y/y or 3.0%.

PV installations operated at an average capacity of 2.3 GW in March (42.0% of renewable energy capacity), representing an increase of 126.6% m/m, but a decrease of 0.9% y/y. The decline compared to 2025 is due to very high curtailment of photovoltaic generation – had there been no curtailment of renewable energy, we would have seen a 2.9% y/y increase in output from PV installations. For the past three years, the rate of growth in photovoltaic capacity has remained very high, with large-scale installations, rather than prosumer installations, accounting for an increasing share of new capacity. Installed PV capacity (latest available data from early February) stands at 26.0 GW (an increase of approx. 20.4% y/y or approx. 4,402 MW per year), of which approx. 13.2 GW are prosumer installations (an increase of 9.4% y/y or 1,137 MW per year).

Biomass installations operated in March at an average capacity of approx. 0.7 GW, and hydroelectric power stations at 0.3 GW.

The maximum hourly share of weather-dependent renewable energy sources (wind and solar) in national electricity generation reached 53.7% in March, whilst the minimum stood at 1.1%. Meanwhile, the highest hourly share of these sources in electricity consumption was 64.0%.

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

In March, the transmission system operator was forced to carry out non-market curtailment of RES generation units for 206 hours (28% of the hours in the month) over a period of 25 days. These situations occurred mainly during the afternoon.

Electricity generation was curtailed by 219.6 GWh, or 8.1% of the potential output of weather-dependent RES. Of this, 161.0 GWh related to large-scale photovoltaic installations (16.5% of potential output).

Since the start of the year, production has been curtailed by 296.7 GWh. By way of comparison, in the corresponding period of 2025, curtailment amounted to 161.4 GWh (45.6% less), and in March of last year alone, 114.9 GWh, i.e. 47.7% less.

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 dispatch changes, broken down into PV and wind power. The curtailment of wind power generation during the winter months mainly takes place at night, when demand for power is at its lowest. However, with the sharp increase in photovoltaic generation in the following months, there is a significant energy surplus during the midday hours. This makes it necessary to also increase the curtailment of wind power. A seasonal shift is evident, with photovoltaics beginning to play a greater role in the mix, meaning that most curtailment takes place in the middle of the day.

Such a high level of curtailment of renewable energy generation is due to the need to maintain the stability of the electricity system, the low flexibility of coal-fired power stations, and the need to keep them operating at minimum capacity.

Production from fossil fuels 

In March 2026, gas-fired power stations and combined heat and power plants operated at an average capacity of 3.2 GW (a decrease of 28.9% m/m and an increase of 1.7% y/y), accounting for 15.3% of electricity generated.

The average capacity at which hard coal-fired units operated increased by 16.1% compared to March last year, and decreased by 9.1% compared to February this year (to 7.9 GW). The average capacity of lignite-fired units reached 4.0 GW. This represents a decrease of 2.5% y/y and 7.2% m/m. Most of Poland’s electricity came from coal. In total, coal-fired units operated at an average capacity of 11.9 GW (57.5% of the mix). This represents a decrease of 8.5% m/m, but an increase of 9.2% 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 March 2016 and March 2026, the share of coal in the mix fell by 22.6 percentage points. At the same time, the systematic development of renewable sources means that the gap between energy production from coal and from renewables is narrowing at an ever-faster rate. Furthermore, large natural gas-fired units are beginning to play an increasingly significant role in the mix.

However, significant seasonal differences remain evident – in winter, the level of generation from renewables remains markedly lower. This is primarily due to higher energy demand and the limited pace of development of onshore wind power, which could significantly increase production during months with low solar generation. The slow development of new wind capacity results in winter generation being more dependent 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.

The chart shows how the monthly shares of electricity generation from individual sources in total generation have changed over recent years.

March 2026 - details

• The average hourly power demand in March 2026 was 18.4 GW (0.1 GW more than in March last year), reaching a maximum of 22.9 GW (minimum – 13.1 GW).
• Electricity consumption stood at 13.7 TWh (0.6% higher than last year), whilst gross generation was 15.4 TWh (1.9% higher 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 0.8 TWh, i.e. 5.8% of domestic demand..
• Most of the imported electricity came from Germany (0.4 TWh). Meanwhile, the largest net exports were to the south, namely 0.9 TWh to the Czech Republic and 0.2 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 26.9% of the generation mix, an increase of 3.8 percentage points compared with 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 10.9% of electricity (1.7 TWh, or 40.4% of renewable energy production), with solar power accounting for 11.3% (1.7 TWh – 42% of renewable energy), 1.2% came from hydroelectric power stations (0.2 TWh – 4.6% of RES), and 3.5% from biomass (0.5 TWh – 13% of RES).
• The remaining 73.1% of electricity came from fossil fuels: 38.3% from hard coal (5.9 TWh), 19.1% from lignite (2.9 TWh), 13.8% from natural gas (2.1 TWh), and 1.8% from other fossil fuels (0.3 TWh).

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

• Coal prices for the power sector (PSCMI1 index) fell by 2.5% over the month, to PLN 14.4/GJ (approx. PLN 310/t). Coal for heating plants (PSCMI2 index) costs PLN 17.2/GJ (approx. PLN 398/t), representing a 0.1% increase compared with the previous month.
• The weighted average price of natural gas supplied in March rose by 4.9% compared to February, to PLN 179.4/MWh, i.e. 6.6% 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 were estimated at 554.5 kg CO₂/MWh, which is 5.4% higher than a year ago and 2.6% lower than in February 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 2.7% higher, at an average of PLN 433.9/MWh, whilst the price during peak hours (PEAK5) was 2.2% higher, at PLN 486.1/MWh. The price of supplies on the SPOT market (RDN) fell by 11% to PLN 453.3/MWh.
• The weighted average price of CO₂ emission allowances (EUAs) on the primary market stood at EUR 68.1/tCO₂, i.e. 7.8% lower than a month earlier. In March, PLN 0.9 billion was received by the Polish budget from the sale of CO₂ emission allowances on the primary market (EEX exchange), and PLN 2.9 billion has been received since the start 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), which serves as an indicator of the margin for coal-fired power stations, stood at PLN 43.3/MWh in March, representing 9.7% of the weighted average wholesale price of electricity supplied that month. Over the course of the year, this indicator rose by approximately PLN 3.9/MWh (it stood at PLN 39.3/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 stations, stood at 42.6 PLN/MWh this month. In March 2025, it was approximately 7.4 PLN/MWh lower (at 35.2 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 comprises: forward contracts entered into in the past and transactions on the spot market (RDN and RDB). The spot price of electricity was PLN 453.3/MWh, raising the average price of electricity supplied to PLN 445.2/MWh. If electricity had been supplied solely on the basis of forward contracts concluded last year, this figure would have been PLN 438.2/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 renewables in electricity generation and the spot market price of electricity. The highest weighted average hourly price of electricity on the RDN market was PLN 1,135.1/MWh, with a renewables share of 9.2%. Conversely, the lowest electricity price (-PLN 64.7/MWh) occurred during an hour when the share of RES was 43.1%. Furthermore, 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 volume (the total volume of futures contracts concluded) stood at 11 TWh, which is 48.7% higher than a year ago (7.4 TWh). This is still 36.6% lower than the average for March in the years 2018–22, which stands at 17.3 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 cost of imports of coal, oil, gas and fuels for December (latest figures) amounted to PLN 7.9 billion. In total, we paid almost PLN 104 billion for net imports in 2025. Data on natural gas imports ceased to be reported from August 2025, as the supplier invoked statistical confidentiality. Previously available historical data has also been removed. For this reason, data from August 2025 onwards consists of estimates based on balance sheet data.

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.