• SAPP's competitive electricity market traded 191.20 GWh in August 2026, up 16.1% year-on-year, but the day-ahead market left 40.12 GWh of matched electricity untraded, equivalent to 24.9% of matched volume
• Off-peak hours accounted for 34.84 GWh, or 86.8% of the day-ahead market's untraded electricity, while settlement-area prices ranged from US$54.80/MWh to US$64.90/MWh
• Europe estimated €580 million in additional economic welfare could have been gained through fuller cross-border capacity allocation in 2024, while the World Bank is supporting Southern African transmission preparation and market reform

Harare - Southern Africa's electricity market traded 191.20 gigawatt-hours in August 2026, its highest monthly competitive-market volume in the first five months of the financial year, but the region's transmission network prevented substantial volumes of matched electricity from being delivered. Southern African Power Pool (SAPP) records show 161.06 GWh matched in the day-ahead market against 120.93 GWh traded, leaving 40.12 GWh untraded.

The shortfall reveals a structural weakness in regional electricity integration: generation and demand can meet commercially while the physical network limits the transactions completed. For economies seeking to expand mining, manufacturing and mineral processing, that constraint affects access to competitively priced electricity and the commercial value of available generation.

SAPP's August report recorded a 6.1% monthly increase in competitive-market trading and 16.1% growth from August 2025. From April to August, cumulative competitive-market transactions reached 815.24 GWh, 24.7% above the comparable period. The recovery indicates greater use of regional trading arrangements, although the figures cover competitive transactions rather than all electricity exchanged through bilateral contracts.

Zimbabwe hosts SAPP's Coordination Centre in Harare, giving the country an institutional role in a market connecting electricity systems across 12 continental SADC member states. Established in 1995, the power pool provides mechanisms for utilities and other eligible participants to trade electricity through bilateral contracts, day-ahead markets, forward products and intraday arrangements. These instruments allow buyers to access supplies beyond national boundaries, subject to available transmission capacity and settlement obligations.

The market's August performance exposes an inconsistency requiring clarification. SAPP's executive summary states that transmission bottlenecks prevented 33% of matched bids from being traded. Its detailed day-ahead table, however, records 40.12 GWh untraded from 161.06 GWh matched, equivalent to 24.9% of matched energy. The 40.12 GWh also represents approximately 33.2% of the 120.93 GWh actually traded. The report does not explain the relationship between its headline percentage and the detailed energy figures, so the two measures should not be treated as interchangeable.

The underlying table provides another important finding. Of the 40.12 GWh not traded, 34.84 GWh occurred during off-peak hours, accounting for approximately 86.8% of the day-ahead shortfall. Only 64.57% of matched off-peak energy was successfully traded, against 91.67% during the morning peak, 90.66% during standard hours and 99.38% during the evening peak.

The concentration during off-peak periods suggests that transmission constraints are especially important when the market has substantial electricity available outside peak demand hours. It does not establish which individual generators lost sales or which consumers were unable to obtain electricity. Those effects require corridor-level trading records and evidence of the alternative supply arrangements used by affected participants.

The pricing data provide a further indication of regional segmentation. SAPP reported an average unconstrained day-ahead price of approximately US$56.46 per megawatt-hour in August, while settlement-area prices ranged from US$54.80 to US$64.90. Zimbabwe's settlement area was reported at approximately US$64.80/MWh, alongside several northern and central trading areas, while southern areas recorded lower prices.

The spread demonstrates that a shared electricity market can contain different local prices when transmission and other market conditions influence the cost of supply. It does not mean every Zimbabwean electricity customer was purchasing power at US$64.80/MWh. The figure is a wholesale market indicator, distinct from domestic retail tariffs, bilateral import prices and individual industrial contracts.

A further measure of congestion appeared in the market revenue breakdown. SAPP reported approximately US$1.035 million in congestion income during August, representing 7.6% of the reported market revenue components. This is settlement income arising from market arrangements, not a calculation of the total economic loss caused by blocked transactions. Establishing that loss would require matched bids, actual prices, costs of replacement electricity and the operating decisions of affected participants.

The distinction is important because untraded electricity cannot automatically be classified as wasted physical generation. A matched bid represents a trading opportunity that may not proceed because a secure transmission path is unavailable. Generators may reduce output, find other buyers or change their operating schedules, while purchasers may use alternative sources. The financial consequences differ across these outcomes.

The World Bank's assessment of SAPP illustrates the limits of the existing regional market. Between April 2023 and March 2024, Southern Africa traded approximately 7.6 terawatt-hours of electricity through the pool, with competitive markets accounting for only 16% of that volume. During the subsequent drought-affected period, the competitive-market share fell to approximately 7% as utilities prioritised supply security. These figures demonstrate the continuing importance of bilateral contracts alongside more flexible market trading.

For Zimbabwe, dependable electricity remains central to industrial investment. Ferrochrome smelters, steel plants and emerging lithium chemical-processing facilities require predictable supply to support continuous operations. Interruptions can reduce plant utilisation and increase costs where firms rely on backup generation. Regional purchases can help diversify supply, but their value depends on delivered electricity prices, contractual reliability and the capacity of interconnectors.

Zimbabwe's geographical position also gives it a role in electricity transactions extending beyond domestic consumption. The regional central corridor links generating and consuming areas across several countries. Congestion along these routes can affect transactions between markets that are commercially willing to trade, even when neither the original generator nor the final purchaser is located in Zimbabwe.

The scale of this problem is increasingly relevant to regional industrial policy. Zambia's copper-processing economy, Zimbabwe's mining and manufacturing facilities, Botswana's industrial consumers and South Africa's large electricity market have different demand patterns and generation resources. An interconnected system can use those differences to support more efficient dispatch, provided electricity can move between them.

Europe offers evidence of the economic benefits and continuing difficulties associated with market integration. The European Union has developed coordinated day-ahead and intraday electricity markets that connect national trading zones. Market coupling allows available transmission capacity to be considered when matching electricity purchases and sales, helping power move towards markets where it has greater commercial value.

The European Union Agency for the Cooperation of Energy Regulators estimated that €580 million in additional economic welfare could have been achieved in 2024 if transmission system operators in the Core region had made at least 70% of relevant capacity available for cross-border trading. The regulator found that only approximately 40% of those potential gains had been realised.

Europe's experience shows that established electricity markets can continue losing economic value through constrained interconnections. The regulator estimated that congestion management cost approximately €4.3 billion across the EU in 2024, while greater market integration in balancing electricity delivered €1.6 billion in economic welfare benefits. Those amounts belong to Europe's much larger electricity system and cannot be applied directly to Southern Africa, but they establish the financial significance of transmission access and coordinated market rules.

The European framework also provides an institutional lesson. Its 70% cross-border capacity requirement gives transmission operators a measurable obligation and regulators a benchmark for monitoring performance. Southern Africa's commercial and network conditions differ, but greater disclosure of transmission capacity offered, capacity allocated and matched trades prevented from proceeding could strengthen accountability within SAPP.

India provides a different comparison. Its five regional electricity grids became fully interconnected in 2013, creating the foundation for nationwide electricity transfers. The International Energy Agency reported that India's interregional transfer capacity exceeded 120 gigawatts by 2025, supported by continued investment in transmission infrastructure.

India's experience demonstrates the importance of coordinated network development across geographically diverse electricity systems. Its integrated grid allows power to move between regions with different demand profiles and generation resources. Southern Africa's international market involves separate national utilities, governments and regulatory systems, making the institutional arrangements more complex than those within a single country.

Closer to home, the region is beginning to finance additional infrastructure. In July 2026, the World Bank announced a US$43 million grant to support the Zambia-Malawi electricity interconnector. The financing covers approximately 47 kilometres of transmission construction on the Zambian side of a planned 192-kilometre, 400-kilovolt corridor.

The project is intended to provide Malawi with stronger access to regional electricity markets, diversify sources of supply and improve resilience to generation shortages. Its contribution will depend on construction and commissioning, the availability of power for trade and the commercial arrangements established between participating electricity systems.

Another intervention targets the market's wider institutional capacity. In November 2025, the World Bank approved US$12 million in financing for technical assistance to SAPP and regional energy organisations. The programme supports regional electricity trading, transmission project preparation and an enabling environment for investment.

These commitments provide institutional and financial support, but their impact cannot be assessed by approved funding alone. A transmission project creates value when it becomes operational and increases the volume of electricity that can be transferred. Technical assistance is more useful when it leads to improved market rules, financeable projects and measurable trading outcomes.

The World Bank has also identified longer-term opportunities for connecting currently isolated or weakly linked electricity systems. Planned interconnectors involving Angola, Namibia, Tanzania and Zambia could extend regional market access and diversify the available generation base. Each project faces different financing, environmental approval and construction requirements.

The business case for such investment should be tested against specific transmission bottlenecks. An additional interconnector may improve security of supply, enable renewable electricity trading and reduce reliance on expensive generation. The expected benefits depend on where the line is built, how frequently it is used and the difference between prices in connected markets.

Financial settlement creates a separate constraint. A buyer may find competitively priced power but still require sufficient liquidity, credit support and approved payment arrangements before the transaction can be completed. Transmission expansion must therefore be accompanied by reliable market settlement and financially credible participants.

The integration of renewable energy increases the importance of these arrangements. Solar output can be abundant during daylight hours, while hydropower availability changes with rainfall and reservoir conditions. Regional trading can help balance these differences across larger markets, but only where the network and market products accommodate the timing of available supply.

The August 2026 data provide an immediate accountability benchmark. SAPP should be able to identify the corridors responsible for the 40.12 GWh day-ahead shortfall, the reasons for the concentration in off-peak hours and the changes in available capacity needed to complete additional transactions. Publication of these measures over time would allow regional governments and businesses to establish the effects of transmission investment.

For Zimbabwe, the relevant gains would include more reliable access to regional supply, competitive wholesale purchasing opportunities and stronger conditions for industrial production. For exporting utilities, additional transmission capacity could create opportunities to sell electricity that would otherwise remain outside the competitive market.

Southern Africa has established institutions capable of matching electricity buyers and sellers across national borders, and August's increased trading volumes demonstrate growing commercial participation. The region's next challenge is to improve the physical and financial systems that allow those transactions to proceed. The 40.12 GWh of untraded matched day-ahead electricity provides a measurable starting point for examining the economic cost of unfinished integration and the return from infrastructure designed to resolve it.

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