What does EU power market reform mean for Central and Eastern Europe power markets?

The current market fails to generate pricing signals allowing full cost recovery of power generation. The European Commission decided to introduce a set of measures to ensure generation adequacy and supply security. The measures are further detailed in network codes, explains Jan Ondřich.

The Berlaymont building in Brussels with flags of the European Union in front of it.

The headquarters of the European Commission in Brussels. (Photo by Gérard Colombat, modified, CC BY 2.0)


The European Commission (EC) realises that the current market fails to generate pricing signals allowing full cost recovery of power generation. The EC therefore decided to introduce a set of ambitious measures to ensure generation adequacy and supply security. Specifically, the EC wishes to:

  1. promote investment into new low-carbon energy systems;
  2. promote competition on the wholesale and retail markets;
  3. make retail part of the solution, i.e. retail-level consumers and producers should participate in the wholesale and balancing markets (e.g. via demand integrators and virtual power plants); retail pricing should be closer to real-time delivery;
  4. increase system flexibility and connectivity;
  5. make support schemes market-based, avoiding overcompensation and market distortion; and
  6. implement scarcity pricing method (i.e. commodity only pricing). Capacity payments should be considered measure of last resort and only on harmonised EU level as national schemes would lead to market distortion.

Those broad principles have been further detailed in new European network codes which will be binding across the EU. The proposed network codes can be categorised into the following three groups:

  • Connection Codes: include two codes that regulate connection requirements for generators and large customers and a third code, which specifies development of High Voltage Direct Current Connections (HVDC lines);
  • Operational Codes: these are three codes which specify how TSOs should operate within a single market; specifically, they are concerned with the grids’ operational security, planning and scheduling; the third code deals with frequency and load regulation;
  • Market Codes: these are three codes that deal with harmonisation of individual markets (day-ahead, intraday, futures markets and balancing markets).

Most importantly, the network package proposes the following unified market design throughout Europe:

  • day-ahead market: wholesale market in which transmission capacity and electricity are auctioned implicitly; market coupling will lead to prices diverging between regions only if the transmission grid is congested;
  • intraday market: operates under the same principles as the day-ahead market (cross-zonal capacity allocation and energy trading based on implicit continuous allocation), but closer to real time;
  • capacity calculation of interconnectors according to flow-based method;
  • definition of bidding zones (applicable for the day-ahead, intraday and longer-term markets) so that market participants will not have to buy transmission capacities separately.

Furthermore, the network package plans to merge national EU balancing markets into a single balancing market. Over time, these national markets should group into regional markets. Eventually the markets should aggregate into a single balancing market. Balancing services providers should be activated through a unified algorithm that selects providers from a common merit-order list based on marginal pricing (pay-as-cleared) method.

Currently, the flow-based market coupling system for day-ahead markets is already active in Western Europe. It is expected that Central and Eastern European countries (Poland, the Czech Republic, Slovakia, Austria, Hungary and Slovenia) will join in Q3 2018.

The key conclusion from the proposed EU energy market reforms seem to be that power prices will continue to be market-driven. The reforms will eliminate certain existing market inefficiencies (such as balancing cost allocation) and enable more efficient and less costly integration of renewables into the power market (for example by shortening trading intervals to 15 minutes). Overall, power systems will be more flexible and robust, as markets will be better connected and balanced across borders (e.g. through the introduction of an EU balancing market).

The reforms will also likely result in lower power prices in CEE countries compared to the policy status-quo. Better interconnection between markets and unified market design should lead to better allocation of resources. Power should be produced in the most cost-effective region based on actual weather, demand and commodity patterns.

Peak pricing in individual countries should be subdued as a result of peak times not being completely aligned between countries and therefore spare generation capacity being available to meet incremental peak demand. Introduction of demand-response management should further decrease a gap between peak and off-peak pricing as consumers with manageable loads could shift their consumption according to pricing signals. Continuous expansion of photovoltaic power would further level intraday price curve due to high generation at times of high consumption, in particular in summer.

Commodity costs should remain low due to better connection and organisation of gas markets. Eventual increases in carbon costs will be offset by the relative cheapness of coal and gas. Increased supply of renewables will further constrain power price increases. Decommissioning of the German nuclear fleet and withdrawal of certain lignite-fired power plants into the security reserve will be compensated by further deployment of renewables, in particular wind and solar.

Demand for electricity should remain constant even as economies grow. The EU policy proposals focus on increasing energy efficiency of final consumption and better demand management. Correlation between electricity consumption and real GDP growth has already been broken. Better demand management (e.g. peak-shaving and grid balancing through demand-response management) will help decrease congestion in grids and decrease magnitude of needed grid expansion, thereby decreasing the system cost for consumers.

by

Jan Ondřich

Jan Ondřich is a partner in market analysis and advisory firm Candole Partners. He is a regular contributor to this blog.

4 Comments

  1. S. Herb says

    This is assuredly not an area of expertise for me, but I also do not understand how cost recovery works here. Are there tacit assumptions regarding carbon tax level and the rate of coal and lignite retirement? What support mechanisms for renewables in various countries are assumed? How do lower prices lead to better cost recovery?

  2. Amory B. Lovins says

    Thanks for the useful summary. Was anything determined about allowing demand-side resources—end-use efficiency, load flexibility, and behind-the-meter distributed generation or storage—to bid into the same markets as supply resources, so they can compete directly?

  3. heinbloed says

    @ Amory Lovins:

    The EU parliament is demanding from the EU commission to draw up plans to standardize the legislation for non-bureaucratic micro generation:

    http://eur-lex.europa.eu/legal-content/EN/TXT/?uri=CELEX:52013IP0374

    The micro generators are plug-and-play generators, they feed into the grid without remuneration or FIT, so called “guerilla PV”

    Once this is becoming the norm (Switzerland, Portugal and the Netherlands have it already) power markets and competition cease to exist.
    Like planting a tree and not charging for the oxygen.
    Power will be donated free of charge to the grid if not used in-home/behind the meter.

    The big utilities are preparing themselves for this ‘market mechanism’ already, REs and grid management seems to be the last part in the electricity sector where money can be made.

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