As a means of getting wind power to consumers, the new system has been considered long overdue. The mechanism in place until the end of last year required expensive manipulation of mainly variable renewables power into a steady supply band through buying or selling additional power. Electricity market retailers were then told how much of the power they had to take, whether they needed it or not. With the amount of power handled in this way rising to 74TWh, or 16% of total consumption, in 2009, the disadvantages of the system could no longer be ignored.
Selling through Epex is seen as preferable as it is less costly and complex than the old mechanism. Wind and other renewables plant operators also continue to receive their premium feed-in tariffs as set out in Germany's renewable energy act. But while the system is still relatively new, market players have complained that it lacks transparency. They are concerned that Germany's regulator, the Bundesnetzagentur (BNA), is allowing the country's four transmission system operators (TSOs) to manipulate market prices.
The main concerns have so far revolved around negative pricing, which occurs when power supply outstrips demand and prices fall accordingly. TSOs pay a guaranteed feed-in tariff of about EUR90/MWh to wind operators. The TSOs sell the wind-generated electricity on the Epex spot market. The renewable energy levy paid by electricity consumers covers the difference between the feed-in tariff and the price achieved on the spot market.
In a rough calculation, if the spot market price for a particular hour falls to, say, minus EUR100/MWh, the difference that has to be covered by the renewables levy for that hour is EUR190/MWh - an economic burden shouldered by consumers. This is most likely to happen when incidences of high wind output and low demand coincide and, with increasing amounts of variable wind energy coming online, these are likely to become more frequent. The Epex spot and intra-day markets allow for negative spikes of minus EUR3,000/MWh and minus EUR9,999/MWh respectively, the latter being commonly referred to as the horror scenario.
But the German branch of the European Federation of Energy Traders, Efet Deutschland, is concerned that TSOs seem to be manipulating the market to prevent extreme negative price blips from happening. From a TSO point of view, this is necessary to prevent huge falls in price, which are very expensive for the TSOs because they effectively have to pay to offload the renewable power - as well as for the consumer, who ultimately foots the bill.
Trading on the spot exchange requires certainty and transparency and, Efet says, the new system provides neither of these. "Market players must be certain that absolutely all relevant renewable electricity that is forecast is bid on to the spot market, regardless of price," says Alexander Kox, head of electricity task force at Efet. "Market players can then prepare for this and plan their electricity procurement. But on very windy days price developments are being influenced by a non-transparent decision by the (relevant) TSO."
TSO 50Hertz, formerly Vattenfall Europe Transmission, has admitted it uses certain measures to prevent extreme negative prices. In a recent statement it said: "Since negative prices can mean extremely high additional costs, in such situations, and in accord with the federal regulatory authority (the BNA), measures to ease the situation, such as price limitation, can be implemented." Its options to limit prices include pumping water at its 1.06GW Goldisthal pumped storage power station in East Germany, effectively taking that power off the market and storing it for later.
This is of concern to Efet. The federation says the market can predict developments in daily renewables generation using weather forecasts and devise appropriate strategies to deal with negative pricing. But, because the TSOs and federal regulators appear to prevent these extremes from happening by taking decisions to limit negative prices behind closed doors, the traders' strategies are effectively being rendered obsolete. "A spot market influenced to such a massive extent by individual TSOs becomes much less attractive to market players," says Kox.
But the BNA argues that the market knows that TSOs can act when necessary to stop excessively negative prices arising. Spokesman Rainer Warnecke says that back in May 2009, the regulator issued a stipulation, aimed at the four TSOs, allowing certain exceptions to rules of marketing renewable electricity under certain circumstances, mainly when the wind is blowing strongly but demand is low. Last October, it also gave one TSO, 50Hertz, special dispensation to diverge from the rules on renewable energy because it has a particularly large amount of wind on its grid.
Last December, Warnecke says the BNA held a consultation involving the TSOs; energy companies; energy traders; Efet and the federal energy and water association, the Bundesverband der Energie und Wasserwirtschaft to discuss future rules to define more precisely the implementation of AusglMechV, as the regulation that paved the way for the shift to the new energy exchange is known.
At this consultation, Warnecke says it was made clear to participants that the rules, which officially took effect at the end of February, would include measures for dealing with negative pricing. Importantly, they allow TSOs to fix a negative price limit to stop "irrational" large negative price dips. Warnecke says each TSO will decide individually on the most appropriate negative price limit - and adds that all traders will be equally affected as none will have the advantage of prior knowledge. TSOs will also be able to request conventional power station operators to curtail their output at times of low demand and strong wind or invite consumers to up their power consumption, for instance by increasing industrial output at certain times. As a last resort, wind station operators can have their output curtailed. For now, Efet's protest has been to no avail, but the organisation is still in talks with the BNA and hopes the regulator will take on board its concerns about price-fixing.
Negative pricing is not always undesirable, certainly not for renewables generators. Market forces compel fossil fuel generators to reduce their production when demand falls and there is enough wind generation available. It hurts fossil-fuel generators far more than it hurts wind to pay to offload their production because they are paying for fuel. So when supply exceeds demand and prices fall, they stop producing first.
And, indeed, the market is beginning to think about ways of dealing with this new reality, says Tobias Federico, director of market analysts Energy Brainpool. "Negative prices are giving the right signals; the market is beginning to react," he says.
Negative pricing prompts energy market players to weigh up whether or not to keep on generating and effectively pay to have the power taken up by consumers or to reduce generation by scaling down output, or even closing plants temporarily. Their decision will depend on the costs of curtailing output - or even closing a power plant down and starting it up again - balanced against what they are paid for taking power from the market instead of generating it themselves.
Traders with power stations at their disposal are using a number of possibilities to adapt to negative pricing, says Torsten Marheineke, head of EnBW Trading. Even temporary closure of base-load power stations - nuclear and lignite-fired plants that generate more or less around the clock - is now on the cards, although in the past this was viewed as undesirable both from technical and economic points of view (see chart, page 66). One major energy company, RWE, says capacity at its nuclear power stations can be ramped up or down at a rate of 15MW a minute.
New avenues are also being sought for plants that have to stay online even when electricity demand is low but the wind is blowing strongly - for example co-generation stations that have to keep running to provide district heating or process heat for local industry. Municipality utilities are now making more use of auxiliary electricity-driven steam generators to generate heat when electricity is available at low or negative prices and allow temporary closure of their fossil-fuelled plant.
Pumped storage hydro plants are also adopting new habits. In the past, they usually pumped water from their lower to upper reservoirs at night when consumer demand is low. Now activity is governed by the electricity price and, especially, occurrence of negative prices.
For more on negative pricing, see the Integrated Europe Special Report with this issue
TO CLOSE OR NOT TO CLOSE? THE COST OF A TEMPORARY SHUTDOWN FOR THERMAL POWER STATIONS
With the prospect of negative pricing, thermal energy producers have to decide whether it makes economic sense to keep a plant running. Gas turbines are the cheapest to shut down, costing up to EUR5,000 to close temporarily.
For the operator of a lignite plant, the cost of taking the plant offline and starting it up again is EUR20,000-80,000. If taking a plant offline that operates at a minimum of 400MW for, say, four hours, the operator will only decide to close the lignite station if he can earn at least EUR20,000 an hour by bidding for power at negative prices over that time. To earn that EUR20,000 an hour, the negative price would need to be minus EUR50/MWh along with the electricity he takes. But taking into account the fact that the operator burns no lignite and requires no CO2 certificates over the four hours, the power plant operator saves around EUR30/MWh, so it pays to switch off the plant for four hours at a price of minus EUR20/MWh.
Overall, nuclear power stations are the most expensive to shut down, costing up to EUR250,000 to close and start up again.