Henry Edwardes-Evans takes a look at the German renewables market, and how this form of energy could be integrated into conventional energy-only markets – giving gas-fired units some hope of a future balancing role.
It is fair to say that Enel chief executive Francesco Starace is not a fan of Brussels’ energy policy. Facing the press at the Italian utility’s investor day in London on March 18, Starace said current distortions in wholesale and renewable electricity markets ruled out any investment that carried a hint of merchant risk.
Enel likes to do things in style, flying in dozens of assistants and foreign correspondents to its investor presentation, laying on breakfast and lunch for the assembled journalists and analysts. This year, however, there was a spectre at the feast in the form of a six billion euro impairment loss. The black hole in Enel’s 2014 accounts included a €3 billion cut in the value of up-for-sale Slovak utility Slovenske elektrarne, and a €2 billion hit in the value of Enel’s conventional generation assets in Italy, nobbled by low power prices, waning demand and growing wind and solar output. No surprise, then, that Starace said Enel would not be building any new fossil-fired power plant in Europe while there was an absence of long-term price visibility.
Similar messages from Europe’s big utilities this year have all sought to placate investors tired of the sound of the shutters coming down on conventional plant assets.
While the sector is used to this by now, it still came as a shock when German utility E.ON announced March 30 that it planned to close its 550-MW Irsching-4 and 846-MW Irsching-5 combined cycle gas turbine plants in Bavaria in 2016. These units came on line in Q3 2009 and Q2 2010. They are top-of-the-class 60 per cent efficient peaking generators, representing €500 million-worth of Siemens’ best kit with an operational life of 25 years.
Two points are worth making. Firstly, the timing of this announcement is significant. Germany is looking, reluctantly, at the need for capacity payments, a strategic reserve or some way of compensating controllable, quick-response back-up plants. The government favours a re-designed energy-only wholesale market with sharper pricing signals, but in the meantime a whole raft of distressed German generators are threatening closures. E.ON’s announcement underlined that even new, flexible assets are at risk.
Which brings us to a second point: this is no bluff, on an economic basis and under existing market design, these plants should indeed close. German forward power prices do not warrant a strategy of toughing it out until nuclear and lignite plants close in the early 2020s, when it is reasonable to assume tighter capacity margins might start to inflate prices again.
As for the prompt market, this is where renewables are truly laying waste to returns. On March 31, German day-ahead baseload power prices dropped to their lowest level for a working day in over ten years.
A windy, sunny Spring has seen record wind and solar output levels, rising close to 40-GW on the last day of the month. The result was a day-ahead price of €15.75/MWh for baseload and €20.75/MWh for peak.
|Platts German Forward Assessments (Eur/MWh), March 30, 2015|
|Cal 2016||32.05 – 32.55||40.55 – 41.05|
|Cal 2017||31.50 – 32.00||40.25 – 40.75|
|Cal 2018||31.15 – 31.65||40.00 – 40.50|
Stellar growth for renewables
German solar capacity additions may have slowed to a trickle in recent months, but total installed capacity stands at 38.46 GW – it’s a huge dispersed fleet now, larger in aggregate than any other power source in the country. In April the country starts trialling its first capacity auctions for the technology, before rolling out the concept for other renewable technologies. This should set solar on track to hit a target ‘corridor’ of 2.4-2.6 GW of new plant every year.
Renewables’ combined generation accounted for 26.2 per cent of gross German electricity generation in 2014, beating lignite-fired generation into second place. Biomass, wind and solar power are established big hitters. Coal, lignite, nuclear, gas – the conventional techs are increasingly playing a supporting role.
German wind goes from strength to strength, defying expectation last year with 4,750 MW in capacity additions, 58 per cent more than in 2013 and the biggest annual gain on record. Wind output last year met almost ten per cent of German consumption.
The sector is fully mature, illustrated by the fact over 1,100-MW of the additions related to re-powering of existing wind farms with more powerful turbines.
The outlook for 2015 is for a net increase in wind capacity of 3.5 GW-to-4 GW, followed by a decline in 2016, albeit remaining at a high level, according to a Deutsche Windguard report.
Coming late to the scene, German offshore wind capacity has reached the one GW mark as installations in the North Sea and the Baltic more than doubled in 2014. Over two GW of offshore wind projects are in advanced stages of construction, but grid connection is progressing slowly and the expense of this form of generation is definitely a drawback – making it the preserve of the larger utilities.
With renewables growth comes volatility. Transmission system operators are understandably nervous about grid stability and want sufficient backup.
The question is how best to provide this. As noted, conventional generators want capacity payments. The German government is far from convinced, and is minded to improve current energy-only market design, augmented perhaps by a limited ‘strategic reserve’ system of around four GW of new, quick-response generation (most likely gas-fired) and demand response (consumers ramping down).
Capacity markets are essentially a national response to perceived wholesale energy-only market failure. By contracting capacity to be on standby at all times, these mechanisms drain risk and so price volatility from short-term power markets. With no volatility there is no signal to invest, prompting further intervention and all the unintended consequences that follow.
Speaking in London, Enel’s Starace characterised capacity markets as ‘aspirin to treat the fever, not the disease.’
“We have overcapacity now because ten years ago there was no long-term signal telling investors to stop building,” he said. “And we are going to suffer in ten, 12 years’ time because nobody is building now for the same reason – no signal.”
Wholesale power markets themselves need sharpening, Europe’s big utilities argue. First and foremost renewables need to be integrated, accepting balance responsibility and losing the privileges of priority dispatch and priority access.
Then the role of grid operators contracting capacity to balance the system needs to be rolled back, allowing the market to respond to scarcity pricing much closer to realtime. Regulators need to focus on implementing the cross-border intraday markets that will help this happen.
It’s a huge ask – but Germany appears to be listening and a moment of truth approaches: will Berlin re-boot the German wholesale power market and give scarcity pricing a chance to work?
Traders argue that the market can deliver security of supply more efficiently than top-down, belts-and-braces regulation. Policymakers seem to agree but are unlikely to resist intervening with some form of capacity support to make absolutely sure that the lights don’t go out.
Henry Edwardes-Evans is associate managing editor, Platts Power in Europe. Platts is a leading global provider of energy, petrochemicals, metals and agriculture information and a premier source of benchmark prices for the physical and futures markets. Platts’ news, pricing, analytics, commentary and conferences help customers make better-informed trading and business decisions and help the markets operate with greater transparency and efficiency. A free trial of Platts’ Market Data Direct can be accessed via http://trial.platts.com/market-data-direct
Issue 122 July 2015