Market environment

Merit order

Organisation of the electricity market

The electricity market is organised in such a way that units with a lower variable cost have priority over units with higher costs. This rule is called „Merit order”. During the demand peak („PEAK”), a larger number of generating units is involved in satisfying demand than in off-peak hours („OFF-PEAK”), when electricity is generated only in the most economical units. Electricity in the peak is more expensive than outside the peak, but with the rapid development of photovoltaic sources in the summer, the price difference has decreased significantly. Conventional power plants can adapt their production to demand and market conditions as part of their technical capabilities. On the other hand, the supply of electricity from renewable sources depends only on atmospheric conditions.


Normal demand


High demand


Normal demand


High demand


Normal demand


High demand


Normal demand


High demand

Renewable installations (RES) – with almost zero variable cost, come first with guaranteed offtake, supported with RES certificates or in auction system

Combined heat and power plants –  treated as „must-run”, generating heat, electricity is an additional product

Autoproducers– “must run” CHPs generating for industrial purposes with ability to deliver surplus of electricity

Lignite power plants

Hard coal power plants

Pumped-storage units – working according to TSO needs, separately remunerated

Gas-fired units – working in condensation, their place in the merit order depends on the relation of gas prices to coal prices

The cost of electricity is made up of the following:

  • cost of investment, i.e. construction of the power plant. This cost is amortised over the plant’s lifecycle.
  • fixed costs, i.e. on-going maintenance: employee wages, repairs, equipment, etc. These costs are incurred regardless of whether the plant is producing electricity or not. From 2021, some power plants and combined heat and power plants receive revenues from the capacity market in return for the unit being ready to supply electricity to the system. These revenues help to compensate for the fixed costs incurred.
  • variable costs, i.e. how much it costs to generate each additional MWh of energy. The level of variable costs directly depends on the level of production. The main component of variable costs is the cost of fuel and cost of CO2 emission.

For different types of power plants, the relation between these costs varies. For example, for wind farms or photovoltaics, the cost of investment and its share in total costs are high. However, operating, fixed and variable costs are relatively low. In the case of conventional plants, variable and fixed costs are more balanced, largely depending on the cost of fuel and cost of CO2 emission.

Due to the rising prices of CO2 allowances and the decline in the prices of RES installations, the standardized cost of energy generation per 1 MWh (the so-called LCOE) is higher in Polish power plants for conventional energy than for renewable energy.

The price on the wholesale market is driven by variable costs, and more precisely – by the marginal cost to produce 1 MWh of electricity. Based on the level of these costs, from the lowest to the highest, a supply curve (merit order) is created. The point where the demand curve crosses the supply curve is the current market price of energy.

Fixed costs are incurred regardless of whether a given plant operates or not. Therefore, they have no present impact on the price of electricity.

High costs of investing in renewable sources (i.e. sources with low variable cost) are financed outside the electricity market, from subsidies that all consumers pay for.

Not all capacities are always available on the market. Therefore, the price is driven by their availability and by demand for electricity – lower at night, higher during the day, and seasonally shifting – higher in the winter, lower in the summer.

In Poland, we have limited water resources and limited capability of using solar energy, which translates into a limited number of plants fuelled by these forces of nature. This is why the most important renewable source is wind energy. It is wind conditions that largely determine the level of available capacity.

The most important factor in capacity availability is thus the weather. Therefore, the level of the availability of renewable capacities is variable, and there must always be an appropriate conventional capacity reserve, ready for immediate use whenever weather conditions make it impossible to generate energy from wind.

It is because variable costs have an impact on the price of electricity. For conventional plants, the main costs are: cost of fuel and cost of COemission allowances.

Wind farms, hydro plants and photovoltaic units do not incur these costs. Therefore, they are always first in the merit order. CHP plants are similar – their primary role is to produce heat, while electricity is generated in addition to that. Given the cost of fuel (coal, gas) and CO2 allowances, conventional plants are further out in the merit order. The variable production cost in conventional plants, of course, depends on the efficiency of fuel processing at the plant. Therefore, new units will offer cheaper electricity than existing ones.

The mechanism for setting prices based on variable costs was effective in a free market situation, undistorted by the subsidising of select technologies.

Subsidising the costs of investing in renewables has distorted the energy market, worsening the economics of conventional unit operations because these cannot operate at full capacity. In many markets, the operation of permanently or temporarily unprofitable assets is being limited. This may not be allowed on the market for electricity, which is one of the basic human needs. In disadvantageous weather conditions (e.g. no wind), there would not be enough energy, which would cause a blackout. This is destructive for the economy and for the regular life of people.

This is where the concept of capacity market comes in – as a market supplementary to the electricity market. Generating units receive additional funds from the capacity market in return for the unit being ready to supply electricity to the system. Thanks to the capacity market, available generation sources may receive a partial compensation resulting from the decline in wholesale prices, which previously covered variable costs and fixed costs. This allows for the ongoing maintenance and modernization of the power plant in order to ensure uninterrupted and reliable energy supplies.

The capacity market and the electricity market

The capacity market is a market separate from the electricity wholesale market and only indirectly influences electricity prices by ensuring stable power supply and a safe reserve.

Without the capacity market, the price on the wholesale market would have to increase (ceteris paribus) by reducing supply.

Thanks to the revenues from the capacity market, units that would otherwise have to be shut own, reducing supply could remain in the merit order.

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In addition, maintaining the power system reserve at an appropriate level reduces the price risk (limiting sudden increases in prices stabilizes the price) and the risk of interruptions in electricity supplies.

It is a market where electricity sellers compete with end users.

Retail market price includes:

  • electricity price from the wholesale market,
  • electricity distribution costs,
  • additional taxes and fees (directed to support RES or cogeneration)

From 2021, a capacity fee is collected – to finance the capacity market

Electricity prices – Domestic market

The situation on the domestic electricity market is crucial for the PGE Group operations. The main factors affecting the domestic market is the European Union’s climate policy, i.e. the listing of CO2 emission allowances and the cost of hard coal, i.e. the key fuel for the Polish power system. The weather has a significant impact on short-term price fluctuations.

Market/measure Unit Q4 2020 Q4 2019 % change 2020 2019 % change
RDN – average price PLN/MWh 246 211 17% 209 230 -9%
RDN – trading volume TWh 7.62 7.5 2% 28.73 28.42 1%

Factor Unit Q4 2020 Q4 2019 % change 2020 2019 % change
CO2 emission rights EUR/t 26.59 24.57 8% 24.14 24.66 -2%
Polish Steam Coal Market Index PSCMI-1 PLN/GJ 11.82 12.14 -3% 11.91 11.99 -1%
Wind generation NPS TWh 4.09 4.04 1% 14.17 13.9 2%
Ratio: wind generation/ NPS consumption % 9% 9% 9% 8%
Ratio: international trading/ NPS consumption % 7% 7% 8% 6%

In the fourth quarter of 2020, the average electricity price on the day-ahead market was PLN 246/MWh and was by 17% higher than the average price (PLN 211/MWh) in same period in the preceding year. The price increase was mainly related to net import lower by 8% in comparison to the fourth quarter of 2019. The price increase was also driven by demand for electricity higher by 1.1 TWh y/y.

In full year 2020, the average price on the day-ahead market was PLN 209/MWh, which is 9% lower than the price recorded in the preceding year (PLN 230/MWh). The decrease in price was connected with the situation on related markets – average price of CO2 emission rights in 2020 was by 2% lower than in the base year and amounted to EUR 24.14/t. The PSCMI1 index in 2020 averaged PLN 11.91/GJ – down by 1% y/y. On the other hand, price decrease pressure was exerted by the net import volume higher by 24% y/y and wind generation volume higher by 2% y/y. The prices were also affected by a decrease in demand by 3.9 TWh y/y.

* Average monthly level of DAM prices calculated on the basis of hourly quotations (fixing).

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Market/measure Unit Q4 2020 Q4 2019 % change 2020 2019 % change
BASE Y+1 – average price PLN/MWh 227 257 -12% 232 266 -13%
BASE Y+1 – trading volume TWh 29.09 34.33 -15% 126.75 118.04 7%
PEAK5 Y+1 – average price PLN/MWh 261 298 -12% 272 324 -16%
PEAK5 Y+1 – trading volume TWh 4 5.26 -24% 14.07 16.41 -14%

Electricity prices on forward market are shaped by the similar fundamental factors, as the prices on the Day-Ahead Market described in the previous section. The observed forward market decrease y/y for the whole year and fourth quarter of 2020 for BASE_Y+1 is related to increased cross-border transmission capacities and the inclusion of the supply of cheaper energy from abroad into the domestic market an. The drop in PEAK5_Y+1 contract price indicates a flattening of the supply curve and less optimistic demand forecasts, after taking net imports increase into account.

* Monthly average index level for forward contracts for the next year (Y+1), baseload and peak, weighted by the trading volume.

International market

Energy prices on European markets are shaped by a common set of fundamental factors, however, due to the diverse structure of the generation portfolio, the scale of the impact of these factors varies. There is a network of cross-border connections between domestic markets, but the balance of exchange is limited by technical factors.

In the fourth quarter of 2020, the y/y drop in prices on neighbouring markets ranged between PLN 18 and PLN 26/MWh (i.e. approx. 12-15%), whereas in Poland the average prices were higher by PLN 35/MWh y/y (approx. 16%).  The price spread between Poland and neighbouring countries is largely due to differences in realized coal prices in the country and abroad. The low correlation of energy prices results from differences in the technological mix (share of renewable energy sources) and the situation on the markets for related products. The price of hard coal in ARA ports fell by 17% y/y, while the domestic pulverised coal price index, PSCMI-1, decreased by just 1% over the same period.

On an annual basis, average energy prices on neighbouring markets dropped by PLN 27-56/MWh y/y (i.e. by approx. 17-33%), while the average price in Poland decreased by PLN 21/MWh y/y (approx. 9%). The price differential between Poland and neighbouring countries was largely attributable to differences in coal prices at home and abroad. Transmission capacities on cross-border connections which increased in the second half of 2019 enabled the import of higher volumes of cheap energy which contributed to reducing differences in wholesale prices observed in Poland and abroad. The reversal of the downward trend in the second quarter of 2020 is mainly due to the increases in prices of CO2 emission allowances in that period

Comparison of average electricity prices on Polish market and on European markets in 2020 (prices in PLN/MWh, average exchange rate EUR/PLN 4.44).


Source: TGE, EEX, Nordpool

Source: TGE, EEX, Nordpool

Source: ARP, Bloomberg (API21MON OECM Index), own work.


Source: own work based on PSE S.A. data.

Source: own work based on PSE S.A. data.

In the fourth quarter of 2020, Poland remained a net importer of electricity, and the trade balance was 3.0 TWh (import 3.5 TWh, export 0.5 TWh). The international trading balance was impacted mostly by import from Sweden (1.03 TWh), Czechia (0.83 TWh) and Germany (0.45 TWh). During whole year 2020 trade balance amounted to 13.1 TWh (import 14.7 TWh, export 1.6 TWh) and in comparison with the previous year (10.3 TWh) was by 2.8 TWh higher (27% y/y).

Geographical structure of commercial exchange in 2020 (in GWh).

Source: own work based on PSE S.A. data.

The diversity of electricity prices for retail customers in the European Union depends both on the level of the wholesale prices of electricity and fiscal system, regulatory mechanism and support schemes in particular countries. In Poland in the first half of 2020 an additional burden (over sale price and cost of electricity distribution) for individual customers accounted for 37% of the electricity price and in comparison to EU average of 36%. In Denmark and Germany the proportion of additional charges in the price of electricity exceeded 50%.

Comparison of average prices for individual customers in selected EU countries in the first half of 2020 (prices in PLN/MWh, average exchange rate EUR/PLN 4.41)

Source: own work based on Eurostat data.

Source: own work based on Eurostat data.

Prices of certificates

In the fourth quarter of 2020 the average price of green certificates (index TGEozea) reached PLN 141/MWh and was lower by 3% compared to the analogical period of the previous year. An obligation to redeem green certificates increased from 18.5% in 2019 to 19.5% in 2020 – as a result the demand for the certificates increased. On the other hand, the wind generation in NPS in the fourth quarter of 2020 was by 1% higher y/y. Moreover, the prices of certificates were affected by the awareness of limited supply thereof in future connected with the closure of a certification system for new units and the upcoming end of a 15-year support period for first installations that had entered the system in 2005. The average price of green certificates in 2020 was at PLN 138/MWh reaching a level lower than the substitute fee, which was PLN 165/MWh in 2020.

Average quarterly prices of green certificates (PLN/MWh).

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Source: Own work based on TGE quotations.

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Prices of CO2 emission rights

EUA (European Union Allowances) prices are one of the key factors determining wholesale energy prices and PGE Group’s financial results. Installations emitting CO2 in the process of electricity or heat production bear the expenses for purchasing EUA allowances to cover the deficit (i.e. the difference between CO2 emissions at PGE Group’s generating units and the free-of-charge allowances received under derogation in accordance with the National Investment Plan). Wherein, last allocations granted free of charge were planned for realisation of investment tasks for 2019. It means that the free allocations in accordance with the currently used method ended in 2020.

In the fourth quarter of 2020, the weighted average price of EUA DEC 20 reached EUR 26.59/t and was 8% y/y higher than the average price for EUA DEC 19 (EUR 24.57/t) in the similar period of the previous year. In the full year 2020 the weighted average price of EUA DEC 20 reached EUR 24.14/t and was by 2% y/y lower than the average price of EUR 24.66/t of EUA DEC 19 in the previous year (this is mainly due to the sharp collapse in prices caused by the outbreak of the pandemic). The increase in CO2 emission prices, lasting from 2017, is a result of market perception of the EU ETS reform.

Prices of CO2 emission rights


Source: own work based on ICE exchange quotations.

Emission rights granted free of charge for years 2013-2020

PGE Group’s installations accounts were credited with free allowances for heat for 2020 and energy for 2019.

In April 2020, 12 million tons of CO2 emission allowances were credited to the PGE installations’ account in connection with the production of energy in 2019. This value is not shown in the table below, which applies to production in 2020.

At the same time, redemption of emission rights resulting from CO2 emissions in 2019 was completed in April 2020.

Emission of CO2 in 2020 broken down into electricity and heat production compared to the allocation of CO2 emission allowances for 2020 (in tonnes).

Product CO2 emissions in 2020* Allocation of CO2 emission rights for 2020
Electricity 54,726,219
Heat 4,792,546 1,034,097
TOTAL 59,518,765 1,034,097

* Emissions verified

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