The effects of climate change mitigation strategies on the energy system of Africa and its associated water footprint

The energy-water model was developed using the OSeMOSYS [49] for medium to long-term energy planning. OSeMOSYS is a bottom-up modelling framework that uses linear optimization techniques to satisfy an exogenously defined energy demand. OSeMOSYS has been employed in the scientific literature to provide insights on possible transformation pathways of large energy systems and their impacts on the economy, society and the environment [53]. The open-source method of the study assists in overcoming the lack of transparency needed to address future long-term decarbonisation trajectories [54].

The electricity supply system, including a simple representation of other energy sources (heavy fuel oil, light fuel oil, gas, coal, biofuel & waste), of forty-eight (48) African countries was modelled individually and linked via electricity interconnectors and natural gas pipelines to shape the African model. Countries were then associated with the following regional power pools [55]: Central African power pool (CAPP), East African power pool (EAPP), Northern Africa power pool (NAPP), South African power pool (SAPP) and Western African power pool (WAPP) to identify trades. NAPP, as it is reported here, is officially called the Maghreb Electricity Committee, or COMELEC. The analysis provided results on a continental-regional-country level at an annual temporal resolution for the period 2015–2065. Country-specific hourly electricity generation profiles and seasonality of the electricity load were considered in the analysis.

To estimate the WW and consumption per type of technology and consequently the water demand by a country, we considered different cooling types: dry cooling, natural and mechanical draft tower, once-through cooling tower with freshwater (OTF) and once through cooling tower with salt water (OTS) per type of technology (power generation). Based on the identified cooling type, specific water factors were assigned (supplementary B table 24).

The detailed methodology is presented in the supplementary material A section.

To explore plausible future developments of the African energy sector, we developed three scenarios. The Reference scenario assumes that there is no change from the national renewable energy policies after 2017. In the two mitigation scenarios (2.0 °C, 1.5 °C), the fuel demands of each African country are derived from the JRC GECO 2018 report [51] and disaggregated based on socio-economic factors (gross domestic product (GDP) [51], population [2]). The mitigation scenarios (2.0 °C, 1.5 °C) assume future emission reduction targets aiming at a global mean temperature increase of 2.0 °C with a 67% probability [51, 52] and 1.5 °C increase with a 50% probability by 2100. The emission reduction targets under these scenarios are modelled as emission limits posed on a regional and not country level.

In the Reference scenario, the carbon dioxide emissions increase by approximately three times, compared with 2015 levels, reaching to 3466 Mt of CO₂ by 2065. The annual emission levels are constrained to the emission pathways compatible with the 2.0 °C, 1.5 °C scenarios [51, 52]. Carbon removal technologies were also introduced in these two scenarios.

Under the 2.0 °C and 1.5 °C scenarios, we assume the implementation of energy efficiency policies and a significant reduction in fossil fuel consumption (figure 4). Consequently, the total final energy demand increases by only 79% and 49%, respectively, by 2065 over 2015 levels instead of 148% in the Reference scenario.

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The influence of future water availability in each country is considered in the optimization process in two different ways. For hydropower plants, different capacity factors are considered according to a dry and a wet scenario developed by Sterl et al [56]. The capacity factors from Sterl et al [56] have been adapted to the timescale considered in this article (more information presented in the supplementary material A). For thermal plants with cooling systems, different options are considered. The WW for cooling is restricted, implemented as a share of the withdrawal from the scenarios (Reference, 2.0 °C and 1.5 °C) accordingly. In the first case, water availability refers to the availability of river flow and reservoirs modelled as changes in capacity factors for hydropower plants. In the second case, water availability is linked to WW for thermal power plant cooling, Four different cooling types considered in the analysis (dry cooling, natural and mechanical draft tower, OTF and OTS), so water availability refers to freshwater and saline water used. However, water availability is not categorised in freshwater and others in this study and the optimization process (appendix table 2).

In the Reference scenario, WWs in Africa grow by almost eight times from 2015, reaching 159 billion cubic meters (bcm) in 2065. This increase corresponds to approximately 3% (in 2065) of the TRWR (5290 bcm in 2015) in the continent [28], assuming no changes in future precipitation patterns. This growth is mainly due to the penetration of high water-intensive technologies (coal, oil) and increased hydropower share. However, WC remains relatively constant between 2015–2065, reaching 2 bcm in 2065, primarily due to the penetration of renewable energy technologies.

In the Reference scenario, in the NAPP and CAPP, there is a decrease in WC due to the transformation of the future energy mix to a higher share of renewables and the use of less water-intensive thermal generation technologies. On the other hand, in the EAPP, SAPP and WAPP, the increase in WC is explained by the adoption of water-intensive thermal generation technologies. NAPP, EAPP and WAPP experience increased WWs by 2065 while SAPP and CAPP experience a decrease, 13% and 61%, respectively.

In the mitigation scenarios, overall WW increases over time (2.0 °C, 52 bcm, TRWR 1%) (1.5 °C, 85 bcm, TRWR 2%). This increase is lower than that in the Reference scenario, 67% and 47% lower in the 2.0 °C and 1.5 °C scenarios, respectively, by 2065. Also, decarbonizing the energy sector further decrease WC from 1.2 bcm in the 2.0 °C to 1 bcm in the 1.5 °C scenario, compared to 2.2 bcm in the baseline scenario by 2065 (figure 2). These results support the message that pathways towards decarbonisation of the energy sector in Africa lead to higher WW and lower WC. This observation highlights the critical role of clean technologies with a low water footprint versus hydropower with integrated water resources management that secures water for other purposes (e.g. agriculture, municipal services).

Each power pool presents a different transformation pathway regarding WW and consumption. National and regional policies need to differ based upon the specific energy and water context of African nations. Specifically, EAPP shows higher WC in the 2.0 °C than the Reference scenario. This increase is primarily due to the higher penetration of natural gas technologies in Egypt. Egypt increases its primary energy production due to a decrease in the country's imports and an increase in its electricity exports. Similarly, WAPP increases WC more in the 2.0 °C than the Reference scenario, mainly due to nuclear investments in Mali. SAPP exhibits the most dramatic transformation in WWs in deeper decarbonisation of the energy system. Higher WWs are required in the mitigation scenarios than the Reference primarily due to nuclear and carbon capture investments with sequestration. Consequently, WC is considerably less in the mitigation scenarios than in the Reference. This transformation is mainly due to changes in the energy mix in Angola, South Africa and Zimbabwe which increase their exports in the mitigation scenarios. Lastly, investments primarily in CCS technologies (with biomass) in Egypt, Morocco, Chad, Guinea, Gabon, Uganda, Nigeria, Benin, Côte D Ivoire, Ghana, Senegal, Mali, increase WWs to higher levels in the 1.5 °C than the 2.0 °C scenarios (supplementary figures 2–10).

In the Reference scenario, the evaporative losses due to the increased use of hydropower plants increase almost four times (174 bcm) by 2065. To attain deep decarbonisation goals in the energy sector (1.5 °C), higher use of hydropower plants is required, leading evaporative losses to reach 180 bcm by 2065. The WAPP is responsible for the majority of these losses while the NAPP the minority. Notably, countries with considerable hydropower potential (e.g. Angola, Cameroon, DRC, Ethiopia, Nigeria, Zambia) experience increased evaporative losses in the future (supplementary B figures 11–13).

The evolution of fuelwood consumption in households is another important aspect influencing overall WC in the continent. Specifically, in the Reference scenario, the green (precipitation) and blue water (groundwater through capillary rise) [57] consumption was 7435 mcm and 354 mcm in 2015, and increases to 8270 mcm and 396 mcm in 2065, respectively. This increase is because fuelwood consumption in households corresponds to most of the biofuels and waste demand in the energy sector in Africa. WAPP represents most of the fuelwood WC amongst the African Power Pools, primarily due to Nigeria since it also has higher WC factors than NAPP and SAPP. EAPP (Ethiopia) has the 2nd highest WC in Africa, followed by SAPP (Democratic Republic of Congo), CAPP (Cameroon) and NAPP (Libya). All the power pools increase their water needs while NAPP presents the highest rise despite its lowest WC for fuelwood overall. To decarbonize the energy system, higher levels of green (2.0 °C-9447 mcm, 1.5 °C–9144 mcm) and blue WC (2.0 °C–477 mcm, 1.5 °C–454 mcm) are required (supplementary B figures 14–15).

Fossil-fuel reserves, renewable potential and water resources are unevenly distributed in Africa. The results show how trade among African countries could support more affordable attainment of lower emission levels, decrease electricity generation costs and influence water resources management. However, the drivers of trade to minimize the overall energy system costs (on a continental level) interact with the differences in national energy resources of neighbouring countries, differences in energy demand, and technological availability.

The largest electricity net exporters by 2065 are Kenya, South Africa and Sudan, while the main net importers are Uganda, Burkina Faso and Mali. The high potential for renewables in the EAPP makes the region the largest net exporter of electricity. Besides, some exporting countries assist importing countries in decreasing their fossil-fuel dependency in the decarbonisation scenarios. Zimbabwe is one of the countries which undergo a transformation from a net exporter in the Reference scenario to a net importer in the decarbonisation scenarios to reduce its fossil fuel-based generation capacity, importing on average 14 TWh of electricity annually. Also, the importing countries use imports to decrease their electricity supply costs (e.g. Kenya). The potential implementation of the Grand Inga project in the Democratic Republic of Congo, together with trade links, could increase the electricity exports to neighbouring countries and displace part of their fossil-fuel-based generation.

A notable finding of this study is identifying some countries as transit traders, including Egypt, Sudan, South Africa and Tanzania (figure 3). Indicatively, under the Reference scenario, Egypt imports 659 TWh (94%) of its cumulative electricity imports from Sudan. Egypt also exports approximately 1194 TWh (96%) of its cumulative electricity exports (2015–2065) to Asia. In parallel, 64 TWh or 15% of Sudan's total electricity exports are derived from imports of electricity generated in Ethiopia.

These results highlight the importance of an enhanced electricity trading scheme on the continent to reduce greenhouse gas emissions and system costs. Nevertheless, this could come at the expense of increasing WW and consumption in the main electricity exporter countries in the Reference scenario, particularly Ethiopia, Guinea, South Africa and Zimbabwe, having consequences for managing their national water. However, countries such as Congo, which increase their electricity net imports in all scenarios, experience a concurrent decrease in WC. Investment decisions in large hydro-electricity generation projects cannot be separated from water resource management and electricity trade and require regional coordination across countries, tailored to the local geopolitical and hydrological realities.

Also, specific gas pipeline projects (e.g. West African, Trans-Saharan) could change the role of certain countries (Algeria, Mozambique, Nigeria) to energy exporters, assisting neighbouring countries to transform their energy sector.

The evolution of the energy mix of a core group of fossil fuel resource-rich countries plays an essential role in African greenhouse gas emissions. For example, South Africa and Lesotho are responsible for most of the continent's coal consumption' Nigeria and Egypt are large consumers of oil products. The results show that Algeria, South Africa, Nigeria, Egypt and the Democratic Republic of Congo consume most of the continent's natural gas, in final energy terms. The analysis of how the final energy consumption evolves among the scenarios can be found in supplementary B.

In the Reference scenario, the total African primary energy supply more than doubles compared to 2015, reaching 1853Mtoe by 2065. While the share of fossil fuels increases over the years (64%), renewables experience a gradual decrease, eventually reaching 36% of the total primary supply by 2065 (figure 4). Without a carbon constraint, coal, as the cheapest source of electricity, constitutes most of the continent's primary energy supply, followed by oil and biomass. Nuclear power disappears from the electricity supply system by 2065. The WAPP stands out as the largest energy supplier (35%) in Africa, followed by EAPP (28%), SAPP (19%), NAPP (11%) and CAPP (7%) in 2065. WAPP is also the largest supplier (37%) of fossil fuels and renewables (32%) in the continent in 2065.

However, in the 2.0 °C and 1.5 °C scenarios, due to the relatively lower final energy demand, African countries increase their 2065 total primary energy supply by only 50% and 31%, respectively, compared to 2015. Moreover, the primary supply of fossil fuels in those two scenarios declines dramatically throughout the years, reaching 27% and 8% by 2065. On the contrary, renewables increase by 64% and 72%, respectively, by 2065 (figure 4).

As natural gas reserves are scattered among nations, the role of natural gas trade through pipelines and liquified natural gas (LNG) terminals is key to decarbonize the African energy system. Countries with natural gas reserves, such as Algeria, Nigeria, or Mozambique, increase their natural gas exports significantly to reduce the consumption of more polluting fossil fuels in the continent. In particular, Mozambique increases its gas exports to South Africa for replacing coal in the power sector with natural gas.

Under the mitigation scenarios, natural gas supply to Europe through the Northern African countries gradually declines, which is in line with Europe's aim to become a climate-neutral continent by 2050. The Western African power pool and specifically Nigeria, are the leading natural gas supplier in the African continent. Several coastal countries (Côte D Ivoire, Ghana, Morocco, Sudan, Senegal, Tunisia, Tanzania and South Africa) increase their LNG imports. This increase in imports leads to lower emission limits by replacing the above countries' fossil fuel capacity in the power sector and decreasing their water requirements.

In the Reference scenario, the overall generation capacity in Africa rises ten-fold from 181 GW (2015) to 1863 GW (2065). The share of renewables increases from 19% (2015) to 78% (2065), while the percentage of thermoelectric capacity decreases from 82% (2015) to 22% (2065). Hydropower was the dominant renewable source in 2015. However, as the costs of renewable (solar, wind) technologies are declining throughout the years, solar PV technologies represent most of the continent's installed capacity by 2065. In the decarbonisation scenarios, the percentage of renewables reach even higher figure 86% (2.0 °C) and 87% (1.5 °C) in 2065 and resulting in generation capacities of 1843 GW (2.0 °C) and 1833 GW (1.5 °C).

In the Reference scenario, CAPP is electrified almost exclusively by renewables (94% of installed capacity) in 2065. At the same time, EAPP hosts most of the continent's renewable installed capacity (427 GW) and NAPP experiences the highest increase (46 fold) in all scenarios. As expected, CAPP becomes the leading hydropower producer as the Democratic Republic of Congo and EAPP (Sudan, Uganda) continue to invest in hydropower. Concentrated Solar Power technologies are limited to NAPP (Morocco) and EAPP (Egypt) and geothermal to EAPP (Kenya, Ethiopia). In mitigation scenarios, to achieve the emission targets, CCS technologies and nuclear power plants are required along with the replacement of coal-based power plants by natural gas.

Nevertheless, to encourage decarbonisation of the energy sector, the technological maturity of CCS technologies needs to be considered, along with the feasibility of nuclear energy in the African context. Socio-economic concerns of nuclear power exceed the scope of this analysis [58]. In decarbonisation scenarios, WAPP (Nigeria, Ghana), Egypt and Morocco present most of the continent's nuclear capacity in the future, mainly replacing thermal capacity. In the same scenarios, SAPP (Angola, South Africa, Zambia, Zimbabwe) invests in biomass with CCS technologies while Egypt invests in natural gas with CCS.

Our results show that to decarbonize the energy sector, the gas-fired power generation technologies and the penetration of renewables, CCS and nuclear technologies replace coal-based power generation. In the Reference scenario, electricity generation in Africa increases from 64Mtoe (2015) to 510Mtoe (2065). Renewables gradually penetrate the electricity mix reaching 57% (2065) from 18% in 2015 and 75% in both the 2.0 °C and 1.5 °C scenarios. Solar PV technologies followed by hydropower are the dominant power generation renewables in the future. In the Reference scenario, coal-based power generation is the primary thermal power source in the long-term instead of natural gas in the decarbonisation scenarios where thermoelectric generation is lower than in the Reference scenario (45% in 2065), specifically 34% (2.0 °C) and 31% (1.5 °C) by 2065.

Also, technologies combining CCS constitute 9% (2.0 °C) and 8% (1.5 °C) of the total electricity generation by 2065. An insight among the scenarios is that the coal-based power generation regions, SAPP and WAPP, replace their generation significantly by wind and solar in the first case while in the second case with natural gas and nuclear.

In the Reference scenario, the total system costs associated with the energy sector in Africa, including only the costs for the supply and conversion of energy and exclude costs on the demand side, are estimated at USD₂₀₁₅ 24 520 trillion. Under the mitigation scenarios, the total costs, excluding costs of energy efficiency measures and welfare losses due to demand reduction, are lower by 29% (2.0 °C) and 54% (1.5 °C) than the Reference scenario for 2015–2065. In the mitigation scenarios, the penetration of renewable technologies leads to fuel supply savings of 32% (2.0 °C) and 53% (1.5 °C) compared to the Reference scenario (figure 5). As expected, mitigation scenarios are capital-intensive and the capital investments in the power sector are higher by approximately 9% (2.0 °C) and 19% (1.5 °C) compared to the Reference scenario (figure 5). Despite that, the lower operating expenses show that decarbonisation options, including energy efficiency measures, are beyond any doubt the cost-efficient pathways. This indicates that increasing the ambition of climate targets results in lower cumulative costs. All scenarios assume universal access to clean energy by 2065, hence the high investment projections in 2030–2065.

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Therefore, developing strategies for the African continent should prioritize sustainable technologies, demand-side management, and set ambitious targets. This also applies to oil-producing countries of the continent (e.g. Algeria, Tunisia) since they are expected to profit from electricity trading leading to savings on their total fuel costs by 48% (2.0 °C)/46% (1.5 °C) and power system costs by 28% (2.0 °C)/7% (2.0 °C) compared to the Reference scenario, improving in parallel their water productivity by approximately 50%.

Water availability would affect the evolution of the energy system in Africa in different ways. Under limited hydropower-based generation, higher WWs and consumptions are required due to the higher penetration of fossil fuel technologies. Contrary, under decreased WWs for cooling purposes, WC also reduces in the Reference and mitigation scenarios. In the first case, more renewables are required, while in the mitigation scenarios, more nuclear investments (supplementary C).

In the Reference scenario, changes in water availability for hydropower plants result in higher WW (7%) and consumption (25%) under a Dry scenario, while under a Wet scenario result in lower withdrawals (1%) and higher consumptions (2%) by 2065. Compared to the Reference, the continental installed capacity under the Dry scenario is higher (1%) and under the Wet scenario is lower (3%) in 2065. Under the Dry scenario, the lower hydropower capacity factors mean that coal is more economically competitive, despite increasing WC and withdrawal. In the Dry scenario, the lower capacity of hydropower plants (62%) results in a higher capacity of coal power plants (18%) and other renewables (5%) by 2065. On the contrary, in the Wet scenario, higher capacity factors in hydropower plants lead to higher electricity generation than the Reference base scenario. However, the installed capacity of hydropower plants is lower (17%) in 2065 and of gas power plants is higher (6%) to meet the peak demand.

Also, the levels of electricity trades are estimated to be lower in the Dry scenario and higher in the Wet scenario than the Reference due to lower costs of generating electricity in the continent. CAPP is transformed from an exporter in the Reference base scenario to an importer in the Dry scenario, while SAPP from an importer in the Reference base scenario to an exporter in the Dry and Wet scenarios due to its coal-based power generation. Due to its hydro and coal-based generation, SAPP increases its exports under the Wet scenario.

Lastly, the changes in water availability affect the costs of generating electricity, with the Reference (Dry) scenario presenting the highest ones and vice-versa. The total system costs related to the power sector are higher in the Dry scenario (1.4%) than the Reference accordingly, while in the Wet scenario, lower (<1%) during 2015–2065 (supplementary B figures 59–139).

The 2.0 °C (Dry) and 1.5 °C (Dry) scenarios correspond to higher WWs and consumptions in the mitigation scenarios. In comparison, wetter ones lead to lower withdrawals and consumptions than the respective 2.0 °C and 1.5 °C base scenarios. To further decarbonize the energy system (1.5 °C), higher WWs are required under 1.5 °C (Dry) and 1.5 °C (Wet) scenarios than the 2.0 °C scenario combination, respectively, due to the higher penetration of nuclear and biomass technologies. However, in the 1.5 °C scenario, fewer WC is needed in Dry and Wet scenarios than in the 2.0 °C.