Intensive coal-to-gas switching, which gathered pace in the electricity market at the beginning of this year, continued across the EU in Q2 2019 as gas prices headed to multi-year lows thanks to plentiful pipeline supplies and record LNG deliveries and as coal was heavily disadvantaged by rising CO2 prices. In some countries lignite-to-gas switching occurred as well. While EU-wide coal- and lignite-based electricity generation in Q2 2019 declined by 16% (or 17 TWh) year-on-year, gas-fired power production jumped by 39% (or 34 TWh), displacing coal and mitigating very weak hydro output in Southern Europe. In June, coal and lignite reached their lowest share in the EU power mix on record – 13%. The share of renewable energy in the EU power mix reached 35.1% in the reference quarter. This was lower than the 36.6% share from Q2 2018 and was mainly influenced by poor hydro generation. Total combined output of solar, wind and biomass generation in the reference quarter increased by 7.5% year-on-year to 145 TWh.
A very rare event of decoupling of several West European day-ahead markets occurred on June 7, distorting cross-border flows and influencing wholesale prices from London to Bratislava that day. The episode, which brought extreme volatility to some markets, demonstrated the possible effects of soft-ware failure at one of Europe’s most important exchanges.
Nuclear generation, which generally constitutes a third of the combined power mix of Czechia, Slovakia, Hungary, Romania and Slovenia, was up 4% year-on-year, broadly in line with a 3.2% increase in total generation during Q2 2019. High precipitation levels in the Danube basin in May and June helped hydro output in Slovakia and Romania increase by 45% and 16% respectively in Q2 2019 compared to Q2 2018. Some coal-to-gas and lignite-to-gas switching took place in Poland, Czechia, Slovakia and Hungary. Gas-fired generation in the four countries in Q2 2019 rose by 1.8 TWh year-on-year, whereas the combined coal and lignite output fell by 1.5 TWh year-on-year. Romania was an exception in this regard, registering a 0.5 TWh year-on-year fall in gas generation in the reference quarter, which had to be partly covered by increased imports from Ukraine. Hungarian imports of Ukrainian electricity in Q2 2019, at 1.2 TWh, were little changed from last year’s Q2. At the end of May, Hungary saw imports meeting as much as 50% of total consumption as maintenance and unplanned outages at the Paks nuclear plant and Matra lignite plant limited domestic generation. The impact on wholesale prices was negligible, though, due to ample interconnection capacity and large flows from neighbouring markets.
Wholesale markets in the South Eastern Europe region took a different path than the rest of the continent in Q2 2019, with baseload and peakload contracts rising throughout the reference period. From its trough in March at 55 €/MWh, the average monthly baseload price climbed to 62 €/MWh in June. The increase in April spread universally across all four markets on the back of rising fuel and CO2 prices and low hydro generation, but in May and June it was exclusively driven by Greece which suffered from reduced lignite generation and had to ramp up imports. Since the regional prices index is volume-weighted and Greece has by far the largest and most liquid market, it singlehandedly swayed the regional trend, even though Bulgaria, Croatia and Serbia registered decreases in their average monthly prices in May and June thanks to improving hydro conditions. The regional baseload contract in the whole of Q2 2019 reached 60.1 €/MWh on average, up 13% compared to Q2 2018.
Changes of the Bulgarian regulatory framework in the reference quarter have removed fees for the export and import of electricity, incentivizing more cross-border trading activity and creating opportunities for market co-pling with neighbouring countries and increased price convergence across the region. In another major legislative change, the mandatory participation of larger renewable generators on the liberalized market was introduced. This effectively brought renewable capacity to the free market and is expected to improve competition and liquidity on the local power exchange. It also means that weather patterns will start to influence Bulgaria’s spot prices more than before. The average Bulgarian baseload electricity price in Q2 2019 increased by 22% year-on-year to 41.2 €/MWh. A similar 17% rise occurred in Greece where the average baseload contract reached 65.5 €/MWh. The average Serbian baseload price rose by 8% year-on-year to 43.4 €/MWh, while the conditions on the Croatian market stayed unchanged at 42.5 €/MWh in the reference quarter.
Bulgaria is traditionally a net exporter of electricity. In Q2 of 2019, a volume of 0.7 TWh was transferred from Bulgaria to Greece (up from 0.5 TWh in Q2 2018) and 0.3 TWh from Bulgaria to Serbia (unchanged year-on-year). Some additional volumes from Bulgaria flowed to Greece via North Macedonia and Turkey.
Sources: DG Energy – Quarterly report on European electricity markets
