Rachana Raizada, Contributor
July 03, 2012 | 1 Comments
Pigs haven't yet flown when the wind blows hard in Germany, but when considering unlikely scenarios, prices on the wholesale day-ahead spot market for electricity have plummeted to -500&€/MWh, while more than 700 km to the south, water flows uphill in the Austrian Alps.
Germany’s long-term commitment towards increasing its share of power from renewable energy sources (RES) through policies like generous feed-in tariffs (FiTs) has shown remarkable results. Preliminary estimates for 2011 from the Federal Environment Ministry show that RES accounted for 20 percent of German electricity supply and 12 percent of the total energy supply in 2011. Wind energy was the major contributor, accounting for 7.6 percent of German electricity production. Germany, with 29,075 MW of installed capacity, accounts for 12.2% of 2011 global wind generation capacity, according to the Global Wind Energy Council (GWEC). But the integration challenges posed by the intermittency of this resource shouldn’t be underestimated. In 2011, for example, almost one sixth of electricity generated from wind in Germany took place in just one month — December — with severe consequences for bordering countries with which it has grid interconnections, like the Czech Republic.
A twisted web of challenges is involved in integrating intermittent sources of energy like wind into a national grid. Liberalisation measures aimed at increasing supply-side market competition, market efficiency and, ultimately, consumer welfare don’t always have the intended consequences, while electricity — difficult to either store or direct — doggedly follows its own path of least resistance.
A ‘Unique Position’
Miroslav Vrba, who is responsible for Grid Operation Control and ICT for CEPS, a.s., the Czech Republic TSO, says CEPS’s special situation is a ‘unique position’. ‘We have a strong grid and very strong connections with all neighbouring countries, particularly with Slovakia for instance, since the grid was developed as one system,’ he says. ‘The dark side of the same coin is that the strong grid allows more flow than a weaker grid. As wind-production capacity in the Baltic area has regularly increased over the past 3-4 years we’ve seen several instances of overloading.’
CEPS is in a ‘unique position’ (Source: CEPS)
This January, CEPS published a statement describing a critical situation in the Czech transmission system between 25 November and 16 December 2011 stemming from increased unscheduled power flows of up to 3500 MW (the usual value is about 1000 MW). Apart from increased output from northern Germany on windy days, other contributing factors identified by CEPS were: the shutdown of eight nuclear power plants in Germany; an increase in installed German PV capacity; increased electricity imports in the Balkan countries due to water deficit at hydro power plants; and intensive electricity trading, especially on spot markets.
How the Market Works
Wind forecasts have been observed for years to have a strong impact on German spot-market prices for wholesale electricity, especially when domestic demand is low. Trading occurs either bilaterally (‘Over-The-Counter’) or through EPEX spot markets organised by the European Energy Exchange (day-ahead for Germany and Austria; intraday for Germany).
A study by Marco Nicolosi at the University of Cologne’s Institute of Energy Economics found that in times of high wind infeed and low demand, the day-ahead market reacts with bids underneath variable costs to avoid ramping-down base-load power plants (nuclear, lignite, hardcoal and gas), which are expensive to shutdown and restart. After September 2008, when EPEX allowed negative prices on spot markets, this phenomenon resulted in about 70 hours of negative prices in 2009.
In 2009, wind power wasn’t directly traded on the spot market but sharp price fluctuations were observed based on large predicted wind feed-in to the grid, particularly in low demand periods. Until 2010, renewable power was purchased from producers at fixed FiTs by German TSOs, which traded daily on the spot markets to balance scheduled against actual renewable energy production.
However, since 2010 TSOs have been required to sell the total quantity of power they have to purchase from renewable energy producers (based on the previous day’s predicted feed-in) directly on the exchange’s day-ahead auction. For any differences between volumes already sold via the auction and the feed-in based on the intraday forecast, TSOs will be required to balance them via the exchange’s intraday market. When the market is saturated (highly negative prices occur when energy is brought to market by the TSOs), the escalation steps followed after intraday trading are bilateral contracts to decrease generation or increase the load (demand) and, finally, bilateral contracts for the decrease of renewable generation. When network stability is endangered, the TSO applies non-costly and costly measures according to an escalation principle, but decreasing renewable generation is a measure of last resort and extremely expensive, as generators must be financially reimbursed.
Liberalisation measures encourage supply-side competition but energy demand in general is known to be inelastic. Dr Fabio Genoese, a researcher at the Fraunhofer Institute for Systems and Innovation Research ISI in Karlsruhe, Germany, co-authored a study on electricity market prices which found that negative prices occurred either with high wind feed-in (>12 GW) coupled with moderate system demand (40-50 GW), or with moderate wind feed-in (5-10 GW) coupled with low demand (<40 GW). The weak correlation between peak wind-production times and peak electricity demand creates greater opportunity for negative pricing to occur.
Genoese says negative pricing was allowed due to problems with clearing the market. While he doesn’t see negative prices as a problem as such, he feels that the 70 hours of negative pricing seen in 2009 and extreme negative prices are indicative of a regulatory problem and a lack of market liquidity. ‘After 2009 trading volumes and the number of traders on the spot market have increased, so we have seen fewer instances of negative prices.’
Germany and Austria
The 2011 trading volume in the day-ahead auction for Germany and Austria on EPEX SPOT accounted for 224 TWh (205 TWh in 2010), partly due to TSOs’ obligation to market RES power on the spot exchange. With an obligation to ensure priority dispatch and integration from RES and simultaneously act as a market player, the TSOs must continuously perform a delicate balancing act.
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