# Economic Feasibility of Underground Pumped Storage Hydropower Plants Providing Ancillary Services
## 3 Results and Discussion
### Estimation of Income and Expenses  
The storable amount of energy in UPSH plants depends on the net head and the water mass moved. The maximum income from selling energy has been studied considering the amount of electricity generated in turbine mode considering the maximum prices in the day-ahead and ancillary services markets. Likewise, the downward tertiary regulation service and the day-ahead market have been analyzed to obtain the minimum price for purchasing energy. Figure 4a shows the maximum prices in the day-ahead and ancillary services and the minimum prices in the downward tertiary regulation service, considering DTCs between 4 and 10 h. The price spread between the day-ahead and the ancillary services markets for generation and consumption modes is shown in Figure 4b. \begin{table}
\begin{tabular}{c c c} \hline
**UPSH Investment Costs (k\(\upxi\))** & **New Tunnels** & **Existing Infrastructure** \\ \hline Civil works & 525,692.80 & 218,083.58 \\ Hydromechanical equipment and penstock & 16,986.52 & 16,986.52 \\ Hydropower equipment & 99,709.12 & 99,709.12 \\ Electrical grid connection & 4510.50 & 4510.50 \\ Commissioning & 4140.85 & 3767.38 \\ Project management & 36,301.30 & 23,907.56 \\ \hline
**Total (k\(\upxi\))** & **687,341.10** & **366,964.67** \\ \hline \end{tabular}
\end{table} 
Table 1: UPSH investment costs analysis for construction of new tunnels or caverns and for making use of existing infrastructure. Concerning Figure 4a, the number of annual generation cycles is calculated to obtain the amount of electricity generated in turbine mode. The electricity consumed in pumping mode is estimated assuming a round trip energy efficiency of about 0.77. The annual generation cycles decrease from 360 to 323 when the DTC increases from 4 to 10 h. The maximum price of electricity is 78.74 \(\upxi\) MWh\({}^{-1}\) and is reached when participating in the ancillary services markets. That value, which corresponds to a DTC of 4 h, is progressively reduced by 7% when the DTC increases to 10 h. The minimum price in consumption mode is 22.13 \(\upxi\) MWh\({}^{-1}\). This cost for purchasing energy is increased by 22.81%, reaching 27.18 \(\upxi\) MWh\({}^{-1}\) when the DTC increases to 10 h. In Figure 4b, it is shown that the maximum price spread between the day-ahead and the ancillary service markets in generation mode is 24.92 \(\upxi\) MWh\({}^{-1}\). In consumption mode, the maximum price spread reaches \(-16.88\) \(\upxi\) MWh\({}^{-1}\). The price spread decreases by 2.36 \(\upxi\) MWh\({}^{-1}\) in generation mode and 1.42 \(\upxi\) MWh\({}^{-1}\) in consumption mode when the DCT increases to 10 h.  
For the purpose of analyzing the economic feasibility of the three HPSs considered in this study, the amount of energy generated and consumed and the maximum income from selling energy in generation mode (turbine) and minimum costs for purchasing energy in consumption mode (pumping) are shown in Figure 5 for the three HPSs. The maximum income decreases while the minimum expenses increase as the DTC increases from 4 to 10 h (see Figure 5d). Figure 4: Analysis of electricity markets. (**a**) Maximum electricity prices in the day-ahead and ancillary services markets; minimum costs in the downward tertiary regulation service and annual generation cycles. (**b**) Price spread between the day-ahead and the ancillary services markets. The design of the DTC influences the annual number of production cycles and therefore the amount of electricity generated.