Lilas Demmou
OECD Economic Surveys: South Africa 2025
Abstract
South Africa's electricity sector has been in crisis for over 15 years, failing to meet electricity demand and leading to worsening shortages and planned electricity outages since 2019. Outages have caused significant economic damage, although they notably declined in 2024. The sector is also a major emitter, with coal accounting for 80% of power generation. While progress in renewable energy has been made, it remains insufficient. Comprehensive institutional reforms and investment are needed to ensure reliable supply and accelerate the transition to a cleaner, more diverse energy mix. Key reforms include increasing private sector involvement and competition to boost Eskom’s efficiency and financial stability. Encouraging private investment through an independent transmission operator will bridge network investment gaps. A strategy is needed to revamp distribution, reducing municipalities’ reliance on electricity revenues and improving service. Reforming pricing to balance affordability with incentives for efficiency and the transition from coal is essential.
For over 15 years, South Africa’s electricity sector has been under immense stress. Over the past five years the problems have significantly worsened. The sector has failed to secure sufficient electricity supply to meet demand, stifling economic opportunities in the country. Facing supply shortages, the government imposed rolling power cuts, known as load shedding, leading to significant economic losses. Power cuts, which have sometimes lasted up to 12 hours a day, make running a business difficult, as reliable alternative electricity sources are not yet available at a sufficient scale. Furthermore, coal accounts for around 80% of electricity generation, contributing to 41% of greenhouse-gas emissions in 2022 (IEA, 2024[1]). This underscores the importance of transitioning the electricity sector, a key priority for the green transition, as discussed in Chapter 3.
Recent reforms are already transforming the electricity sector (Box 4.1), delivering progress, especially through the expansion of renewable electricity sources, which has helped ease some of the supply constraints. To fully unlock South Africa's economic potential and foster stronger, greener and more inclusive growth, it is crucial to maintain strong momentum in completing ongoing reforms that will accelerate the shift towards renewable electricity. Key remaining challenges include establishing a wholesale electricity market, scaling up electricity supply, accelerating the transition away from coal, expanding the transmission grid and redefining municipalities' roles in electricity distribution to better serve end users. While renewables are not a silver bullet, they represent a powerful opportunity to ease the electricity-supply constraints on economic growth, better serve end users through a more decentralised and secure electricity supply and decarbonise the economy.
This chapter examines challenges and reforms in the electricity sector, proposing strategies to enhance efficiency, security, affordability and sustainability. It begins by outlining key issues, including electricity security, financial stability and decarbonisation, along with recent reforms. The second section highlights progress in renewable energy under the Energy Action Plan and steps towards decarbonisation goals. The third section focuses on structural transformation of the generation and distribution activities through better regulation and governance. The fourth section explores ways to boost financing and private sector participation in transmission, while the final section reviews pricing strategies to balance costs and ensure affordability.
4.1.1. Deteriorating generation capacity is compromising electricity security
South Africa’s state-owned electricity supply has deteriorated significantly in recent years, partly due to shortfalls in investment in new generation capacity and insufficient maintenance of an aging fleet of power stations. Capital expenditure by the state-owned electricity utility company Eskom has declined substantially since the late 2010s. Eskom’s electricity generation in recent years has been a fraction of that in the early 2000s (
Figure 4.2, Panel A). The Energy Availability Factor (EAF), a measure of operational capacity computed as the ratio of actual electrical energy output to maximum electrical energy capacity, has long been trending down, reaching 55% in 2022 from more than 90% in 2000 (Panel B). With the average age of coal power stations at 41 years and maximum lifespans of around 60 years, energy losses due to deteriorating plant and equipment have steadily increased over the years, while units in some power stations have increasingly been shut down for safety reasons. Furthermore, Eskom’s efforts to build new generation capacity have run into significant delays and cost overruns, further weighing on the capital stock and profitability.
Rolling power cuts (load shedding) have occurred in most years since they began in 2007. Furthermore, the number of pre-arranged load-shedding days has increased in recent years and skyrocketed in 2023 to nearly 300 days (
Figure 4.2, Panel C). The impact of loadshedding on households and businesses has been severe, driving those who can afford it to increasingly rely on diesel generators, while leaving others without electricity. According to the last available World Bank Enterprise Survey, 92% of firms report having experienced electricity outages in 2020, much more than in the average in upper middle-income countries (44%) and in Sub-Saharan African countries (77%).
The electricity sector has been structured vertically around the state-owned enterprise Eskom, which produces 90% of electricity, primarily from coal-based sources. The sector has significantly transformed over the past 15 years. Since 2011, independent power producers have supplied electricity to Eskom through the Renewable Energy Independent Power Producer Programme (REIPPP). The Electricity Regulation Amendment Bill adopted in August 2024 marks a significant milestone and lays the groundwork for establishing a competitive market in the medium term.
Source: OECD.
Eskom fully owns and operates the transmission grid. However, since mid-2024, transmission activities have been legally separated from Eskom’s other activities following the creation of the National Transmission Company South Africa. This wholly owned subsidiary of Eskom will act as the interim Transmission System Operator until an independent entity firm is established.
The distribution of electricity is divided between Eskom and municipalities. Municipalities primarily purchase electricity from Eskom and a small share purchase from independent producers. Some municipalities also operate generation facilities. The special role of municipalities in South Africa relates to obligations to provide electricity written in South Africa’s constitution, which explicitly lists low voltage distribution as a competence of municipalities (referred to as “electricity reticulation”).
The electricity used by end users can be sourced from different providers: Eskom, municipalities but also Independent Power Producers and through self-generation. The licensing threshold for embedded generation was eased in 2021 and removed in 2022, allowing large end users to establish direct bilateral contracts with producers or self-generate electricity. Alongside these generators, the share of small-scale embedded generation and rooftop solar panels in the overall electricity supply is rising, though it remains modest.
Note: In Panel A and B, data refers to fiscal years, i.e. the 2013 financial year refers to the year ending March 2013. Panel A: Total capital expenditure of the Eskom group excludes capitalised borrowing costs. Panel B: EAF is a measure of power station availability, taking account of energy losses not under the control of plant management and internal non-engineering constraints. Panel C: Loadshedding refers to the scheduled and controlled power cuts that rotate available capacity between all customers when demand is greater than supply in order to avoid blackouts. Distribution or municipal control rooms open breakers and interrupt load according to predefined schedules.
Source: Eskom; The Outlier and EskomSePush, Loadshedding Tracker; and South African Reserve Bank (2024[2]).
Load shedding eased considerably in 2024, to only 69 days. The Energy Availability Factor rose to 67% in July 2024, the highest since 2021, due to improvements in Eskom’s supply, as important stations like Kusile were reactivated (in October 2023), but also due to lower demand for electricity amid sluggish growth and increased self-generation. The installation of privately-owned solar photovoltaic (PV) systems, also known as embedded generation, has surged in recent years, rising from 1.2 GW in 2021 to 6.1 GW by 2024. In 2023 alone, self-generation capacities increased by 73%. Business and commercial sectors account for 71% of self-generation installations, agriculture for 17% and households for the remainder (CRSES, 2024[3]).
While the suspension of load shedding since March 2024 represents notable progress, significant challenges persist, and the system remains fragile, as evidenced by the return of load shedding in early 2025. First, despite the growth in self-generation, it is still far from being able to substitute for coal generation, accounting for only 11% of total capacities. Furthermore, since 2010, both electricity production and demand have trended down, with Eskom's output at its level observed in the early 2000s. Currently, seven out of eighteen power stations are operating below 60% capacity, with one as low as 32%. The aging fleet will require Eskom to gradually decommission several power stations over the next five years, further reducing its generation capacity. This underscores that while recent improvements have alleviated some supply constraints, concerns about the capacity of the electricity system to meet higher demand, should economic growth accelerate, remain.
4.1.2. Electricity shortages are a barrier to economic growth
A stable electricity supply is essential for operating businesses, promoting industrialisation and fostering innovation and is a key determinant of household welfare (Box 4.2). Frequent power outages disrupt manufacturing processes, increasing production costs and decreasing productivity (Allcott, Collard-Wexler and O’Connell, 2016[4]; Mensah, 2016[5]). Energy-intensive industries reliant on continuous power, such as manufacturing and transport, are particularly affected (Alam, 2014[6]).
Macroeconomic and sectoral impact
Studies show a significant negative relationship between electricity shortages and economic growth, as power outages lead to a decline in industrial and commercial activities (Fisher-Vanden, Mansur and Wang, 2015[7]).
Adaptation through adjusting the production process and input substitution
Uncertain power availability can prompt firms to substitute from electricity-driven machines towards other machines or labour (Abeberese, Ackah and Asuming, 2021[8]), or to resort to backup power solutions (e.g. diesel generators or outsourcing energy-intensive production process). This is found to mitigate productivity losses but without offsetting them (Fisher-Vanden, Mansur and Wang, 2015[7]).
Impact on investment, innovation and technology adoption
Power outages can deter overall investment because firms become reluctant to expand and adopt new technologies, reducing productivity and economic growth (Lebepe and Mathaba, 2024[9]). While firms, especially the largest, are more inclined to invest in response to an electricity supply shock, productivity may decline as many technologies rely on electrical machinery (Wang, 2020[10]).
Impact on firms’ dynamism
Small firms have comparatively limited capacity to invest in generators or adopt other energy-efficient technologies in the face of power outages. This may lead to a disproportionate share of these firms closing, reducing firm dynamism and thereby productivity (Khalid, 2011[11]). Symmetrically, improving access to electricity is associated with firm creation (Lipscomb, Mobarak and Barham, 2013[12]).
Economic costs for the South African economy have been substantial. A study commissioned by Eskom estimates the total cost of load shedding at ZAR 43.5 billion from 2007 to 2019, an amount broadly equivalent to the impact of the 2008/09 financial crisis on GDP growth. Over this period a 1% decline in electricity sales was associated with a 0.4 percentage point reduction in GDP growth on a quarter-to-quarter basis. Despite occurring over a much smaller time period, the cost to growth surged fivefold between 2020 and Q1 2023, reaching ZAR 224 billion (Kay, Nel and Kiln, 2023[13]). This represents a loss of 1.2% of the cumulative GDP in level terms over this period.
Exceptionally high load shedding in 2023 is estimated to have reduced GDP growth by 1.5 percentage points, leading to sluggish growth of 0.7% (
Figure 4.2, Panel D). The impact has been estimated at 0.7 and 0.5 percentage points for 2022 and 2024 (SARB, 2024[2]). Overall, load shedding has been the primary factor driving the decline in potential output, with average growth falling from 3.9% between 2000 and 2009 to just 1.4% in the years following the Great Financial Crisis (see Chapter 1). Potential growth has been estimated to be around 0.7% in 2022 and 0.0% in 2023 (Janse van Rensburg and Morema, 2023[14]). With the ease of load shedding, the South African Reserve Bank estimates that the impact on economic growth will be reduced to only 0.2 percentage points in 2025.
4.1.3. Eskom’s financial difficulties are weighing on public finances
South Africa’s power crisis is deeply intertwined with Eskom’s financial crisis, with the state-owned enterprise in severe financial stress. Declining sales have strained the utility company’s financial health. Between 2013 and 2023 Eskom’s total sales fell by nearly 15%, with a particularly large fall in sales to the rail sector (Figure 4.3, Panel A). Part of the decline can be attributed to sluggish economic growth and structural changes in economic activity, leading to lower electricity consumption by large end users that previously formed Eskom's core baseload. Increasing self-generation by businesses and households in response to poor reliability in grid electricity has also played a role.
Eskom has found itself in a vicious cycle. The company has significantly increased its prices to deal with increasing losses while not yet able to ensure security of supply, making alternative power options even more attractive and aggravating its financial difficulties. Electricity tariffs have increased almost tenfold since 2000, rising particularly steeply since 2009, dramatically more than consumer price inflation (CPI) (Figure 4.3, Panel B). One reason behind Eskom’s insufficient financial profitability is that prior to the recent steep increases, tariffs had been lower than the cost-recovery level for several decades (see section below on tariff setting). Additionally, corruption and mismanagement have further undermined the utility company 's financial sustainability (see below).
Source: Eskom and OECD Analytical database.
Eskom’s deteriorating financial health has undermined its capacity to undertake the necessary investment to become economically viable. Its credit rating has sunk to “speculative” grade, limiting its borrowing capacity even further, and forcing the government to implement successive bailouts (Figure 4.4). Significant fiscal transfers from the central government have been required to ensure the financial survival of the utility company, weighing on public finances. Eskom’s debt burden represents 15% of government debt and around 8% of GDP (Panel B).
To restore Eskom’s financial stability, the Eskom Debt Relief Act passed in June 2023 covers ZAR 254 billion (5.5% of GDP) of Eskom debt (including ZAR 168 billion in capital and ZAR 86 billion in interest) over the next three years. The strict bailout conditions include a moratorium on further borrowing. New debt or government guarantees are subject to the National Treasury’s approval (National Treasury, 2023[15]). The strict conditionality imposed through the moratorium on new debt is intended to secure public funding. However, the arrangement risks hindering the deployment of investment in security of supply along with the green transition of the electricity supply sector. The government should closely monitor such risks.
Note: Panel B: Eskom's debt covers debt securities and borrowings, derivatives held for risk management and finance lease liabilities. 2024 figures are estimated using March 2024 financial statement data.
Source: South African National Treasury; Eskom; OECD Analytical database; and OECD calculations.
4.1.4. Many municipalities struggle to efficiently distribute electricity
Municipal governments play a key role in the electricity sector (see Box 4.1). This stems from provision obligations in South Africa’s constitution. Municipalities distribute around 40% of electricity, mainly serving households and small businesses. The remaining 60% is distributed by Eskom, mainly serving large users and municipalities with no distribution network.
When municipalities are responsible for electricity distribution, they are generally the sole distributors in their respective locality. Approximately two-thirds of municipalities are licensed by the energy regulator (NERSA) to serve as electricity distributors. This role includes responsibility of maintaining infrastructure, providing new connections and setting minimum service level standards and subsidy levels for low-income consumers. Reflecting the concentration of the population and economic activity in relatively few municipalities, approximately 20 municipalities account for almost 90% of the municipal electricity market (Vanheukelom, 2023[16]).
Many municipalities struggle to deliver reliable electricity services. Much of the distribution infrastructure is poorly maintained and suffers from high technical losses, leading to frequent power outages, on top of those from scheduled load shedding (Vanheukelom, 2023[16]). Furthermore, theft and vandalism during load shedding has regularly led to further local outages. Most municipalities struggled to perform maintenance and safeguard infrastructure assets because they spend only 1% of their infrastructure value on repairs and maintenance, compared to a national norm of 8% (Auditor General South Africa, 2022[17]). The development of renewable electricity introduces additional challenges for financially constrained municipalities. The intermittency of renewables requires substantial investments to balance supply and demand, necessitating advanced grid management technologies, electricity storage solutions and smart grids (Johnstone and Haščič, 2012[18]; Ledger, 2024[19]).
Similar to Eskom, high financial debt limits the capacity of many municipalities to invest in a reliable distribution network as well as in new technologies to accommodate the rise of renewables (Figure 4.5, Panel A). Nearly half of municipalities, including some of the largest ones, have serious financial problems, raising concerns about their ability to effectively perform their functions (Auditor General South Africa, 2022[17]; National Treasury, 2022[20]). Almost 80% of municipal debt resides with 20 municipalities that are particularly struggling to provide electricity (National Treasury, 2024[21]). Most municipal debt is in the form of arrears owned to Eskom (Panel B). This debt has steadily increased over the years, reaching a record of ZAR 75 billion in February 2024, twice the level in 2021. Arrears feed into Eskom’s financial health, accounting for 15% of Eskom's total debt.
To address the systemic challenge of municipal debt to Eskom, a debt relief programme was introduced in 2023. It allows municipalities to write-off part of their debt, provided they commit to financial sustainability and operational best practices. The programme’s strict conditions ensure accountability, with non-compliant municipalities required to request NERSA to revoke their electricity license. However, not all heavily indebted municipalities are yet participating, potentially reducing its impact. Some aspects of the debt relief programme raise concerns. For the debt that is not written off, the programme requires municipalities to set up dedicated and ring-fenced sub-accounts for payments to Eskom. It is reasonable to ask municipalities to earmark revenues from their electricity distribution activities. However, there are concerns that to fulfil reimbursement obligations, municipalities will have to also use direct transfers from the central government, potentially reducing the resources available to alleviate poverty and inequality (e.g., funds for free access to electricity grants) (Ledger, 2023[22]). Ensuring that reimbursement plans are carefully tailored to avoid such unwarranted effects is key.
Source: National Treasury, Municipal Borrowing Bulletin, Issue 30, September 2023; Eskom (2024), Financial results presentation; OECD Analytical database; and OECD calculations.
4.1.5. Continuing the fight against mismanagement and corruption
The “Zondo Commission” exposed extensive governance failures at Eskom involving organised criminal networks and government involvement (Zondo Comission, 2022[23]). By late 2023, 15 cases against previous Eskom directors had been prepared, revealing internal and external collusion in procurement abuses. These findings have led to changes in Eskom’s management.
The economic costs of corruption at Eskom are significant, though hard to quantify precisely. Mismanagement and procurement fraud led to inflated operating costs, delayed projects and insufficient effective investment, all factors that have contributed to load shedding and thereby sluggish growth and poor quality of life. For example, the Special Investigating Unit (SIU) is now investigating allegations around nine contracts involving coal and diesel, focusing on irregularities like advance payments, poor coal quality controls and unusually favourable contract terms, all irregularities that inflated Eskom’s operational costs. The new and large Medupi and Kusile power stations illustrate mismanagement issues, with both projects facing massive delays, design flaws and cost overruns, partly due to corrupt contract practices and weak oversight. Cost overruns to complete the Kusile and Medupi power stations are estimated to have increased costs by about 185% and 66% (Tshidavhu and Khatleli, 2020[24]).
While law enforcement efforts do take time, most investigations have not yet progressed to prosecution and convictions, further contributing to public distrust (see Chapter 1). More work is needed to conclude investigations and, where appropriate, begin criminal prosecutions and enforce the resulting sanctions for corruption offences. At the company level, efforts such as promoting channels for reporting corruption and fraudulent activities should be further encouraged.
4.1.6. Decarbonising the electricity sector has a long way to go
South Africa’s Low Emission Development Strategy aims to achieve net zero emissions by 2050. Decarbonising electricity generation is key as the sector accounts for 41% of total emissions and 58% of energy-related emissions in 2022( (IEA, 2024[1]),Chapter 3), largely because coal accounts for around 83% of power generation (Figure 4.6, Panel A).
Source: IEA Data Services.
Progress in decarbonising the electricity sector has been insufficient so far. Emissions from grid electricity generation and heating have recently declined, but this is more due to the decline in grid electricity consumption and supply disruptions than from intentional policy efforts. Consumption of grid electricity per capita declined by 17% from 2000 to 2021 (Ledger, 2024[19]). In fact, the emissions intensity of the sector has remained stable despite the increase in renewables generation (the share of renewables reached 9% in 2021). The opposite has been observed in China and India (Figure 4.6, Panel B).
In the short-to-medium term, there are some trade offs between accelerating the green transition and securing a sufficient supply of electricity. To support the latter, the Energy Action Plan (see Box 4.1 and Box 4.7) pushed for maximising the use of the existing coal capacity. Eskom's renewed focus on maintenance has enabled the return to service of several power stations. To further alleviate the strain, the government has proposed to postpone the decommissioning of the coal power plants in Mpumalanga Province, as well as Eskom's Camden, Grootvlei and Hendrina power plants from 2023-2027 to 2027-2030 (Department of Mineral Resource and Energy, 2024[25]).
The most recent draft of the Integrated Resource Plan (IRP 2023), released in 2024 and currently under discussion, serves as a strategic framework for energy planning in South Africa. Unlike the IRP 2019, which had forecast the shutdown of old coal plants (Figure 4.7, Panel B), the 2023 plan does not include such closures and instead focuses on completing ongoing coal capacity projects. As a result, coal capacity is projected to increase to 39.4 GW by 2030, up from 33.4 GW in the 2019 plan. This reflects a continued emphasis on maintaining baseload power due to energy security concerns.
In contrast, the allocation for renewable energy sources (wind and solar) has been reduced. Total renewable capacity is now projected to reach 25.7 GW by 2030, down from 31.1 GW in the previous plan. However, the 2023 IRP highlights a significant increase in distributed generation capacity, rising from 4.5 GW in the 2019 plan to 11.3 GW in the latest draft. Despite this growth in distributed generation, it appears insufficient to fully offset lower projections for overall renewable energy capacity. Though admittedly prioritising energy security may be necessary in the short term, this approach may delay decarbonisation and the 2030 emission target might be missed.
There has been a significant boost in renewable generation over the last decade, driven by the renewables auction programme and the ongoing 2022 Energy Action Plan (see Figure 4.6, Panel A). Despite progress, further efforts are still needed to achieve renewable energy targets and electricity security. First, from an international comparison perspective, South Africa’s share of renewables in energy supply is still lagging behind (Figure 4.7, Panel A). Second, according to the last Transmission Development Plan, achieving a resilient and secure power system by 2035 requires 61.3 GW of renewable generation capacity to be in place. As of 2022, there was only 11.1 GW renewables capacity (Panel B). This progress appears insufficient to meet the 2035 target, even considering the increase in small-scale embedded generation, which reached 6.1 GW by the end of 2024 (see below). While ongoing advancements in this area are expected to add several new energy projects to the pipeline, the pace of progress still needs to accelerate.
Note: In Panel A, renewable energies exclude solid biofuels. In Panel B, renewables cover wind energy, solar PV energy, hydroelectric (included imported), pumped storage schemes and concentrated solar power.
Source: OECD Environment database; and Eskom (2022), The Eskom Transmission Development Plan 2023-2032.
To accelerate the expansion of renewable capacity, South Africa relies on several plans and strategies (see Box 4.7). Primary objectives include maximising generation from independent power producers and significantly increasing renewable electricity supply through small-scale generation.
4.2.1. Maximising renewable generation from independent producers
The Renewable Energy Independent Power Producers Programme (REIPPP) launched in 2011 has been the most important programme established so far to facilitate private sector investment into grid-connected renewables generation. This scheme allocates long-term power purchase agreements from Eskom to independent renewable power producers (via competitive auctions). There have been seven rounds of auctions since the programme began. As of 2023, 123 projects have been awarded and 6 200 MW of capacity installed (or 5% of South Africa's energy supply was added to the market). The programme promoted competition among independent generators, with only minimal changes to the market structure.
The programme has helped drive down the price of renewable electricity. Between 2015 and 2021 the average bidding price declined by 45% for solar power and 36% for wind power. Since 2019, the average cost of renewable electricity production has been below that for coal-based production in South Africa. This has been reinforced by the increasing costs of extracting high-quality coal, which is deeper than low-quality coal (OECD, 2022[26]). Compared to European countries, evidence suggests that South African auctions have experienced the sharpest reductions in auction prices and a clear price convergence towards global technology cost estimates (LCOE), highlighting the intense competition within the South African auction programme (Kitzing et al., 2022[27]). As of 2022, the average retail tariff for electricity was USD 0.18 per kWh while the price of renewables tendered during the Fifth Renewables Procurement Round was about 10 times lower (Figure 4.8). While tariffs include other costs related to the upgrade and maintenance of the grid, this comparison suggests relatively high cost-competitiveness of renewables.
Note: Bid window 1 (2011): 30 projects; Bid window 2 (2012):19 projects; Bid window 3 and 3.5 (2013-2014):21 projects; Bid window 4 (2018): 26 projects; Bid Window 5 (2021): 25 projects; Bid Window 6 (2022): 6 projects. Bid Windows 7 is ongoing.
Source: Department of Mineral Resources and Energy (DMRE).
While the REIPPP has been largely successful, some challenges remain, and additional barriers continue to slow the transition to renewables. Significant delays in the schedule of renewable auction rounds (hereafter, “bid window”) have brought uncertainty for investors and developers, slowing the expansion of renewable projects. As a result, achieving a continuous stream of revenues for renewable generation enterprises has been challenging, with many going out of business between rounds (Obisie-Orlu, 2023[28]). However, there have been welcome efforts to improve the auction process. The 7th Bid Window, launched in December 2023, was amended to introduce a reserve bid to ensure continuity if the preferred bidder fails to deliver and to implement a “first ready, first served” rule for grid connection allocations. Reducing the gap between bid windows would help ensure further continuity of new renewable generation projects. Another area for maximising the effect of the programme is revising its conditionality. Bidders are judged not only on cost but also on a range of other criteria, including job creation, local content, management control, skills development, and socio-economic development (Presidency of the Republic of South Africa, 2023[29]). Limiting the number of criteria could accelerate the development of renewables capacity. Finally, looking ahead, a potential consideration is the long-term sustainability of the sector. While the REIPPP has been highly successful and low auction prices are not currently a concern, the absence of reference prices (or floor prices) could become relevant in the future. Such mechanisms can help ensure the long-term stability of the supply chain by providing a predictable investment environment, encouraging consistent participation and preventing excessively aggressive bidding that could compromise project viability and quality. Given that South Africa's programme is already characterised by low auction prices, setting a reference price above these levels to enhance financial sustainability and attract investment in the value chain must be approached cautiously, to avoid undermining competitive bidding.
The 2022 Energy Action Plan encourages additional generation projects beyond the REIPPP auction programme. The measures include removing the obligation to hold a generation license for independent renewable producers selling electricity directly to end users in December 2022 and easing the entrance of private suppliers to invest in renewable generation projects. Consequently, major industrial consumers can either produce their own electricity or source it directly from private suppliers. A measure allowing municipalities to buy and generate their own electricity by establishing bilateral contracts with independent renewable power producers since 2023 is also encouraging renewables generation. While major metropolitan areas have already begun to do so, smaller and heavily indebted municipalities lack the financial and technical capacity to take advantage of this opportunity (see next section).
4.2.2. Increasing small-scale renewables generation
Encouraging more rooftop solar
The installed capacity of rooftop solar has been growing rapidly, from 1.2 GW in 2020 to 6.1 GW by 2024 (CRSES, 2024[3]), helped by measures in the Energy Action Plan. Tax incentives include a 25% rebate on the cost of solar panels up to a maximum of ZAR 15 000 against installers’ tax liability, as well as a 125% capital depreciation allowance in the first year of installation. Additionally, the National Treasury has launched the Energy Bounce Back (EBB) Loan Guarantee Scheme to help small and medium enterprises finance rooftop installations. The scheme aims to support the installation of up to 1 GW of additional generation capacity by reducing the risk taken by banks providing finance. Under the scheme the government assumes initial losses (up to 20% of the value of the loan) in case of non-reimbursement, while finance providers assume the risk if non-reimbursement continues.
While effective at easing access to finance, fiscal incentives primarily cater to wealthier households and larger companies due to the high initial investment costs. Furthermore, only tax-paying households and businesses can take advantage of these incentives. Incentives for low-income households and smaller businesses should be considered in addition, not least as this can help improve electricity supply in low-income areas. A scheme in India (PM Surya Ghar: Muft Bijli Yojana programme) targets low-income households, providing subsidies and secure loans for households to install solar panels, with revenues from sales of excess electricity generated used to repay the loan.
Recent import tariff hikes on some items of equipment used in photovoltaic generation risk hindering growth in renewable generation. To protect domestic manufacturers and boost job creation, the International Trade Administration Commission (ITAC) of South Africa introduced a 10% tariff on solar photovoltaic panels, cells and modules in July 2024, following the recommendations of the Renewable Energy Masterplan. However, the capacity for local manufacturing to ramp up production is uncertain, not least because of electricity shortages and skill gaps. Consequently, tariffs might mainly translate into higher costs and supply shortages. To mitigate these risks, a temporary rebate for importers has been issued conditional on a specific permit allowed by the ITAC. However, combining increases in tariffs and rebates for importers may be unnecessarily complex, potentially increasing barriers to renewables expansion.
Furthermore, the 10% import tariff increase on photovoltaic equipment represents a partial policy reversal, as it follows a reduction of import tariffs on transformers from 100% to 30% in 2023, heightening uncertainty for investors. Reducing import tariffs on more equipment could further accelerate renewable power generation and alleviate supply chain issues. Overall, the joint impact of higher trade tariffs established in 2024, specific rebates for importers and the 2023 tariff reduction on some imported equipment should be closely monitored and trade barriers eventually phased out. More incentive-oriented measures, such as funding for R&D, lower interest rates and export credits, could better foster green competitiveness and innovation (Haussman et al., 2023[30]), as discussed in the previous Economic Survey (OECD, 2022[26]).
Developing solar home systems in remote areas
Despite significant strides in expanding the distribution network, 14% of households still do not have electricity access. Since 1999, the Integrated National Electrification Programme (INEP) has provided capital subsidies to municipalities and Eskom to address the electrification backlog for low-income households. However, achieving universal grid access remains challenging, particularly in remote areas. The current annual electrification rate of 5 to 10% is insufficient to meet the 2030 target in South Africa’s National Development Plan (Meyer and Overen, 2021[31]). Renewables offer a promising solution for electricity access in remote and underserved areas through off-grid generation or small smart grids. Several emerging economies, such as India and China, have achieved universal access to electricity. In particular, solar home systems can play a crucial role (Zubi et al., 2019[32]). These opportunities are especially promising in northern regions of South Africa, which have some of the highest levels of sun exposure in the world. The Department of Electricity and Energy (DEE) has advanced this effort through its Integrated National Electrification Programme (INEP) Grant, recently funding off-grid solutions like solar home systems and other renewables generation for low-income households in remote areas. Ensuring adequate funding and effective implementation is crucial. Stronger coordination between the DEE, municipalities and stakeholders can accelerate electrification. Future revenues from an increase in the effective carbon tax rate (see Chapter 3) could be used to expand off-grid renewable access.
4.2.3. Promoting battery storage solutions
In the medium to long term, the shift to renewables depends on robust storage solutions that ensure grid stability and facilitate the integration of solar and wind energy. Battery storage addresses intermittency by storing surplus power during peak production and releasing it when demand is high. In South Africa, it is particularly crucial for providing industrial consumers with continuous electricity during load shedding and outages, as well as for establishing effective mini grids in remote areas.
South Africa is expanding battery storage through two key programmes: the Battery Storage IPP Procurement Programme (BESIPPPP) and the Risk Mitigation IPP Procurement Programme (RMIPPPP), which supports hybrid solutions. These initiatives build on the success of REIPPP, fostering private sector participation through competitive bidding, driving down costs, and developing a battery storage market. In November 2023, South Africa selected preferred bidders for the first BESIPPPP tender, with four programmes reaching commercial close at the end of 2024. A third bid window was launched on 28 March 2024 (National Treasury, 2025[33]). International support, particularly through concessional finance, is also boosting South Africa’s battery storage sector. The World Bank and African Development Bank are funding a hybrid renewable project within the Eskom Just Energy Transition Partnership (JETP) to replace a decommissioned coal plant with solar, wind, and 150 MW of battery storage.
While these initiatives are promising, challenges persist. Lengthy negotiations, bureaucratic delays and Eskom’s financial instability create risks for investors. Additionally, grid capacity constraints continue to cause project delays and cancellations, highlighting the need for further infrastructure investment as discussed in the section below (IEA, 2024[34]).
A fundamental restructuring of the entire electricity supply chain is needed to sustain momentum on decarbonisation and to ensure long-term electricity security. This includes establishing a competitive market, opening the distribution segment to include private operators and strengthening municipal financial and managerial capacities.
4.3.1. Establishing a competitive electricity market
The electricity regulation component of the OECD’s Product Market Reform (PMR) indicator shows that South Africa’s electricity sector is more heavily regulated than that of many OECD and emerging economies (Figure 4.9). Eskom operates in the transmission and distribution segments of the sector in addition to generating around 91% of the country’s electricity (see Box 4.1).
The current market structure limits the entry of new players in all segments. It provides preferential access to Eskom’s ageing fleet of coal-based generation plants to the grid, limiting competition and compromising progress towards decarbonisation and greater electricity security. In both the transmission and distribution segments, third-party access conditions are not yet fully established. Access to the high-voltage transmission grid has been so far mainly limited to the specific contracts procured by Eskom and the Department of Mineral Resources and Energy, with access granted based on grid availability and a priority to Eskom generators. This may create a conflict of interest as Eskom has the power to set barriers to renewable electricity investments and give priority to Eskom generation. Integrating electricity generated by independent power producers or self-generation into the distribution network is also conditional on municipal approval, with only a few municipalities having approved installations of embedded generation in their network facility (World Economic Forum, 2024[35]).
Composition of the electricity indicator in 2023-24
Note: The Electricity indicator is the weighted average of the four components. The indicator for South Africa reflects the laws and regulations in force on 1 January 2023. For some countries, the indicator reflects those in force on 1 January 2024.
Source: OECD Product Market Regulation database and OECD-WBG Product Market Regulation database for 2023/2024.
In 2024 significant progress was made in laying the foundations for a more modern governance and market structure for the electricity industry. Most notably, Eskom is being unbundled into three separate entities, each with independent management and financial autonomy. Most notably, the newly National Transmission Company of South Africa (NTCSA), operational since July 2024, has been established as a wholly owned subsidiary of Eskom with an independent board, which is an important step towards full unbundling. This separate entity is expected to better ensure fair access to the grid for all electricity generators. A new fully independent transmission system operator (TSO), expected to replace the NTCSA, will manage the competitive market.
The Electricity Regulation Amendment Act passed in August 2024 establishes a framework for a competitive regulatory environment. Importantly the framework lays the groundwork for creating a wholesale electricity market. i.e. a trading platform where electricity can be bought and sold, which will facilitate a more flexible and efficient expansion of generation capacity. Notable transformations include:
A Central Purchasing Agency will operate within the NTCSA and fulfil the role of the “Single Buyer”. This is an important step towards a more decentralised market, compared to the current auction programme, which restricts participation to predefined bid windows determined by the Department of Mineral Resources and Energy (DMRE).
In the new system, independent power producers will be able to trade on the wholesale market, responding to price signals based on real-time supply and demand dynamics (NTCSA, 2022[36]). The platform will include a “day-ahead market” to match supply and demand on an hourly basis.
A market code is being developed to outline the rules of the market governing the trading and settlement and procedures of the new transmission company. The draft is under consultation.
Timely and effective implementation of these most recent reforms, including establishing the full independence of the transmission company, will be key. A five-year transitional period is planned to make the NTCSA fully independent from Eskom and to establish the Transmission System Operator. The market is projected to start in 2026 with a limited number of participants. This phased approach will allow adequate time to develop and implement the essential institutional framework, including the market code, vesting contracts and tariff regulations. There is also a need to reform the Municipal Finance Management Act to allow municipalities to procure from traders or directly on the wholesale market via the Market Operator. While a careful approach is essential to safeguard the market’s integrity, a phased implementation can facilitate this process. However, it is crucial to proceed without unnecessary delays to maintain momentum and confidence in the market's development.
In addition, under current plans, the legal separation of the distribution and generation segments into subsidiaries of Eskom will last until 2027, which should be accelerated. Separating the distribution grid operator functions – responsible for operating and maintaining the grid network – from the electricity trading activities, which could be open to competition, has the potential to significantly enhance service delivery to end users. One important implication is that the municipal trading function would eventually be open to competition; households and businesses would then be able to choose their electricity provider. Yet openness to competition requires establishing national regulation governing “use-of-network” access. This is commonly referred to as “wheeling” by trading entities (see the section on tariffs below). Progress is underway, with the National Wheeling Framework published for public consultation in August 2024.
The structure and governance of the proposed Transmission System Operator and the rules and regulations around the wholesale market are still not fully defined. This is especially the case for the trading platform and the day-ahead market. Providing more details on the structure of the future electricity market and the timeline of the changes would further increase policy certainty and support private investment. Another concern expressed by some municipalities relates to the risk that the new competitive environment reduces the revenues they stem from electricity. Opposition risks delaying the reform's implementation (Crompton, 2024[37]). To reduce opposition from municipalities, complementary reforms are necessary to ensure the sustainability of the municipal fiscal model within the new electricity market.
4.3.2. Revamping the sources of municipal funding and building capacity
Revising municipality’s funding model to reduce their dependency on electricity revenue
Many South African municipalities rely heavily on revenues from electricity sales. Currently these revenues represent around 25-30% of total municipal government income. However, the share varies widely across regions, from 3% in areas where Eskom distributes electricity to nearly 50% elsewhere (Statistics South Africa, 2022[38]). Amidst tight fiscal constraints and high indebtedness, municipalities often use electricity revenues to cross-subsidise debt and fund other initiatives, paring back spending on the electricity network under their responsibility.
Municipalities generate revenue by applying a markup to the electricity they purchase from Eskom, contributing ZAR 23 billion (around 0.4% of GDP) to net municipal revenue in 2020/21. This markup is intended to fund infrastructure and provide profit margins but raises concerns about inefficiency and poor governance in some municipalities. On the other hand, several municipalities make a net loss, buying more electricity from Eskom than they sell to end users. This is likely due to outdated and poorly maintained distribution infrastructure causing power losses and challenges in collecting payments from households and businesses (Mathoppo and Minnaar, 2023[39]). Rising bulk tariffs are reducing municipal margins, leading them to explore surcharges to sustain revenue. The National Treasury is developing regulation for these charges and exploring alternative revenue sources, with a draft set for public comment soon.
In the medium to long term, transferring operations of struggling municipalities to a third party could improve service delivery. A concession agreement with an independent company could ensure the necessary investments that municipalities are currently unable to finance, while generating stable revenue through concession fees. Clear provisions for service quality delivery, access and affordability would also be essential. Portugal successfully adopted this model, transferring operations to private operators while municipalities retained ownership of the distribution grid. In 2020, there were 13 distribution system operators in Portugal (IEA, 2022[40]). However, opening the distribution to private players may add to financial difficulties for many municipalities. Revising municipalities’ reliance on electricity revenue would ease resistance to this shift. A comprehensive review of the Local Government Fiscal Framework -including revenue models, electricity pricing and grants- is underway by the National Treasury.
In the short to medium term, efforts should focus on improving tax collection and the operational capacities of struggling municipalities. Greater reliance on property taxes under the current fiscal framework could reduce dependence on electricity revenues (Box 4.3). However, uneven local government capacity, particularly in rural areas, limits tax collection. Supporting administrative capacity building and ensuring regular valuation roll updates are crucial. Many municipalities struggle with the “market value” property tax approach (which applies tax rates to property market values), suggesting a need for revision (Franzsen, 2022[41]). Technologies (such as IA tools) can support timely and accurate assessments.
Finally, more transparency and regulation are needed around cross subsidisation to ensure that it does not compromise electricity services. For example, making all information on cost structures, outage performance and investment plans publicly available and easy to access would foster transparency and accountability and prevent strong increases in distribution costs.
Direct transfers
Transfers from central government to municipalities include a core unconditional grant and several conditional grants. Unconditional grants account for 50% of total revenue across municipalities and conditional grants account for 40%. The importance of conditional grants has increased over time as some municipalities have failed to deliver services.
The Equitable Share Grant is the main form of unconditional funding for the purpose of providing equal access to essential public services, including water, waste and electricity. Conditional grants include the Infrastructure Grant, the Urban Settlements Development Grant, the Water Infrastructure Grant, the National Electrification Programme Grant and the Capacity-Building Grant.
Self-generated revenues
Taxation powers in South Africa are highly centralised and the municipal tax base is typically narrow. Municipalities mainly derive revenue from service delivery and property taxation, though revenue collection is often weak (OECD, 2022[26]). Rural municipalities with mainly low-income inhabitants receive most of their revenue from grants through a larger part of the Equitable Share Grant, while urban municipalities raise a major part of their revenue from their own sources.
Enhancing the capacity of municipalities to manage electricity distribution
Many small municipalities face significant challenges in effectively managing distribution grids, hindering both infrastructure maintenance and expansion. Since 1995, national authorities have offered capacity building support through the Municipal Finance Management Act, offering guidance, training, workshops, and the prescribed publication of performance indicators on municipal service delivery. The Municipal Finance Improvement Programme further supports distressed municipalities by enhancing revenue management, strengthening policy implementation and building technical capacity for sustainable fiscal management. Despite spending ZAR 40 billion in municipal capacity building between 2016 and 2021, significant deficiencies remain. A diagnostic review conducted by the National Treasury in 2022 identifies measures to ease capacity bottlenecks, including improving expenditure reporting, collecting more targeted data from municipalities, streamlining existing conditional grants’ components and increasing learning opportunities (National Treasury, 2022[42]). Progressing with the plan would be highly beneficial.
The South African government is acutely aware of the challenges posed by municipalities’ capacity, often associated with the deteriorating state of infrastructure and trading services. Several initiatives are underway to enhance capacity and incentives to deliver essential services. One such initiative is the upcoming National Treasury's trading services reforms for metropolitan municipalities, which will introduce performance-based financial incentives to reward effective decision making and strong performance. Operation Vulindlela Phase II reforms will be expanded to reforms that will strengthen local government and improve the delivery of basic services. This will include: improving the performance of metropolitan water and electricity utilities; strengthening oversight, intervention and support in failing municipalities; and reviewing the institutional structure of the local government system through an updated White Paper on Local Government. Furthermore, the National Energy Crisis Committee (Workstream 5) is specifically focused on reforms within the electricity distribution sector, contributing to policy discussions and the development of strategies for wheeling, market formation, trading, and strengthening distribution grid capacity. Advancing in all these areas as planned is critical.
Promoting municipal partnerships or shifting responsibilities to provinces can also help address managerial capacity issues. Smaller municipalities can collaborate with larger ones with stronger management capabilities, reducing network fragmentation that hampers governance and exacerbates territorial inequalities. Fragmentation also complicates planning for transmission lines, increasing challenges between Eskom, municipalities and independent power producers (World Economic Forum, 2024[35]). An initiative from the 1990s to consolidate municipal distribution networks into regions through regional energy distributors (REDs) could be revived to enhance financing, optimise investment and improve governance. However, this would require a constitutional amendment and hence is a medium- to long-term goal. In the interim, the government could incentivise informal case-by-case pooling, such as financial rewards for large, well-functioning municipalities mentoring smaller ones or tie the debt moratorium framework for distressed municipalities to capacity-building efforts with well-functioning municipalities.
Strengthening the role of municipalities as contractors of electricity projects
Since 2022 municipalities have been able to procure electricity from independent producers and have been developing their own generation capacity. This potentially contributes to advancing energy security and decarbonisation, but so far take-up of these opportunities has been limited.
The complexity of procurement contracts combined with a lack of project management capabilities dissuade many municipalities from engaging with independent producers. Incentives for municipalities to pool distribution management (as discussed above) could help in this regard. Another approach is to lower the complexity of contracting, for example by standardising project documents, such as purchasing power agreements, construction agreements and operation and maintenance agreements (World Economic Forum, 2024[35]).
The new Procurement Bill, signed into law in July 2024, is an important first step to consolidate and streamline the country’s procurement system (see Chapters 1 and 2). The bill lays the foundation for a single public procurement system across the entire state, e.g. departments, municipalities and State-Owned Enterprises. Moving forward with its implementation is essential and should be accompanied by close technical support and guidelines to assist municipalities in implementing their own renewable electricity procurement programmes.
A unified procurement system can also reduce the risk of corruption (see Chapter 1) through standardised practices that facilitate the oversight of contracts. Further progress in this regard could also be achieved by promoting transparency. Ensuring public access to procurement information is key to accountability, yet enforcement remains weak due to poor IT skills and limited management capacity, especially in small municipalities (Dullah Omar Institute, 2023[43]). Encouraging the systematic use of the National Treasury e-Portal to display procurement information could foster a culture of transparency. Progress has been made with the Treasury publishing municipal financial data and launching the Municipal Money portal to boost public awareness and engagement.
Expanding and upgrading the transmission network should be a key pillar of South Africa’s electricity policy. Insufficient and ageing grid capacity is a major barrier to the expansion of renewables generation and contributes to problems in electricity security. For example, during the Sixth Renewables Procurement Round, wind projects could not progress because Eskom was unable to provide the connections to the grid.
The pace of installing new transmission lines has to ramp up to support the expanded generation capacity needed in the coming years. The best locations for large-scale renewables generation are generally far from South Africa’s main urban areas. According to Eskom’s Transmission Development Plan (TDP), 14 000 km of new transmission lines are needed between 2023 and 2032, equivalent to around half of the current 33 000 km of transmission lines. The increase in the installation pace needed to achieve this goal is substantial. Over the past decade or so, typically no more than 500 km of transmission lines have been installed annually (Figure 4.10). The Development Plan anticipates ramping up annual installation to over 2 000 km by the late 2020s.
Reducing the time required to plan and build new transmission infrastructure is needed. New grid infrastructure often takes eight to ten years from planning to commission, compared with one to five years for new renewables generation projects. The Transmission Development Plan, updated every year, provides important strategic orientation by detailing how the network will develop over the next ten years. However, implementation remains uncertain, in particular due to tight financing constraints.
Installation of new transmission lines and projected needs
Source: Eskom, Transmission Development Plan 2022.
4.4.1. Bridging the financing gap through independent power transmission projects
Eskom has so far mainly financed its investments through a mix of loans, grants, public transfers, international finance and sovereign guarantees from the government and multilateral development banks. However, as discussed above, Eskom’s and the government's ability to finance investments is constrained by Eskom’s debt moratorium, coupled with diminished fiscal space, successive economic shocks and low growth. Development finance institutions have provided significant loans to South Africa to support the green transition and overcome electricity transmission challenges. A notable source of funding will be USD 8.5 billion in the form of (mainly) concessional finance from the International Partners Group, with a significant share devoted to improving the transmission and distribution network (see Chapter 3). Nevertheless, the announced support falls short of the estimated USD 47 billion required for the transition of the electricity sector (Figure 4.11, Panel A) and the estimated USD 21 billion investment needed for transmission lines. Eskom has so far secured USD 4 billion (Panel B).
Source: South African Presidency; IEA.
To bridge the transmission financing gap, cross-country experience suggests various solutions (Box 4.4). There is limited appetite for privatising Eskom, yet promoting independent power transmission (IPT) projects may be the most viable option, alongside reforms to the corporate governance of Eskom and procurement. The IPT approach, increasingly adopted in emerging economies, requires fewer reforms than privatisation or full grid concessions. Under this model, Eskom would contract an IPT project to provide and manage transmission lines for an agreed availability fee. A pilot IPT procurement process is scheduled for the second half of 2025, overseen by the Independent Power Producer Office, with market tenders expected to be launched by late 2025. Meanwhile, the National Treasury and NTCSA are finalising the regulatory framework to support this initiative.
International experience highlights four main models for financing and operating transmission grids:
Public ownership is the most common model, where a state-owned enterprise (SOE) holds exclusive responsibility for building and operating the transmission grid.
Country examples: Belgium, France, the Netherlands, the Slovak Republic.
Whole of grid concessions grant the responsibility of transmission grid ownership to a private company for a time-limited concession, typically 20 to 30 years.
Country examples: Mali, Philippines, Senegal.
Private ownership transfers the responsibility of transmission grid ownership to a private company, which must secure financing from various sources as well as regulated tariffs.
Country examples: Germany, the United Kingdom, the United States.
The independent power transmission model assigns a portion of the investment to a private company, which is responsible for constructing, operating and maintaining specific grid lines.
Country examples: Australia, Brazil, Colombia, India, the United States.
Country-specific examples of successful Independent Power Transmission models include:
In India one of the major private transmission companies, Adani Transmission Limited, has a portfolio of more than 185 000 km of transmission lines across 13 states. In 2020, the company raised USD 1 billion by issuing bonds, with strong global participation in bond issuance.
In Egypt between 2014 and 2020 the Egyptian Electricity Transmission Company commissioned over 3 600 km of 500 Kilovolt (KV) transmission lines, more than doubling the length of transmission lines, which were mainly used to connect new renewable electricity projects.
In Brazil between 1999 and 2017, the electricity regulator (ANEEL) conducted 38 tenders for IPT projects, awarding 211 projects with a combined length of over 69 000 km.
Source: Kristiansen (2022[44]) and Flavin and Ketchum (2023[45]).
4.4.2. Securing private finance for transmission projects
Scope for increasing further sovereign guarantees is limited amid fiscal risks
South Africa could build on its success with the Independent Power Producers (IPP) programme by launching an Independent Power Transmission (IPT) initiative. However, transmission projects have long timelines, require substantial upfront investment and face heavy regulatory burdens, leading to complex risk issues (Box 4.5). Consequently, financing for transmission often comes at a premium (Sweerts, Longa and van der Zwaan, 2019[46]; Ameli et al., 2021[47]).
In South Africa, securing private backing for such ventures is further complicated by concerns over Eskom’s financial stability. Lenders may be wary of entering into contracts with Eskom, particularly if the new transmission utility (NTCSA) inherits a significant portion of Eskom’s debt. Additionally, an ageing, undermaintained transmission network heightens the risks for IPT projects. All this makes financing more difficult and necessitates sovereign guarantees to alleviate these concerns. Yet, amid mounting fiscal pressure and large contingent liabilities (Figure 4.12), the South African government may struggle to provide the large-scale guarantees needed for IPT projects.
Given the potential high fiscal costs if contingent liabilities materialise, the National Treasury has established an effective framework to assess and manage these risks, serving as a model for implementing such frameworks (Bachmair, Aslan and Maseko, 2019[48]). Recent rounds of IPP projects already indicate a slowdown in guarantees, with developers citing difficulties in obtaining their preferred guarantees as a significant barrier (GreenCo, 2022[49]). If demand for risk mitigation tools is not met, IPT projects would potentially stall, slowing down the pace of investments. A partial alternative to the expected decline in sovereign guarantees is to establish an institutional environment reducing risks.
Transmission projects have specific risks that make their financing difficult. These include:
A long-term horizon: Long timelines expose investors to higher financial risks as returns fluctuate with interest rates, inflation and economic cycles.
Uncertain demand: Transmission projects’ profitability can suffer from economic or grid inefficiencies, causing unpredictable demand and reduced revenue streams.
Policy and regulatory risks: The risk of policy priorities shifting or complex regulations diminish incentives for investors to commit to long-term projects.
Large fixed investments: The substantial upfront capital required increases both credit and operational risks.
Moreover, transmission infrastructure cannot be used as collateral as the lines are not owned by the private company and there is no established market to value these assets.
A key challenge in creating a new IPT market is developing a framework that efficiently distributes risks among stakeholders to facilitate investor access to finance (Table 4.1).
Note: The table indicates the distribution of risks across stakeholders. Costs to consumers are usually reallocated through changes in tariffs.
Source: OECD based on Consolidated Articles-SEAsia_ENG.pdf (doc.gov).
Government guarantees to Eskom and Independent power producers (IPP) as a share of GDP
Note: Fiscal years, i.e. 2012 refers to April 2011 to March 2012. GDP data and OECD projections are used as the denominator.
Source: National Treasury (2025), 2025 Budget Review.
Easing financing barriers by lowering-financial, regulatory and change-of-policy risks
The National Treasury in collaboration with the World Bank is developing a Credit Guarantee Vehicle that pools resources from multiple sources, including Multilateral Development Banks, private investors and the government. This approach distributes risk among multiple stakeholders, reducing reliance on sovereign guarantees. Initially, the focus will be on independent transmission projects to address the energy transmission gap, with a potential expansion to other sectors in the medium term. The Credit Guarantee Vehicle is expected to be operational by the end of 2025. The development of such blended finance is promising but is not a silver bullet. Reducing the perceived risks for investors remains key to crowd in private investors.
The government could further ease financial risks for investors by promoting the use of specific de-risking tools that ensure a clear revenue stream for the investor. This could include placing a share of Eskom’s revenues in a secured account (an “escrow account”) to pay investors providing transmission services (Steyn et al., 2024[50]). South Africa has already used this approach to finance investment in water infrastructure, where an additional end-user charge is ringfenced to repay an infrastructure investment loan. Such model could be applied to an IPT model with an “IPT charge” to customers. To reduce financial risks for the government, payment could be made conditional on the availability of transmission capacity.
The government could also ease regulatory risks by fast tracking procurement and simplifying administrative procedures for installing renewables infrastructure and transmission lines. Several actions have already been taken:
Environmental permits are waived in low-environmental impact areas while strategic infrastructure projects receive permits within 57 days. Registration to the electricity regulator (NERSA) averages 19 days while land-use authorisations now take 30 days, down from 90 days.
Priority zones have been designed for transmission lines and Renewable Energy Development Zones, easing permits for wind and solar PV development.
The Energy One Stop Shop (EOSS), launched in July 2023, coordinates approvals across government for planning and construction authorisations.
The Department of Trade, Industry and Competition (DTIC) provides dedicated resources to facilitate applications.
Efforts are underway to coordinate demand at the local level and to introduce a single electronic entry point for electricity-related permits and licences. Progressing in these areas will be another welcome improvement. Establishing a “silence is consent” rule would further enhance business dynamism in the sector (see Chapter 2).
More policy work is needed to facilitate the acquisition of land-use rights for renewable electricity generation. IPPs and Eskom often have to negotiate with multiple landowners and the right of expropriation is rarely applied for transmission projects (World Economic Forum, 2024[35]). The new Electricity Regulation Amendment Act aims to strengthen expropriation provisions by authorising the Minister to expropriate land or land rights on behalf of licensees. A swift implementation of this project combined with measures facilitating IPP’s access to government-owned land would further help.
The government could ease the “change-in-policy” risk inherent in long-term infrastructure projects. Investors will only commit to long-term financing if they trust the legal and political processes and are confident that successive governments will not unilaterally alter contracts. Political risk insurance is currently provided, often by the World Bank’s Multilateral Investment Guarantee Agency (MIGA), in case of losses related to political causes, easing financing barriers for long-term projects.
Finally, an important direction to mitigate perceived risks is for the government to demonstrate consistency in environmental policies and a solid track record of action, which directly influence investors' calculations of rates of return. Similarly, the Transmission Development Plan is critical in outlining development targets for transmission lines and reporting the progress of their implementation. Adhering to these commitments will be essential for building and maintaining the market’s trust.
South Africa's electricity pricing reform needs to address three challenges while ensuring that electricity remains affordable: establishing price signals for the green transition, moving towards cost-reflective prices and supporting the expansion of electricity supply by independent generators.
4.5.1. Strengthening price signals to encourage a shift away from coal-based generation
In South Africa, coal-based electricity is heavily subsidised, keeping prices low and slowing the green transition (Qu et al., 2023[51]). Eskom receives direct subsidies that reduce its coal generation costs. Since 2009, it has paid an electricity levy on fossil fuels and nuclear power but has been exempt from the carbon tax. In 2026, the electricity levy will be replaced with the carbon tax. The carbon tax policy planned for 2026 includes tax-free allowances on up to 85% of Eskom’s emissions. However, until 2030, Eskom’s total levies and taxes will remain unchanged, with any difference in the electricity levy and the carbon tax being offset accordingly. Stronger price signals are needed to incentivise Eskom to shift away from coal. Progressively channelling central government transfers to Eskom towards renewable generation would help strengthen price signals.
Note: Panel A: Fiscal transfers to Eskom are divided by Eskom's CO2-equivalent emissions. Eskom is currently exempt from the carbon tax. Electricity levy is the environmental levy on electricity generated in South Africa from non-renewable sources and revenues from non-Eskom producers are assumed to be negligible. Eskom's CO2-equivalent emissions for 2024 are estimated based on quarterly data.
Source: National Treasury; Eskom; and OECD calculations.
4.5.2. Progressing towards cost-recovery electricity tariffs
The debate over electricity pricing has intensified over the past decade, driven by sharp price hikes that have raised overall prices almost tenfold since 2000 (see Figure 4.3). The current pricing methodology has fueled disputes between Eskom and the regulator (NERSA), highlighting several challenges (Box 4.6). A major issue is whether to raise tariffs to reflect true electricity costs, after years of below-cost pricing that weakened Eskom’s finances and led to repeated government bailouts (Eskom, 2021[52]). Moving to a pricing methodology allowing cost recovery, however, must be balanced with affordability (see section below). Moreover, for a cost recovery approach to be acceptable, it is essential that services are delivered efficiently, minimising unnecessary costs. The unreliability of electricity services combined with corruption and mismanagement that have contributed to driving up operational costs, further complicates public acceptance of higher rates. Yet, successful electricity sector reforms in regions like Latin America, Europe and Central Asia show that middle- and high-income users are generally willing to pay cost-reflective rates if service quality is reliable (Trimble et al., 2016[53]).
Implementing cost-recovery tariffs is essential for Eskom’s financial health but requires progressing further towards efficient operations to avoid burdening consumers with unnecessary costs. Achieving this heavily depends on fundamental structural reforms. The planned reforms aim to create a decentralised wholesale market in five years and to contribute to promoting efficiency (see the section above on transforming the electricity market structure). At the same time, pricing methodology also has a role to play. To enhance efficiency, NERSA developed a new framework, the Electricity Price Determination Rules (EPDR), in December 2023. Although it was initially set to take effect in 2025/2026, its implementation is now on hold, which should be reconsidered given the ongoing challenges. While not a complete solution, the EPDR introduces improvements, including benchmarking costs across the sector, increasing transparency by unbundling generation, transmission, and distribution costs and removing the clawback clause that had allowed Eskom to raise tariffs to recover past losses (Box 4.6). Advancing all of these reforms is essential to reach fair, cost-based electricity tariffs while ensuring support for low-income households. Future reforms could also explore a model used in Germany, where utility revenues are separated from operational costs. This “revenue cap” limits how much a utility can charge based on its revenue needs rather than on all its expenses, helping keep prices stable and affordable (see Box 4.6) (Energy parternship, 2017[54]).
Main drawbacks of the current electricity tariff methodology in South Africa
Tariffs are set according to the Multi-Year Price Determination (MYPD) methodology, which determines the allowable revenue that Eskom can earn to cover costs given expected electricity sales. Using this methodology, Eskom applies for the approval of a particular tariff from the regulator (NERSA), which either occurs or NERSA suggests another. Increasing conflicts between the regulator and Eskom reflect the inherent limits of this methodology, most notably the:
Clawback option. Under the “the Regulatory Clearing Account” option, Eskom can request tariff adjustments to offset revenue declines, whether due to increased costs of primary energy or declining domestic sales. This approach allows Eskom to pass on revenue shortfalls to consumers, including those stemming from mismanagement. This diminishes incentives for cost-effectiveness and fails to appropriately share risks between the utility and consumers (Ismail and Wood, 2023[55]).
Lack of transparency. While the regulator and Eskom publish documents each year outlining the request and decision-making process, there remains a lack of transparency regarding the specific costs associated with generation, transmission and distribution activities. This opacity, often characteristic of a vertically integrated public utility, prevents identifying areas for cost-efficiency improvements.
Inadequate trade-off between cost-reflectiveness and affordability. Prices have not been cost reflective for a long time, undermining Eskom’s ability to generate adequate returns and contributing to a build-up of debt (Eskom, 2023[56]; 2021[52]; Trimble et al., 2016[57]). However, recent price hikes have led to a significant price catch-up to international standards (Figures 4.3 and 4.14) and made electricity less affordable (Labuschagne, 2024[58]).
Different approaches for tariff regulation
Cost-based (rate-of-return) regulation: Tariffs are set to cover system operators' justified costs, including operating and capital expenditures costs, plus a return on invested capital. This approach is expected to ensure the financial sustainability of the utility.
Country examples: China, Canada, Indonesia, South Africa
Revenue or price-cap regulation: Revenues or prices are fixed for a set period. Tariffs adjust annually for inflation and efficiency gains. Operators are encouraged to be efficient because they can keep the savings from efficiency improvements, i.e. the difference between the price cap and the effective price.
Country examples: this is the main common approach adopted in European countries for instance in Italy, Germany, Norway and the United Kingdom
Performance-based (Yardstick) regulation: These models, less common, link tariffs to performance or compare operators to drive improvements in efficiency and service quality. Best performers provide the benchmark against which other operators’ performance is assessed. Therefore, this approach is particularly sensible in the competitive segments of the electricity sector and is usually combined with other approaches.
Country examples: The Netherlands, Norway
The main trade-off between these different approaches is the balance between the risk that the operator does not recover costs and incentives for efficiency. While the main objective set by the regulator may depend on local conditions and the main principle behind electricity tariff methodology may vary accordingly, countries typically adopt a hybrid regulatory approach. For instance, efficiency incentives (such as an X-efficiency factor) are increasingly introduced alongside price cap or rate-of-return regulation, as seen in Europe and Australia. To mitigate capital expenditure bias – where capital investments are favoured over operational spending – regulators also implement measures that promote operating expenditures (such as in Austria where both costs are considered jointly) or link cost-based approaches to service improvements and cost efficiency.
4.5.3. Implementing effective tariffs to accommodate a decentralised electricity system
The shift towards a more decentralised electricity system presents significant challenges for distributors. In the traditional system, NERSA regulates tariffs at each stage: i) Eskom’s tariffs, which average all costs (generation, IPP purchases, transmission and distribution); ii) wholesale tariffs, which set the prices for Eskom’s sales to other distributors, i.e. municipalities; and iii) distribution tariffs for municipalities, which aim to cover both electricity costs and distribution expenses (including maintenance and expansion). With more Independent Power Producers (IPPs) and small-scale generators now using distribution networks to reach end users, new “use-of-network” (or “wheeling”) tariffs are needed. These tariffs, currently unregulated by NERSA, are left to municipal discretion. However, the absence of national legislation may hinder the growth of electricity supply from IPPs and small-scale generators.
Two critical challenges need to be addressed: i) incentivising self-generators to connect to the grid and sell their electricity surplus and ii) safeguarding the financial sustainability of municipalities:
Most municipalities manage small-scale generation, offering households credits for surplus electricity, which offset their bills. However, these credits expire annually, discouraging net selling. Cape Town’s “Cash for Power Programme”, launched in January 2023, addresses this, allowing households to earn credits against their full municipal bill and receive cash for surplus power sold to the grid. Expanding this programme nationwide could greatly increase small-scale grid generation.
As more households and businesses generate their own electricity, the volume of electricity transmitted through municipal distribution networks may decrease, leading to reduced revenue from electricity sales. Since fixed operational costs depend on the size of the network to maintain and upgrade – rather than on the flow of electricity – municipalities are likely to face increasing financial stress. To mitigate this risk, tariffs can be structured with fixed charges ensuring that municipalities recover the costs of distribution activities even if electricity sales decline significantly. However, it requires careful design to maintain incentives for self-generators to sell electricity to the grid.
A common billing framework providing clear guidance for municipalities on establishing use-of-network charges would help mitigate the above challenges and reduce uncertainty for generators. Progress in this area is underway, with the National Wheeling Framework published for public consultation in August 2024. Once approved, it will be adopted and implemented by municipalities. Advancing this process would be highly beneficial. To process the large volume of billing data, end users’ meters and municipalities’ digital capabilities need to be significantly upgraded. Higher cost-reflective tariffs combined with short-term targeted financial transfers could help cover the costs of these investments.
4.5.4. Boosting the political acceptability of price increases through targeted support
Moving to cost-reflective electricity pricing and strengthening price signals that disincentivise the use of coal are crucial for Eskom’s financial stability and for advancing the transition away from coal. However, affordability remains a key challenge: between 2007 and 2022 electricity prices rose by 450%, far outpacing inflation (129%) and reaching above OECD averages, placing an increasing strain on households (see Figure 4.3, and Figure 4.14, Panels A and B). Although Eskom requested NERSA's approval for a 36% tariff increase effective March 2025, NERSA approved a lower increase of 12.7%. The approved hike still exceeds inflation by a wide margin and is likely to place a disproportionate burden on low- and middle-income households, while potentially accelerating the shift toward off-grid solutions among higher-income groups. Opposition to increases in electricity prices often arises from concerns about the impact on firms' profitability and affordability for vulnerable households. Public acceptance can be increased by clearly communicating how the additional revenue will be used to help mitigate the adverse effects of higher electricity prices and improve access for households and SMEs (Dechezleprêtre et al., 2022[59]). Although unseen on users’ electricity bills, taxpayers already shoulder the costs of subsidising Eskom’s operations through large transfers.
To better support firms, higher electricity prices could be accompanied by targeted and time limited support to help those highly impacted adjust. Lessons in policy design could be drawn from the subsidies introduced in most OECD countries over the period of high energy prices in 2021-22. For example, some countries capped electricity prices for specific kinds of businesses, such as small enterprises (e.g., France, Japan) or certain energy-intensive industries (e.g., France, Italy, Spain). Some countries temporarily reduced energy-related taxes (e.g., Austria, France, Germany) or network fees (e.g., Estonia, Italy). Evidence suggests that on average, firms can adapt to higher electricity prices and achieve increased productivity in 4-5 years by investing in energy efficiency (André et al., 2023[60]). However, adaptation hinges on the availability of alternative energy sources, highlighting the importance of scaling up renewable electricity generation. Firms' ability to adjust also depends on having robust environmental policies and a strong macroeconomic environment.
To better support households, the main challenges are to improve access to electricity infrastructure and ensure affordability. Specific support is already in place, in particular the Free Basic Electricity (FBE) subsidy, which has provided a free allowance of 50 kWh per month to disadvantaged households since 2003. This programme should be strengthened and take up improved, with an estimated 5.4 million or almost 80% of eligible households not receiving it in 2020 (Figure 4.14, Panel C). The main challenges include poor targeting (as many municipalities lack registries of indigent households), weak administration (municipalities struggle to implement and monitor these registries) and coordination issues between Eskom and municipalities when Eskom is responsible for delivery. Additionally, the FBE programme currently provides an insufficient amount of free electricity to fully meet basic needs, such as cooking and heating (Ledger, 2021[61]). Estimates suggest that the FBE allocation would need to be increased by 50% to adequately support eligible households (Vanheukelom, 2023[16]).
Several actions could be considered to support the take up of the FBE subsidy and increase its effectiveness at fighting energy poverty. First, improving communication on the availability of the scheme, simplifying registration as well as increasing transparency in municipal fund usage is crucial to ensuring resources are allocated as intended. In some municipalities, the transfers received to compensate for the subsidy are used for other purposes (Ledger, 2021[61]). This should be dissuaded by strengthening municipalities’ accountability, including greater conditionality on using these funds alongside measures to improve oversight, including the implementation of penalties when FBE is not properly delivered. However, revising the unconditional nature of grants may prove challenging, as it constitutes a constitutional right of municipalities. Several actions could be taken to improve managerial capacities of municipalities. Stronger support in maintaining up-to-date indigent registers could be achieved by better integrating municipal databases with national social grant recipient lists. Training municipal staff in efficient database management, including the use of digital tools, would also enhance accuracy and administration. Expanding the use of prepaid meters can also help automate FBE distribution while improving coordination between Eskom and municipalities. Implementing a more refined tiered pricing structure enabled by digital meters could also allow minimal payments above a certain threshold to maintain incentives for energy efficiency and reduce stigma. Finally, linking FBE with other social programmes, such as water and housing initiatives – which have more effective indigent-targeting mechanisms – could create a more comprehensive safety net.
Source: IEA Data Services; and IEA (2023), Shares of home energy expenditure in average household incomes in major economies, 2021-2022, IEA, Licence: CC BY 4.0; and Ledger (2021).
Ultimately, in municipalities with limited capacity, alternative tools such as vouchers, grants, or subsidies could be considered, as they may be more efficient than in-kind benefits. These alternatives could leverage central transfers based on social databases, reducing administrative complexity by eliminating the need to monitor electricity consumption among indigent households. However, this approach comes with its own challenges, including the potential use of financial support for other purposes given competing needs for limited resources while the risk of greater reliance on alternative energy sources, such as burning tyres, may pose significant health and emission concerns.
Reducing non-payment among consumers would also help reduce budget strain in municipalities and raise room to target support to those most in need. Evidence suggests that non-payment of electricity bills is a significant issue for many municipalities, with their financial performance reduced by ZAR 291 for every ZAR 1 000 increase in bad debts written off (Murwirapachena, Kabange and Ifeacho, 2022[62]). Non-payment is typically less of an issue in large municipalities and municipalities receiving a high share of grants to support free basic electricity. To assist municipalities struggling to improve revenue collection, the National Treasury included a SMART Meter project as part of the Municipal Debt Relief Programme and issued a transversal tender for SMART metering. However, challenges remain, including high installation costs for municipalities and concerns about reduced electricity access for low-income communities. Public relations might also be used to reduce non-payment. Some suggest involving traditional leaders and influential community members to promote a culture of payment (Enwereji and Potgieter, 2018[63]). Ultimately, a key factor in fostering this culture is improving service delivery and ensuring accurate billing.
The Integrated Resource Plan (IRP) is a national policy document that outlines the country's energy mix and electricity generation capacity for the next decade. It was first published in 2011, then updated in 2023. Further revision is under discussion.
The Transmission Development Plan (TDP) assesses South Africa’s network requirements and proposes plans to meet projected future electricity demand and the renewable electricity that will need to be integrated in the next 10 years. The latest plan covers the period 2025-2034.
The Energy Action Plan (EAP), established by President Ramaphosa in 2022, is a strategic planning document that lays out goals and possible actions to reduce electricity consumption, including increasing energy efficiency and procuring more renewable electricity. The National Energy Committee (NECOM) oversees the plan’s implementation and coordinates the many government agencies involved.
The Just Energy Transition Implementation Plan (JET IP) sets out several interventions and investments to reducing emissions and become more resilient to climate change over the period 2023-2027.
The Electricity Regulatory Amendment Act (ERA) lays the legislative foundations for establishing a fully independent Transmission System Operator (TSO) in the coming five years. The ERA Act will provide for additional electricity generation capacity and infrastructure and for an open-market platform that allows for competitive electricity trading. It was signed in August 2024 by the President, amending the Electricity Regulation Amendment Act 1999.
The Renewable Energy Independent Power Producer Procurement Programme, launched in 2011, is a competitive tender process designed to facilitate private sector investment into grid-connected renewable electricity generation.
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