3.1.3. Adequacy assessment

A.

How to interpret the LOLE criteria

The following indicative Figure 6-1 shows how to interpret the adequacy criteria. Many future states (or ‘Monte Carlo’ years) are calculated for a given winter or year in a probabilistic assessment (see Section 3.1.3.1). For each future state, the model calculates the LOLE (or ‘loss of load’) for each winter or year. The distribution of the LOLE among all studied future states can be extracted. For the first criterion, the average is calculated from all these LOLE results obtained for each future state. For the second criterion (95th percentile), all the LOLE results are ranked. The highest value, after the top 5% of values have been disregarded, gives the 95th percentile (1 chance in 20 of having this amount of LOLE). Both criteria need to be satisfied for Belgium, as specified in the Electricity Act.

EXAMPLE OF A CUMULATIVE DISTRIBUTION FUNCTION OF LOLE [FIGURE 6-1]

0 25 50 Average P95

95% of results are below this value

Average results. Sum of results divided by the number of results

P50

50 % of results are below this value

75

LOLE [h] 100 125 150

Depending on the values of these indicators, four situations can be derived from the results as represented in the table below (see Figure 6-2).

AVERAGE, P95 AND P50 LOLE INDICATORS [FIGURE 6-2]

LOLE P95 LOLE P50 Situation

0 0 0 No LOLE observed in any of the future states >0 0 0 LOLE in less than 5% of the future states

>0 >0 0

LOLE in more than 5% of future states but less than 50% >0 >0 >0 LOLE in more than 50% of the future states Expected Energy Not Served (EENS) [MWh/year or GWh/ year] is the average energy not supplied per year by the generating system due to the demand exceeding the available generating and import capacity. In reliability studies, it is common that Energy Not Served (ENS) is examined in expectation over a number of ‘Monte Carlo’ simulations. To this end, EENS is a metric that measures security of supply in expectation and is mathematically described by (1) below:

EENS = 1/N ∑ ENSj j∈S (1) where ENSj is the energy not supplied of the system state j (j ∈ S) associated with a loss of load event of the jth-Monte Carlo simulation and where N is the number of ‘Monte Carlo’ simulations considered.

Cross border capacity calculationB.

B.1. ‘Flow-Based’ versus ‘NTC’

‘Flow-Based’ is a term that englobes methods for capacity calculation which take more accurately the physical grid constraints into account (impedances, physical capacities). On the contrary the so-called Net Transfer Capacity (NTC) approach assumes only one commercial capacity between two market nodes (in each direction). In both the Flow-Based and the NTC, system operational security constraints are respected, fulfilling the N-1 criteria (see Section for more information).

While the NTC method is still used nowadays for capacity calculation on specific borders, the CWE region has moved some years ago towards a ‘Flow-Based’ method. Currently within the European Capacity Calculation and Congestion Management guideline, the Flow-Based capacity calculation framework is set as the target also for other regions in Europe.

IN NTC:

NTCs are typically calculated by TSOs per border between market areas and provide the maximal commercial capacity to be allocated. TSOs of neighboring market areas coordinate bilaterally to align the NTC values on their common borders. Nevertheless, in a NTC simulation approach each border is treated independently from other borders.

IN ‘FLOW-BASED’:

The Flow-Based method (FB) instead considers transmission capacity constraints for commercial exchanges between different market areas by considering the physical limits of every individual and relevant critical network element of the grid. The domain of possible commercial exchanges for market coupling is thus not limited by a generalization of exports viewed per border individually (NTC approach), but rather by a set of constraints considering the level of congestions on the critical network elements under normal (N) and grid contingency (N-1) situations. Different commercial exchanges will cause different physical flows on any given branch of the network. Therefore in the FB approach the different exchanges are not independent from each other.

In the next section, a detailed description of the FB method as applied currently in the Central Western Europe (CWE) day-ahead market coupling is presented.

B.2. The CWE Flow-Based operations

The Flow-Based (FB) method implemented in Central Western Europe (CWE) uses Power Transfer Distribution Factors (PTDF) that enable the approximation of real flows through the physical network branches as a result of commercial exchanges between bidding zones.

For each hour of the year, the impact of energy exchanges on each Critical Network Element (also called ‘branch’), taking into account the occurrence of network contingencies (N-1), is calculated. The combination of Critical Network Elements and Contingencies (CNEC’s) therefore forms the basis of the Flow-Based capacity calculation.

A reliability margin on each CNEC is considered to cover for unexpected flow variations and, where appropriate, ‘remedial actions’ are also taken into account. These actions can be taken by the TSO, preventively or after an outage has occurred, to partly relieve the loading of the concerned critical network element. Those actions allow to maximize the possible commercial exchanges thanks to changes in the topology of the grid or the use of phase shifting transformers. This procedure finally leads to a set of constraints which form a domain of safe possible energy exchanges between the CWE countries (this is called the ‘flow-based domain’).

Different assumptions are made for the calculation of these domains, such as the expected renewable production, consumption, energy exchanges outside the CWE area, location of generation, outage of units and lines, etc. For every hour there might be a different flow-based domain because for example: y the grid topology can change; y outages or maintenance of grid elements can occur; y the location of available generation units can vary.

The operational calculation of the FB domain for a given day is started two days before real-time operation and is used to define the limits of energy exchanges between bidding zones for the day-ahead market coupling.