Distribución de frecuencias en la variable Negación de la

Redispatching aims to adjust generation (or load) patterns in order to change the physical ows in the network and to mitigate congestion. Generally two forms of redispatching can be distinguished, which dier in the determination of the generation capacity available for the redispatch. In cost-based redispatch, the determination of available generation capacity is based on the generation costs, whereas in the market-based redispatch (or counter-trading) a separate merit order curve is used to determine the available generation capacity. Both congestion management methods are described in the following. Redispatch is used in many electricity markets as preventive congestion management option. E.g. in Germany cost-based redispatch is applied, whereas in Nord Pool and Great Britain market-based redispatch is used.

Cost-Based Redispatch

Given the stylized power system of two regions and a transmission capacity of T C between both regions, the cost-based redispatch works as follows (see Figure 2.4). First, the spot market is cleared and a market price p∗

A = p∗B is

determined for the single market. The transmission capacity is not considered in this clearing procedure. Resulting generation in Region A and B are g∗

A and

g_B∗, respectively. Given the market result of the spot market, it is obvious that the exchange between both regions exceeds the available transmission capacity T C. The amount g_B∗ − QB represents excess generation in Region B and thus

the planned export to Region A. However, as g∗

B− QB exceeds the available

transmission capacity T C the export is operationally not feasible. Henceforth, the generation dispatch has to be adjusted to ensure feasibility. Therefore, the responsible transmission system operator reduced generation in Region B from g_B∗ to ˆgB so that the export equals available transmission capacity T C. On the

other hand, generation has to be increased in the decit Region A to ensure equality of demand and generation. Generation is increased from g∗

A to ˆgA and

the nal import in Region A equals the export in Region B.

In order to implement the redispatch, generators expect compensation pay- ments for reducing and increasing their generation. Generators in Region B pay their avoided costs to the transmission operator as their generation is reduced (grey area in Region B, Figure 2.4). Increased generation in Region A receive their additionally incurred marginal costs (grey area in Region A, Figure 2.4). For the transmission system operator, the redispatch results in additional costs, as payments to generators in Region A are higher than avoided marginal costs of generators in Region B.

Price

Quantity Quantity Quantity

Region A Region B p∗ A GA+ GB GA QA Price Price p∗ B QA+ QB QB gˆB T C T C g∗ B g∗ A gˆA GB Region A+B

Figure 2.4.: Cost-based redispatch. Source: Own illustration based on de Vries and Hakvoort (2002)

Eciency is guaranteed in the short-run as the cheapest available power plants are producing (Wawer, 2007). However, market participants do not internalize

the congestion and only power plants involved in the redispatch procedure are informed about congestion and receive signals on congestion (de Vries, 2001). Therefore, the congestion management approach does not give appropriate long- term signals to all market participants for ecient siting of power plants or demand. de Vries (2001) points out that redispatching provides ecient signals to the transmission system operator. As redispatching results in costs for the transmission system operator, he can balance the redispatching costs against the costs of a capacity expansion.17

Market-Based Redispatch / Counter-Trading

As in the cost-based redispatch congestion management method, the spot mar- ket is characterized by a uniform price for electricity if a market-based redispatch is used as congestion management method. Contrary to the cost-based redis- patch, available redispatch capacities are now determined in a market procedure using bids of market participants at which they are willing to increase or de- crease generation. In this case two additional markets are created in addition to the dayahead spot market: the redispatch market for the provision of addi- tional capacity and the redispatch market for the shutdown of capacity (Inderst and Wambach, 2007). This can also be seen as positive and negative redispatch capacity. In case of congestion, the transmission system operator will counter- trade against the ow of congestion by using available redispatching capacities until congestion is eliminated (Dijk and Willems, 2011). Thus, the market-based redispatching is also known as counter-trading.

The general procedure of the market-based redispatch is comparable to the cost-based redispatch (see Figure 2.5). Given the market result of the uncon- strained energy market, the exchange between both regions exceeds the available transmission capacity T C. Again, the amount g∗

B− QB represents the planned

export from Region B to A and exceeds the available transmission capacity T C. Therefore, the responsible transmission system operator reduced generation in Region B from g∗

Bto ˆgBso that the export equals available transmission capac-

ity T C. On the other hand, generation has to be increased in the decit Region A to ensure equality of demand and generation. Generation is increased from g_A∗ to ˆgAand the nal import in Region A equals the export in Region B.

In order to implement the redispatch, generators receive compensation pay- ments for reducing and increasing their generation. Generators in B should not be willing to pay more than their avoided marginal costs (grey area in Region B,

17 _{The theoretical incentive to balance redispatching costs against the costs of network}

Figure 2.5), whereas generators in A should not receive more than their incurred marginal costs (grey area in Region A, Figure 2.5). For decreasing generation, the transmission system operator accepts the highest oers and the lowest bids for increasing generation. Also in a market-based redispatch, the payments to generators in Region A are higher than avoided marginal costs of generators in Region B. Comparing Figure 2.4 and 2.5 indicates that resulting payments are at least as much as in the cost-based redispatch, but most likely to be more (de Vries and Hakvoort, 2002).

The determination and pricing of available redispatch capacities in a separate market can be designed either as discriminatory (pay-as-bid) or uniform-price (marginal bid) auction. Alternatively, the bids placed on the spot market or the reserve market may be used for the determination and provision of redispatch capacities (Inderst and Wambach, 2007; Wawer, 2007).

Price

Quantity Quantity Quantity

Region A Region B p∗ A GA+ GB GA QA Price Price p∗ B QA+ QB QB gˆB T C T C g∗ B g∗ A gˆA GB Region A+B

Figure 2.5.: Market-based redispatch. Source: Own illustration based on de Vries and Hakvoort (2002)

Similar to cost-based redispatch, eciency is guaranteed in the short-run as the cheapest available power plants are producing (Wawer, 2007). As a trans- parent and market-based market procedure is applied, the prices in the redis- patch market give generators long-run incentives to place new power plants in the decit region (Inderst and Wambach, 2007). As in cost-based redispatch, the transmission operator faces the costs of congestion management and can balance the costs against the costs of a capacity expansion. Hence, ecient sig- nals are provided to the transmission system operator to invest in transmission infrastructure.18

However, the simultaneous optimization of the bidding in the various markets will also present a more complex decision problem for power plant operators, which opens the possibility for an adverse behavior and resulting ineciencies in the short-run as well as long-run perspective (Inderst and Wambach, 2007;

18 _{Again, the theoretical incentives provided to the transmission system operator may be}

Wawer, 2007; Perekhodtsev and Cervigni, 2010; Dijk and Willems, 2011). The price on the redispatch market in the decit region can be higher than the uniform price on the spot market, as power plants that are not in-merit have to increase their generation. This could be anticipated by power plants in the decit region, including those who would operate at the spot market price due to their low marginal generation costs. In order to maximize their prots, they could withhold their capacity from the spot market in order to oer this capacity in the redispatch market. However, this assumes that the congestion can be predicted by the power plant operators. Due to the reduction of the generation capacity in the decit region, the decit appears even greater. In particular, this means that in comparison to the cost-based redispatch the spot price increases (Inderst and Wambach, 2007). Due to the anticipation of the congestion in the bidding behavior of the power plant operator and the resulting impact on the spot price, inecient long-run incentives for generation investments are created (Perekhodtsev and Cervigni, 2010).

2.3. Economic Evaluation of Congestion Management