## 5 Case Study
The RES owners bid with prices greater than the day-ahead clearing price \(P_{s}\) for upward reserve because these bids require a voluntary derating of generators (10%) for creating upward margins with an immediate economic loss for producers. Regarding the downward bids, they might bid at zero or even negative prices if allowable by the \begin{table}
\begin{tabular}{c c c c c c} \hline \hline \multirow{2}{*}{**DER**} & \multirow{2}{*}{**Participation Level**} & \multicolumn{2}{c}{**Downward Reserve**} & \multicolumn{2}{c}{**Upward Reserve**} \\ \cline{3-6}  & & **Quantity (\%)** & **Price (EUR/MWh)** & **Quantity (\%)** & **Price (EUR/MWh)** \\ \hline RES & All & \(-100\%\) & 0 & +10\% & \(2\cdot P_{s}\) \\ \hline CHP & All & \(-20\%\) & \(0.9\cdot P_{p}\) & +20\% & \(P\)(fuel) \\ \hline End-Users &
\begin{tabular}{c} 25\% of industrial \\ customers \\ \end{tabular} & \(-5\%\) & \(0.9\cdot P_{p}\) & +5\% & \(1.1\cdot P_{p}\) \\ \hline \hline \end{tabular}
\end{table} 
Table 2: DER participation in the market: quantity/price pairs. Figure 2: Case Study. regulatory framework. A zero price bid means that the producer will receive the money corresponding to the energy curtailed at the market clearing price. The zero price bids are the most convenient for fuel power plants, but they are non-convenient for RES that do not have operational fuel costs such as thermal power plants. Conventional plants (e.g., CHP) that use fuel, offer a limited upward reserve at a price dependent on the fuel price \(P\)(fuel), which represents the most significant part of the production costs. CHPs have the priority to produce heat for the served thermal load, and thus a fluctuation not bigger than 20% of their instantaneous power production is allowed. For the downward reserve, the price should consider that it is necessary to switch on some electrical loads without changing the produced heat to reduce the power production exchanged with the grid. This can be convenient only if the price for purchasing energy in advance may be lower than the current purchasing price (\(P_{p}\)). Similarly, active end-users realistically may offer minimal quantities (\(\pm\)5%) to modulate their consumption for offering upward and downward reserve. It is worth observing that upward bids mean reducing the consumption of end-users, and downward bids mean increasing it. Reasonable prices for such offers will be low for purchasing energy in advance (i.e., lower than \(P_{p}\)) and extra valuated in case of load postponing (i.e., greater than \(P_{p}\)). In addition, DG units can support the volt/var regulation by exchanging reactive power with the grid for solving possible voltage violations caused by the variations in the active power setpoints of the DERs (included themselves) involved in the market. Concerning the remuneration for such a service, it is an open matter because, in several countries, the provision of reactive power by DG is considered to be free within the operating limits imposed by the current regulation. In this paper, the service is deemed to be paid at an administrative price of 5% of \(P_{p}\) (EUR/Mvarh) for considering the possible extra cost sustained by the DG owners for equipping their plants with a bigger than necessary inverter. The reactive power limits of DG units are defined according to the Italian technical rules for DG connection in MV networks [44], as allowed by the European standard [45]. The static generators are supposed to be connected through power electronics (i.e., inverters), while the CHPs are supposed to be directly connected. The capability curves used for defining the reactive power limits depend on the technology and size of generators.