After years of steady price declines, European power markets are dancing to a lively tune of nuclear outages, low wind and spiky Winter demand. Will prices rebalance once the current capacity squeeze is over? S&P Global Platts power reporters Henry Edwardes-Evans and Andreas Franke compare notes.
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HEE: Welcome to this Spotlight on European wholesale electricity prices with me, Henry Edwardes-Evans, and Andreas Franke, S&P Global Platts’ German power expert.
After several years of declining prices in continental Europe on the back of falling coal prices and surplus generation, in late 2016 near-term markets in France and its neighbours witnessed extreme volatility. Into this year, and we’re seeing multi-year highs in the German day-ahead power market. Andreas, what’s going on?
AF: well in France, we’re seeing that at times of peak demand the country has to import significant amounts of electricity when nuclear availability is hit.
If surrounding countries are also facing high demand because it’s cold, and if wind is low and nuclear down, then we have a developing problem.
For Germany, we’ve seen really low wind this week – below 5 GW, of nearly 50 GW installed. Nuclear is also reduced by winter refueling and maintenance stops. We think of Germany as Europe’s power supermarket, but this week prices are higher than at any time since 2012, averaging Eur67 a megawatt hour – compared to last year’s average of Eur29.
HEE: these nuclear issues are partly to do with safety checks in France and tax considerations in Germany, so are we to assume that this winter period of high pricing will soon subside, and we’ll be back down to 30 euros?
AF: the consensus is that once these problems have eased, prices will rebalance in 2017. But remember that prices in Germany had already ticked up from record-lows at the start of 2016, ahead of this winter’s dramatic price spikes.
The market now seems to agree that last year was the bottom of a downward spiral that started in 2012 on falling coals prices, booming renewables and a final surge in thermal plant additions.
Both day-ahead and year-ahead average power prices posted their fifth consecutive annual decline in 2016, but both ended the year higher for the first time since 2011, Platts data show.
HEE: now, we saw some sporadic signs of fuel switching in northwest Europe at times last year, could we see gas displacing coal this year?
AF: Coal and wind will remain the dominant and price-driving forces in German power -- both on the spot and on the curve -- but the impact of further plant closures and the volatile nature of wind power will be felt even more strongly in future.
Gas-fired power, which registered the only gains across conventional power generation sources in 2016, will further increase its share in the power mix although from a very low base.
But 'coal-to-gas-switching' episodes are likely to remain limited unless the 2016 trend of bullish global coal prices continues into 2017.
HEE: I’m just back from our East European power conference in Warsaw, where traders called for greater intraday market access, pushing TSO balancing timeframes back. Quite apart from today’s winter squeeze, traders are excited by the new volatility in power as renewables gain ground.
AF: indeed – and of course, volatility on the German spot market is nothing new, with Germany leading the way in moving intraday trading right up to delivery, supported by a policy framework built around the energy-only market.
But you know the medium term view remains bearish. German year-ahead power prices fell 14% on the year, the biggest annual percentage decline since 2013. Wind capacity additions were strong again last year. Solar has slowed right down, but it’s not that long ago that a raft of mis-timed new coal plants came online. Meanwhile at municipal level we’ve seen a rash of gas-fired cogeneration plants replace ageing infrastructure.
It is not until the country’s remaining eight reactors are closed in the early 2020s that Germany’s conventional plant margins begin to tighten.
HEE: meanwhile, however, dispatchable plant margins are set to drop by 22 GW in NW Europe over the next three years as old coal and oil plants are shut – could that support continental prices in the medium term?
AF: we wait and see – there are so many variables in the market, notably on the demand side in terms of efficiency, and at the distributed generation level. Then there are policy interventions – capacity markets prompting new plant investment, and old plant life extension. In Germany we’ve seen plant operators ordered to keep old power stations on line.
In the UK we’ve seen closures reversed to capture regulated earnings. Interventions tend to deaden market prices – it takes unusual circumstances, as in France this winter, to lift prices significantly.