Planning and prospects for renewable power: Eastern and Southern Africa

INTRODUCTION

Southern and Eastern Africa are endowed with extensive untapped renewable resources. With rapidly declining costs and increasing policy support, solar PV and onshore wind generation technologies have, in recent years, established strong business cases and begun taking off at scale in selected African markets, such as in South Africa and Egypt. The International Finance Corporation (IFC) has been helping to scale up the use of solar technologies in smaller African countries (IFC, 2020). However, despite their massive potentials, renewables are yet to be fully reflected in national and regional plans and strategies. Under current regional master plans, fossil fuels will be relied upon heavily to meet the increasing electricity demand.

Countries included in the ACEC region.

CURRENT STATUS AND RECENT DEVELOPMENTS

This chapter provides an overview of the power systems of the ACEC countries, in terms of
current electricity production, generation capacity and capacity of transboundary transmission
infrastructure.

Final electricity demand, 1993–2017 (UNSD, 2020)

OUTLOOK FROM THE EAPP AND SAPP MASTER PLANS

The EAPP and SAPP master plans8 provide long-term regional electricity generation and transmission plans to guide future system expansions and then identify transboundary infrastructure projects with a view to establishing an integrated regional market. The revised EAPP Master Plan, produced by the Eastern African Power Pool in 2014, analysed the regional electricity system for 12 countries, under 21 scenarios. It was updated from the 2011 Master Plan to include the entire DRC, Libya and South Sudan. The SAPP 8 Unless otherwise stated, for the DRC and Tanzania, which are in both the EAPP and the SAPP, aggregated numbers for the region use the data from the SAPP master plan. Master Plan published in 2017 covered 12 countries and presented three main scenarios (referred to as ‘components’ in the master plan). Both master plans have a timeline to 2040. However, they do not reflect the reality of investment cost reductions and growth of renewables deployment in recent years, and both present a future dominated by fuel-based generation in their respective base cases for 2040. At the point of drafting this report, processes for updating the master plans have commenced (EU–TAF, 2020).

Projected electricity demand from 2020 to 2040 for the SAPP and EAPP countries, according
to master plans and additional research

Power generation capacity expansion As of 2015, about 100 GW of mainly coal and natural gas units exist in the EAPP and SAPP. Based on the plants’ lifetimes and build years, by 2040, half of that capacity will have retired. Based on those committed12 as of 2015, the retired plants will be replaced by approximately 100 GW of projects during the decade leading to 2025, including 40 GW of gas, 25 GW of hydro and 24 GW of coal.

Peak demand and capacity mix timeline including committed plants and retirement schedule
of existing plants in the ACEC countries, 2015–2040

In the EAPP master plan, in addition to the “main scenario”, which acts as a reference, there are
also scenarios formulated for high renewable future, different demand trajectories, transmission capacity expansion plans, hydro resource 13 In this figure, both the EAPP and the SAPP master plans include the DRC and Tanzania. availabilities and costs, the presence of carbon tax, export levels, nuclear generation, gas prices, interest rates and reserve margin requirements. Of which, typically only a single parameter is varied per scenario.

EAPP and SAPP’s capacity mix until 2040 based on the respective master plans’ reference
plans

RENEWABLE RESOURCE POTENTIAL IN SOUTHERN AND EAST AFRICAN COUNTRIES

This chapter presents recent renewable energy deployment trends and contrasts them with available renewable resources in Southern and East Africa, with a focus on solar PV and onshore wind. Specific solar PV and onshore wind project zones are presented here for their resource quality based on defined criteria, as a pre-screening step prior to further analysis. Solar CSP, hydropower and geothermal resources are also assessed.

Electricity generation by renewables (2012–2019) and installed capacity of renewables
(2012–2019) in ACEC countries

Most of the growth in wind capacity expansions are a result of capacity expansions in Egypt, Ethiopia, Kenya and South Africa.Solar PV and onshore wind potential The continent is known to have massive untapped solar and wind potential. From forthcoming, updated analysis, IRENA’s estimates suggest that technical potential for wind and solar PV are over 147 TW and 337 TW, respectively, in the region.17 In order for these theoretical technical potentials to be considered as tangible investment options in the planning process, they were translated into
a narrower concept of renewable zones. IRENA’s Multi-criteria analysis for planning renewable
energy (MapRE) study, jointly undertaken with Lawrence Berkeley National Laboratory, employs this translation for the region.

Schematic of how zones are derived and used for further analysis

Among all the zones originally identified in the MapRE analysis, further screening was conducted to identify investment options for comprehensive investigation in the subsequent SPLAT modelling analysis. This subset collectively corresponds to 161 GW for solar PV and 124 GW for wind.

Identified solar PV and wind zones

KEY METHODOLOGIES

In order to assess the possible future evolutions of the power systems in the region and the roles of renewables in future power systems, we deployed a capacity expansion modelling method, combined with the zoning analysis.

Hourly demand profiles for a day in January (left) and scaled 10-time slice representation of
demand profile for South Africa in season 2, in local time

For this report, hourly capacity factors were derived based on meteorological data and averaged to produce daily profiles representing each of the three seasons.36 Within the model, the capacity factor patterns determine the hourly generation of solar and wind. Solar PV, for example, is not able to produce at night, when the capacity 36 The three seasons are: January–April (season 1); May–August (season 2); and September–December (season 3). factor is zero, while wind cannot provide beyond its capacity factor. The capacity factor profiles are
specific to each zone. The method is outlined in detail in Appendix shows two such examples of capacity factor profiles for solar PV (example of a zone in Angola) and wind (example of a zone in Egypt). The meteorological data used were reanalysis data from Vortex (Vortex, n.d.).

Examples of average capacity factor profiles for solar PV and wind for the three seasons

The project zones’ capacity factor profiles were derived by averaging the daily profiles of each
of the three seasons modelled. This smooths out intra-seasonal and intraday variability, especially for wind. As a result, the model can underestimate the fluctuations of VRE production, thereby also understating the firm capacities required of synchronous generators. The modelled results may, therefore, favour renewable technologies.

INSIGHTS FROM SCENARIO RESULTS

This chapter presents and derives in-depth insights from the results of the modelled scenarios defined in Section 4.3. Key findings include the importance of VRE generation in replacing conventional fuels and increasing system diversity, as well as the interaction between transmission and VRE generation. The results in terms of capacity, generation mix, CO2
emissions, trade flows42 and system costs are compared 42 The volume of trade is a function of electricity price, generation mix, demand pattern and transmission capacity. For the purpose of providing a simplified overview, this report does not differentiate between forms of power trading (e.g. day-ahead vs. intra-day); rather, the focus is on the volume of overall trade taking place. In the model, there is no lead time between building the interconnector and when the interconnector becomes operational. 43 Does not include fuel or O&M costs. across the scenarios. The analysis focuses on the long-term (2040) evolution of the power system while also discussing changes in the medium-term (2030) as key milestones in the transition.

Summary of key results

Significant VRE penetration is integral for realising least-cost pathways the projected total power generation (in TWh) and capacity mix (in GW) for the region in the Reference Scenario, for the period 2020–2040. Solar PV and wind capacities grow to 232 GW combined (solar PV, 134 GW; wind, 98 GW) and generate up to 36% (579 TWh) of total regional power production by 2040.

Total electricity generation in the ACEC region (TWh), Reference scenario, 2020–2040

Renewables can replace coal and gas in providing both baseload and peak load power
The VRE scenarios (where VRE penetrations are constrained to 20% and 50% in 2040, respectively in the VRELim and VREHigh scenarios) show which technologies are replaced by VRE in the case of a higher ambition, and which technologies replace VRE in case of limited VRE penetration. In the higher ambition case (VREHigh), natural gas is reduced and compensated for by an increase in wind. At the same time, gas replaces solar PV and wind when VRE penetration is limited (VRELim). Coal generation remains largely the same across all three scenarios, as coal’s comparatively lower prices than gas prevent it from being edged out
of the supply stack when VRE penetration varies. Carbon emissions are reduced when VRE displaces coal and gas Under the coal-dominated futures of the EAPP and SAPP master plans, CO2 emissions rise to 1212 megatonnes per year in 2040 based on the master plans’ base case scenarios. With continued reliance and expansion of coal generation capacity in the master plans, CO2 emissions are more than triple the emissions in IRENA’s Reference scenario
(357 megatonnes).depicts the yearly emissions (in megatonnes) as projected by the 49 Excluding Libya. 50 The SAPP Master plan presents only shares of production rather than total generation number for the high renewable scenario. The EAPP Master plan also does not report the carbon dioxide productions for the renewable scenarios. master plans and from modelled results.

Total yearly CO2
emissions (in megatonnes) from the base cases50 of the master plans
(EAPP, 2014; SAPP, 2017) and IRENA’s Reference (REF), VREHigh and VRELim scenarios

Cost-effective VRE projects are geographically dispersed Due to the geographically widespread VRE resources, smaller countries such as Djibouti, Eswatini, Lesotho, Malawi and Namibia can also cost-effectively achieve 40% or higher VRE shares. the solar PV and wind capacity in the Reference scenario in 2040, alongside the percentage of VRE generation for each country.

VRE capacity and share of generation by country in the Reference scenario, 2040

Since the region has excellent resources that are geographically diverse, solar PV and wind
deployment are observed throughout the corridor, most prominently in Egypt and South Africa where large numbers of project zones are considered.

Generation capacities of solar PV and wind in Reference scenario, 2040

RE investment is a robust strategy against hydro-related risks Those power systems that have a moderate amount of hydropower can be robust if planned accordingly, reaping benefits from both the dispatchable and storage capabilities of hydro dams. However, there can be risks to the security of supply for systems that rely heavily on hydropower, if the availability of water is reduced during extended periods of drought, or when hydropower projects are delayed for financial and regulatory reasons (as with other types of large generation projects). Systems that
comprise a diverse mix of primary energy are better able to withstand shocks, constraints and
crises affecting supply. This report finds that power systems in the region can respond to hydro-related risks by complementing hydropower with other sources of renewables.

Share of hydropower production for all countries, 2040

Cross-border trade is integral to minimising system cost With increased transmission capacity over time and more routes to trade electricity, power generated from areas with high-quality and cost-effective renewable resources can be used more efficiently to meet demand needs in other areas. Total trade flows grow by 4.5 times – from 39 TWh in 2020 to 182 TWh in 2040 (Figure 5-17) – in the Reference Scenario. In addition to the committed transmission lines, another 15 GW of additional capacity from candidate transmission lines can accommodate 74 TWh of trade flows in 2040. The number of country pairs with interconnectors almost doubles, from 18 to 35. The savings from these efficiency gains exceed the estimated costs for transmission capacity expansion, and the average utilisation rate increases from 30% to
58% (total flows as a percentage of total possible flows in a year).

Interconnector capacity (GW) and total trade flows (TWh) in 2020 and 2040 for four

Among certain countries, net trading volumes increase tremendously in the last five years
of the horizon, between 2035 and 2040. a country-level breakdown of the net imports in 2035 and 2040 under the Reference scenario and the TxNoLim scenario for major trading countries. Under all scenarios, the largest net importer is South Africa (62 TWh in 2040 in the REF scenario). Significant exporters include the DRC (REF, 51 TWh; TxNoLim, 60 TWh) and Mozambique (REF and TxNoLim, 31 TWh) in 2040. When there is a higher level of VRE deployment (VREHigh), Ethiopia and Tanzania both become net exporters, while the DRC sees
much lower net exports as compared to the REF scenario. While trade between individual countries can be sensitive to the level of VRE penetration, the increase in trade volumes over the years attest to its role in minimising the system costs of the entire region.

Modelled interconnector capacities and total trade volumes between countries in 2040,
sorted in order of total flows (REF scenario)

Regional integration where synergies exist addresses the need for flexible generation
An increase in interconnector capacities not only enhances cost efficiency of production by facilitating the increased flow of lower-cost power supplies, it also enables the pooling (and mutual balancing) of supplies from resources with hourly fluctuating and complementary profiles. For example, hydropower supplies are flexible and can therefore help balance the inherent variability of VRE supplies. Complementary generation profiles between countries can be utilised to provide stable power through trade if there is adequate interconnector capacity. With adequate transmission infrastructure and generation capacity, a country with excellent hydro resources can import solar power during the day and export its hydropower at night. Furthermore, the time zone differences on the continent also mean that high demand periods occur at different times, possibly allowing one country to export to meet the peak demands of another, without putting excessive pressure on its own capacity margin.

Hourly generation and trade in the DRC and Rwanda for the Reference scenario in 2020,
2030 and 2040, in SAST (UTC+2:00).

Modest potential for interconnection expansions beyond current plans

With the increase in total power flows between now and 2040 across all scenarios existing and identified (committed and candidate) connections are adequate for increased power trade flows in the future. The TxNoLim scenario seeks to investigate how the system changes when additional interconnectors not yet considered (i.e. generic options) can come online from 2030. This scenario demonstrates that, beyond what has already been planned, there is even further potential along certain lines to accommodate higher trade flows.

Cross-border transmission flows (GWh) in the region in 2040 for the REF scenario with only
planned interconnectors (left) and flow changes with the TxNoLim scenario54 and additional
connections (right)

PIDA – a key continental infrastructure planning programme While the results of this report’s analysis provide important insights for power systems as a whole in the region, they can also deliver a wealth of information on the prospects and performance of particular projects. Such information can be useful to both public and private initiatives that are interested in infrastructure project development. Many such initiatives exist to spur the development of energy infrastructure in Africa, with one key effort led through the Programme for nfrastructure Development in Africa (PIDA) under the African Union Commission (AUC).

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