This study analyzes local‐scale temperature and precipitation projections in the Shire River Basin (SRB) in Malawi using 10 global circulation models (GCMs) available in the coupled model intercomparison project phase 5 (CMIP5), under two representative concentration pathways (RCP 4.5 and RCP 8.5). For nine stations in the study area, large‐scale maximum temperature (Tmax), minimum temperature (Tmin) and precipitation data from the selected GCMs were downscaled by the sixth version of the Long Ashton Research Station Weather Generator (LARS‐WG6). The mean seasonal and annual change projections for Tmax, Tmin and precipitation during two future periods, that is, the middle future (2041–2070) and late future (2071–2100) periods were analyzed. Modelling results demonstrated that the LARS‐WG model is capable of simulating temperature more accurately than precipitation in the SRB. All 10 GCMs revealed that continually rising temperatures are anticipated in the study area; however, the projected magnitude of change varied across GCMs and between RCPs. Generally, the increase in average Tmax and Tmin was observed to be higher under RCP 8.5 compared with RCP 4.5 due to unmitigated greenhouse gas emissions (GHGs). Future precipitation change results showed more complexity and uncertainty than for temperature; not all GCMs agree on whether there will be positive or negative changes in precipitation and no systematic variations under RCP4.5 and RCP8.5 were observed during the two future time period, illustrating that both GCMs and RCPs are important sources of the relatively large uncertainties in future precipitation projections in the SRB. Thus, this study indicated that uncertainties constrained by both GCMs and RCPs are crucial and need to always be considered when executing climate impact studies and adaptation, particularly at river basin level.
Solar energy is currently dispatched ahead of other renewable energy sources. For the first time, this study presents a concept of exploiting temporary–periodical runoff discharge in the Shire River. Pumped hydro storage–photovoltaic plant (PHS–PV) was optimized to satisfy the all-day peak electricity demand in Malawi. The effect of varying the net head on the PHS system in both the generation and pumping operation modes was investigated. The bi-objective optimization evaluated the system reliability for day-time and night-time operation together with implied costs of investment for the whole system. The optimized system generated above 53% of added power as contrasted to single-source power generation from the existing hydropower plants. The estimated optimal capacities were 182 MWp (solar PV) and 86 MW (PHS plant). These additional optimal capacities achieved a 99.8% maximum system reliability (Loss of Power Supply Probability—LPSP—of 0.2%) and Levelized Cost of Energy—LCOE—of 0.13 USD/kWh. The overall investment cost of the PHS–PV system was estimated at 671.23 USD for an LPSP of 0.20%. The net head varies from 15.5 to 17.8 m with an impact on electricity generation of the PHS–PV system. More notably, the PHS–PV production matches with daily day-time and night-time peak loads and functions as a peaking plant.
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