Modelled outcomes including annual electricity production, total annual capacity, electricity imports and exports, carbon dioxide emissions, and total system costs of the six scenarios are shown in this section.
3.1. Annual Electricity Production
Figure 2 shows the annual electricity production for all scenarios in the years 2025, 2030, 2040, and 2050. The NZ and CET scenarios have a higher total generation that the remaining scenarios, mainly due to the increased uptake of electric vehicles and renewable energy storage technologies. Nonetheless, the CET scenario has a lower amount of total generation compared to the NZ scenario, due to a high market penetration of energy efficient technologies that can drive down consumption rates.
Detailed annual electricity production rates for each technology in the years 2025, 2030, 2040, and 2050 for each scenario are in Appendix 1.
Power Development Plan VII (revised)
As seen in the modelled PDP 7 (rev) scenario (Fig. 3), annual electricity production is predominantly coal-based. This proportion increases each year to leave little room for the expansion of renewable energy technologies. In more detail, electricity generation is expected to increase rapidly to 1,850 PJ by 2050, roughly a 97% increase from 2025’s value. Of this, coal is expected to supply 1,001 PJ in 2050. In comparison, solar PV and wind are expected to contribute 41 PJ and 14 PJ only in 2050.
Power Development Plan VIII (draft)
Figure 4 shows the annual electricity production under the PDP 8 (draft) scenario. There is a larger proportion of renewables such as wind and solar compared to PDP 7 (rev). By 2050, coal is expected to provide 908 PJ, with solar PV and wind supplying 197 PJ and 359 PJ, respectively. 176 PJ of the latter is offshore wind. However, there is also a larger reliance on imported electricity. From 2030 onwards, imported electricity is expected to supply 187 PJ.
Renewable Energy Development Strategy
The REDS scenario pushes for an increase of renewable technologies up to 2050 to displace fossil fuel technologies, and this can be seen in Fig. 5, where production of natural gas is phased out in 2024. However, the strategy’s targets may not be enough to reach net zero as the Figure shows that coal is still a dominant supplier in the energy mix in 2050. Of the expected 1,851 PJ demand in 2050, 893 PJ consists of coal, with solar PV and wind contributing 255 PJ and 64 PJ, respectively.
Renewables-Led Pathway
Figure 6 shows a significant increase in wind, solar, and natural gas under the RLP scenario. There is a slight decrease in coal after 2026, due to the integration of renewable technologies, and the value stays relatively level at roughly 230 PJ, however this value picks up slowly after 2038 to reach 779 PJ by 2050. Natural gas reaches 192 PJ in 2030 and stays the same until the end of the modelling period. Similarly, solar PV and wind reach 136 PJ and 145 PJ in 2050.
Net Zero
The NZ scenario forces coal to be out of the generation mix by 2040, and fossil fuel 2050, as seen in Fig. 7. To supplement this, large proportions or wind, solar PV, and CSP are picked up. Additionally, total electricity production is greater than other scenarios due to an uptake of additional energy technologies such as electric vehicles. In 2050, electricity production is expected to be 5,546 PJ. Of this, solar PV may contribute 2,018 PJ, CSP 949 PJ, and wind power 1,976 PJ. Hydropower production is expected to stay the same after 2025, at 582 PJ.
Clean Energy Transition
Figure 8 shows the annual electricity production for the CET scenario. Coal and natural gas can be seen out of the generation mix by 2030 and 2040, respectively. The total annual electricity production is also lower than the NZ scenario, due to the high market penetration of energy-efficient technologies in the scenario. Sustainable biomass is seen to take up a significant proportion of the load throughout the modelling period, reaching 1,515 PJ in 2050. On the other hand, the level of CSP is lower than that of the NZ scenario, as it reaches 192 PJ in 2050. Nonetheless, solar and wind are at 1,002 PJ and 1,074 PJ in 2050. Hydropower is also expected to provide 582 PJ annually from 2025 to 2050.
3.2. Total Annual Capacity
Figure 9 shows the total annual capacity for all scenarios in the years 2025, 2030, 2040, and 2050. The NZ and CET scenarios have a higher total capacity that the remaining scenarios, mainly due to the increased uptake of intermittent renewable energy technologies such as solar and wind power. Nonetheless, the CET scenario has a lower amount of total capacity compared to the NZ scenario, due to a high market penetration of energy-efficient technologies that drive down consumption rates.
Detailed total annual capacity levels for each technology in the years 2025, 2030, 2040, and 2050 for each scenario are in Appendix 2.
Power Development Plan VII (revised)
Figure 10 shows that the PDP 7 (rev) scenario will have a large capacity of coal throughout the modelling period, reaching 43 GW in 2050. Additionally, hydropower reaches its maximum capacity of 38 GW IN 2046 and stays at this level until 2050. Similarly, natural gas reaches and stays at a capacity level of 8 GW from 2025 onwards. There are minimal levels of solar PV, wind, and geothermal in this scenario, as they reach 11 GW, 3 GW, and 0.4 GW in 2050.
Power Development Plan VIII (draft)
The PDP 8 (draft) scenario shows a larger amount of natural gas, solar, and wind in the capacity mix, as they grow gradually throughout the modelling period, as seen in Fig. 11. By 2050, these technologies are at a level of 67 GW, 55 GW, and 61 GW. Coal and hydropower is expected to contribute 50 GW and 21 GW to the capacity mix in 2050.
Renewable Energy Development Strategy
As shown in Fig. 12, the REDS scenario expects a large proportion of its capacity mix to be from solar PV. By 2050, the capacity is modelled to be 71 GW, which is almost a 10 times increase from the scenario’s 2025 value. Wind power is expected to reach a lower capacity of 12 GW, which is roughly a four times increase from 2025.
Renewables-Led Pathway
Figure 13 shows the total annual capacity for the RLP scenario. Similar to Fig. 6, there is a slight decrease in the capacity of coal due to the uptake of renewable technologies such as solar PV and wind. By 2050, solar is expected to reach 38 GW and wind is expected to reach 28 GW. Hydropower also supplies 38 GW of capacity by 2050. Thus, capacity is roughly split equally between solar, wind, and hydropower technologies.
Net Zero
The NZ scenario expects a large amount of capacity from solar PV and wind power. Figure 14 shows that by 2050, solar and wind are expected to reach 514 GW and 378 GW, respectively. Modelling also suggests that there is a rise in CSP capacity, from 0 GW in 2033 to 173 GW in 2039, where it stays until 2050. Hydropower is also expected to reach its maximum capacity of 38 GW in 2023, staying at this level until 2050.
Clean Energy Transition
Figure 15 shows the total annual capacity of the CET scenario. Similar to the NZ scenario, there is a large amount of solar PV and wind power in the capacity mix as they reach 256 GW and 209 GW in 2050. The CSP proportion in the CET scenario, however, is lower, reaching 35 GW in 2031 and staying at this level until the end of the modelling period. Sustainable biomass is expected to increase gradually to 69 GW in 2050 and hydropower is also modelled to reach its maximum capacity in 2025, staying at this level until 2050.
3.3. Electricity Imports
The electricity import for each scenario varies over the modelling period. As seen in Fig. 16, the PDP 8 (draft) scenario is expected to import the most electricity from neighbouring countries at an annual level of 6 GW from 2030 to 2050. The NZ and CET scenarios are expected to be vary over time. The NZ scenario reaches peak import at 3 GW in 2034 before diminishing down to a value of roughly 0.7 GW by 2050. The CET scenario reaches peak import earlier, at 3 GW in 2026 before decreasing down to an annual capacity level of 0.8 GW from 2032 to 2050. Alternatively, the levels of electricity import in the PDP 7 (rev) and RLP scenarios are constant throughout the modelling period, at 0.6 GW and 1.5 GW, respectively.
Figure 17 shows the accumulated electricity import amount from the six scenarios over the modelling period. Modelling suggests that PDP 7 (rev) will import the least amount of electricity at 23 GW, followed by the CET scenario at 30 GW. On the other hand, PDP 8 (draft) will import the most electricity from neighbouring countries, at 160 GW.
3.4. Electricity Exports
The PDP 8 (draft) scenario is expected to export the least amount of electricity over the modelling period, as shown in Fig. 18. Alternatively, the CET scenario reaches a maximum export of 1.8 GW in 2030 and stays at this annual level until 2040, when it dips down to 1.6 GW. Similarly, NZ and RLP reaches this maximum amount in 2032 and 2039. The NZ scenario, however, dips down to 1 GW in 2043 before rising back up to the maximum level.
Figure 19 shows the accumulated electricity export amount from the six scenarios over the modelling period. Modelling suggests that PDP 8 (draft) will export the least amount of electricity over the modelling period, at a total of 9 GW. On the other hand, NZ will export the most electricity to neighbouring countries, at 45 GW, due to the high amount of renewable energy in the energy system. The CET scenario closely follows this, at an accumulated amount of 44 GW.
3.5. Carbon Emissions
Figure 20 shows that the PDP 7 (rev), PDP 8 (draft), REDS, and RLP scenario all follow a similar trajectory in terms of carbon dioxide emissions. In these scenarios, carbon dioxide levels are expected to hit at least 850 Mton by 2050. Alternatively, the NZ and CET scenario are capable of reaching zero carbon dioxide emissions by 2050 and 2040, respectively. The CET scenario will also reach peak carbon dioxide emissions in 2023.
Figure 21 shows the accumulated carbon dioxide emissions from the six scenarios over the modelling period. Modelling suggests that NZ and CET will emit the least amount of carbon dioxide over the modelling period, at a total of 6,983 Mton and 5,529 Mton, respectively. The PDP 7 (draft) scenario will emit the most carbon dioxide, at 21,071 Mton, followed by PDP 8 (draft), REDS, and RLP.
3.6. Total System Costs
Figure 22 displays the annual costs of the six scenarios over the modelling period. Note that these costs include variable, capital, and fixed costs. The CET scenario is expected to hit a peak spend of $255 billion in 2030, before diminishing rapidly to $78 billion in the next year. Additionally, costs after this year are expected to stay low. Similarly, the NZ scenario reaches a peak of $201 billion in 2038, although this peak is more gradual than CET. Costs after this year are also expected to stay low. Costs for PDP 7 (rev), PDP 8 (draft), REDS, and RLP have the same trajectory, reaching at least $120 billion in 2050.
As seen in Fig. 23, the CET scenario is the cheapest scenario out of the six. Alternatively, the NZ scenario is the most expensive scenario, being $1,227 billion more expensive than CET. Looking into the NZ scenario further, most of this cost is due to capital costs from renewable technologies.