Easing the flow across the network

EUROPE: When brisk winds are heralded for Denmark that will sharply increase output from the country's wind turbine fleet, electricity traders are on the alert. More power on the market will cause the cost of Danish electricity to fall. If it drops to a level lower than that in Germany, then cross-border trade would allow German consumers to also benefit from the cheaper power. And the Danish traders benefit by being able to sell their abundant power supply into Germany.

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Then, when the strong wind reaches northern Germany, the electricity generation of the turbine fleet in Schleswig-Holstein increases and the additional electricity on the German market causes German prices to drop to a similarly low level. If the hefty winds then leave Denmark but continue to blast northern Germany, Germany's surplus of wind power will continue to put downward pressure on German prices, making electricity traders keen to sell power into Denmark where prices will have risen again. 

In a perfect trading world, a Danish wind energy surplus would push down German prices as well as Danish, and a German wind energy surplus would similarly dampen Danish electricity prices, to the benefit of consumers in both countries.

But there is a hitch. Only two high-voltage transmission cables connect the electricity networks of the two countries. One connects the western Denmark network with that in Schleswig-Holstein. The other, running undersea, connects the eastern Denmark grid with that in the east German state of Mecklenburg-Vorpommern. The amount of electricity that can be transported by these interconnectors is limited to about 1.6GW.

Most of the electricity cables connecting Europe were built when electricity systems in each country were monopolised by a single or, at most, a few companies, each operating within their individual monopoly supply areas. Each utility ran its own system and had its own generation backup for emergencies. There was no competitive pressure on the higher costs of such "island" systems since these could easily be passed on to customers who, in those days, had no alternative suppliers that they could switch to.

These interconnectors were built between neighbouring countries' electricity grids not to enable trading and competition across borders but rather for the utilities to help each other out. Germany's system was based on fossil fuels and nuclear power, which operated most economically at a steady output, making Switzerland and Austria's hydro-generating capacities useful for providing electricity to Germany at times of peak demand. And when Austria or Switzerland's hydropower station water reservoirs were low, they could take electricity from Germany's coal, lignite or nuclear plants when German demand was low.

So interconnectors were built between those countries to cover this need. And, when German utilities took shares in French nuclear power stations built close to Germany's border, it needed interconnector capacity to bring the electricity from France to Germany.

How times have changed. As competition in the electricity markets has developed over the last 14 years (the European internal market for electricity directive was passed in December 1996), customers have pressed for lower prices, and inefficiencies have slowly been identified and dealt with. But the process has a long way to go to achieve a single integrated European electricity market in which competition between energy companies prevails.

And insufficient connection capacity between some of the national electricity networks is one of the key problems. Although building new interconnectors seems an obvious priority, progress has been slow due mainly to the long periods necessary for the planning process.
In the meantime, an efficient allocation for the scarce interconnector capacity that is available is crucial to make improvements towards an integrated European electricity market. This was not achieved until last November, when market coupling finally got underway in some parts of Europe. European Market Coupling Company (EMCC), responsible for operating the new system, reported in mid-January 2010 that it was running smoothly, benefiting all electricity trading, whether the power is sourced from nuclear and coal plants or wind and solar, notes Enno Bšttcher, managing director of EMCC.

Explicit auctions

Before the new system started, transmission capacity available on the two interconnectors was sold to electricity traders in tranches in annual, monthly and daily auctions, called explicit auctions. This happened completely separate from auctioning of electricity with the result that, due to the time lag in buying the transport capacity and the actual time of use, as well as other reasons, inefficiencies occurred.

Transport capacity could be bought ahead of time and hoarded, a form of market abuse. Or transmission capacity was bought for one direction, say from Germany to Denmark, which then turned out to be inappropriate because the price difference between the two was such that the electricity ought to flow in the other direction - from the low- to the high-price zone. In such instances, the electricity did then flow in the wrong direction, contradicting market forces, or not allowing extra capacity to be used - and traders and end users lost out. 

Explicit auctions were implemented for interconnectors at most European borders, recounts Bšttcher. "Even though this can be considered as progress compared to the formerly applied first-come, first-served or pro-rata regimes, explicit auctions still have many disadvantages," he says. Initially, explicit auctions of cross-border transmission capacity used a simplified model of electricity networks in each country.

The physical electricity transfer was mapped solely on the cross-border cable connections between the countries. In reality, however, the physical electricity transfer can change the stability of the electricity flow in the network of the receiving country and even affect cross-border connections between the receiving country and other countries. Until this was understood and taken account of, cross-border capacity made available had to be reduced by a considerable safety margin.

Today, explicit auction methods have become more sophisticated. The fundamental flaw, however, remains: that actual trade of electricity at energy exchanges in the different market areas is separate from transmission capacity, trading leading to market inefficiency. This can be reduced by combining cross-border transmission capacity allocation and electricity trade from one country or market area to another in a so-called market-coupling regime.

Market coupling uses implicit auctioning and focuses on the short term (day ahead), rather than months or a year ahead. The transmission capacity available on an interconnector the next day, as reported by the transmission system operators (TSOs), is matched with electricity bought or sold on the energy exchanges in the two countries involved for delivery the next day, creating a price for the transmission capacity and making it clear in which direction the market requires use of the transmission capacity of the cables.

Congestion charge

In effect, market coupling is a charge placed on the power exported or imported between countries when the network interconnector capacity is optimised to reduce congestion. The charge for this service, known as the congestion rent, is calculated according to the theoretical change in the prices for power in the two countries involved.

So, if Germany with lower prices, sells to Denmark with higher prices, Germany's power cost per unit theoretically rises slightly because there is greater demand, and Denmark's power cost per unit theoretically reduces slightly because there is now more power available. The market coupling cost is the difference between these two theoretical prices multiplied by the amount of MWh of power imported or exported. It is paid to the owners of the interconnectors between the countries, to be reinvested to enhance the grid quality or extend the transmission network. If there is no congestion on the network, there is no change in the electricity prices in the two countries, so there is no market coupling charge.

This was implemented at the Danish-German border. EMCC was set up as a joint venture by Scandinavian and Franco-German energy exchanges Nord Pool Spot and Epex Spot - companies that provide an electronic platform for the buying and selling of electricity and other energy related products for on-the-spot delivery, that is next day or within the day - and the TSOs in Denmark and Germany. These are Danish Energinet.dk in Denmark, west German Transpower and east German 50Hertz.

EMCC originally planned to start market coupling between Germany and Denmark in June 2008. But due to the complexities, the launch did not take place until November 2009. Since then about 90% of the traded electricity has been going in the right direction, according to the price signals, EMCC reports. Before market coupling, around 20% or more of the traded electricity was defying market logic and going in the wrong direction.

Extending the process

Market coupling to ensure efficient use of interconnector cables between Denmark and Germany is relatively simple, involving just two connecting cables, two TSOs and two energy exchanges. The ambitious aim of the European Regulators' Group for Electricity and Gas (ERGEG) is to introduce such mechanisms across Europe, allowing all the interconnecting cables between the different countries' high-voltage network systems to be used more efficiently.

In 2006, it set up the Electricity Regional Initiatives, creating seven regional electricity markets as a first step towards a single EU electricity market. Congestion management on the electricity networks is one of the priority areas of action, the German-Danish model of day-ahead allocation and the market-coupling model being one of the options.
Also, since November 2006, trilateral market coupling has been tested between Belgium, France and the Netherlands.

The more efficient exports and imports between the countries have resulted in a common market price in the three countries for 70% of the time, says Jalla Wils, spokesman for Dutch TSO Tennet. "We are aiming to go further with market integration by extending the system to Germany and Luxembourg," he adds. Originally planned for the end of 2009, the new date for the expansion is now June or July this year.

"Market coupling is a complex and long process with many parties involved," Wils stresses. But Tennet's acquisition of one of Germany's four TSOs, Transpower, finalised in February 2010, helps by making Tennet a stronger player, he states. If Belgian TSO Elia is successful in the current bidding to take over the German TSO 50Hertz, active in eastern Germany, the consolidation of TSOs in central west Europe will take another step forward.

"Such consolidation is helpful because we get to know each other's electricity households better and can fit them together in a better way. Our current systems are too nationally based," he says. "Ultimately the aim is for a flow-based market coupling where the physical flow of electricity is combined efficiently with what the market wants," he states.  
Integrated spot market

Running parallel, and building on the experience of the market coupling project between Germany and Denmark, and similar market-coupling projects within Scandinavia and on the Iberian peninsula, a cooperation was launched in October 2009 between Scandinavian energy exchange Nord Pool Spot, the Franco-German Epex Spot and the Spanish equivalent Operador de Mercado Iberico de la Energia, to deliver a day-ahead market coupling solution for Europe as a whole. A truly integrated European spot market for electricity would allow more efficient electricity marketing of variable wind generation. 
The first step in the project, the partners say, is to test the idea of a pan-European price coupling of regions. This means cooperation in spot electricity price formation between the energy exchanges in an area covering Portugal, Spain, France, Germany, Austria, Switzerland, Denmark, Norway, Sweden and Finland.

Annual electricity consumption across the area amounts to 1,900TWh, or over two-thirds of the European power market, of which more than 700TWh, or 37%, is traded on the day-ahead organised markets. With the support of the relevant power exchanges and TSOs, the concept has the potential to be jointly implemented on the Dutch, Belgian, British and Baltic areas and beyond, the partners say.

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