• Zimbabwe has licensed 7,876MW of independent power projects, and dependable generation sits at roughly 1,200MW to 1,600MW against
• Hwange Units 7 and 8 and Kariba supplied three-quarters of grid power in the second quarter of 2026, and independent producers contributed only 5%
• Meeting the 2030 private generation target requires about 500MW a year to reach financial close, more than ten times the pace of the past eight years

Harare  -  Centragrid, an independent power producer that runs a utility-scale solar plant at Nyabira in Mashonaland West, told the Zimbabwe Economic Development Conference (ZEDCON) that high interest rates, legacy utility debt and currency uncertainty continue to deter investors from power projects in Zimbabwe.

Zimbabwe had licensed 7,876MW of independent power projects by March 2025, including 2,868MW of solar. Dependable generation sits at roughly 1,200MW to 1,600MW against peak demand of about 2,200MW, and the World Bank projects demand of 5,177MW by 2030.

The National Energy Compact targets 5,432MW of installed capacity by 2030 and puts the generation bill at US$3.81 billion, 90% of it expected from private investors. The full 2025 to 2030 energy envelope is US$9.1 billion, including US$968.4 million for transmission and US$147.4 million for distribution. Private generators are expected to own 2,440.5MW of the 2030 total, against 356MW of private capacity added between 2017 and 2024. Adding about 2,085MW in the remaining years implies roughly 500MW a year, more than ten times the pace of the past eight years.

A generation licence grants regulatory permission to develop a project. It secures no debt, no equity, no offtake agreement and no transmission capacity, so the 7,876MW pipeline holds projects at very different stages of readiness. The conversion rate from licence to financial close, construction and grid connection is the figure that measures progress.

Zimbabwe built its power system around a state utility model centred on ZESA and its generation and transmission subsidiaries, with Kariba South and Hwange as the main stations and smaller thermal plants in support. The model depended on sustained public and utility investment in generation, maintenance and networks, and that investment broke down during the years of macroeconomic instability. The World Bank recorded available capacity of 1,585MW against peak demand of 1,900MW in 2020, with outages of 12 to 14 hours a day.

ZETDC, the buyer for most independent power, carries substantial creditor obligations and legacy debt built up through high inflation, exchange rate movements, sub-economic tariffs and internal inefficiency. The Compact adds poor revenue collection, technical and commercial losses, theft and vandalism to the list. A private generator selling to that buyer either prices the credit risk into its tariff or does not build.

Power projects import their equipment, service foreign currency debt and recover capital over decades, so a tariff collected in a depreciating currency erodes debt service capacity. The Compact names exchange rate fluctuations and multicurrency accounting as constraints on pricing that recovers full costs. ZERA has raised the average tariff to 16.08 US cents per kilowatt hour from 11.3 US cents. Purchased electricity takes 10.97 US cents of the current structure, distribution 1.27 US cents and transmission 0.39 US cents, and the return on assets component is 1.28 US cents, about 8% of the tariff. That leaves little room to fund network investment or repay legacy debt.

Limited access to cheap long-term finance pushes developers towards expensive short-term funding, a constraint the Compact identifies directly. A solar or hydro plant can run for decades, and its financing terms decide whether it reaches construction and whether its tariff can carry debt service and an investor return.

Zimbabwe Power Company and Reserve Bank data put generation at 2,788.64GWh in the first quarter of 2026 and 2,914.47GWh in the second, about 5,703GWh for the half. Hwange Units 7 and 8 produced 1,283.41GWh of the second-quarter total, or 44%, Kariba 943.79GWh or 32%, the older Hwange units 530.43GWh or 18%, and independent producers 156.85GWh or 5%. Two stations supply three-quarters of grid power.

Hwange Units 7 and 8 added 600MW and took the complex to around 1,520MW. The Compact puts Zimbabwe Power Company’s installed capacity at 2,640MW, made up of 1,050MW at Kariba, 920MW at Hwange Units 1 to 6 and 670MW at Units 7 and 8. The older units hold more installed capacity than the new ones and produced only 41% of their output in the second quarter, the clearest measure of the rehabilitation backlog. Coal production rose to 5.8 million tonnes in 2024 from 4.9 million tonnes in 2023, partly on demand from the new units, reached 2.14 million tonnes in the second quarter of 2025 and fell to 1.64 million tonnes in the fourth quarter.

Kariba’s 1,050MW generates only as much as the Zambezi River Authority water allocation allows. The authority cut the 2024 allocation to 16 billion cubic metres after a poor rainy season, against 27 billion cubic metres for 2025. Kariba produced 955.67GWh in the first quarter of 2026 and 943.79GWh in the second. Usable storage stood at 39.09% on 28 September 2026, up from 15.29% a year earlier, a stronger buffer that still depends on the coming rains.

National installed capacity, on and off grid, stands at 2,962MW according to the Compact, above peak demand, and dependable output still falls short enough to require imports and load-shedding. The Southern African Power Pool records Zimbabwe with 2,045MW installed and 1,555MW operating against peak demand of 1,615MW, a 292MW shortfall once reserve requirements are counted. Zambia has 2,734MW operating against peak demand of 2,194MW, Mozambique 2,279MW against 1,850MW and Angola 2,500MW against 1,869MW. Imports from those systems cost foreign currency and depend on their spare capacity, so regional trade can balance the grid and cannot replace domestic investment.

The World Bank estimates that electricity shortages, generation inefficiency and network losses cost Zimbabwe 6.1% of GDP a year, with 2.3% from inefficiency and losses and 3.8% from the downstream effects of unreliable supply. Mines need power before production starts and reliable power to keep plant running, farms need it for irrigation, processing and cold storage, and manufacturers lose output and pay for back-up generation. Export capacity and the returns on new productive investment are both capped by the power supply.

The Government Project Support Agreement framework covers political risk, power purchase agreement tariff risk and currency convertibility risk, with government commitments on tariffs that recover full costs, electricity uptake and offshore repatriation of investor funds. Vungu Solar signed a 25-year power purchase agreement with ZETDC for its 30MW project in 2026 under that framework. The Compact’s wider reform programme adds competitive procurement to weed out speculative licences, standardised power purchase agreements, third-party access so generators can sell directly to large customers, and regional trading through the power pool to widen the offtake market.

ZETDC’s legacy liabilities cannot stay embedded in the cost of new power purchases. Debt restructuring, stronger collections, revenue ring-fenced for power purchases and transparent settlement would give generators and lenders a clearer basis for underwriting projects. The Compact targets full operational cost recovery for utilities by fiscal 2027 and includes legacy debt resolution among its core objectives. Hwange needs predictable maintenance and rehabilitation finance and reliable coal supply for its older units. Kariba needs reservoir management, dam maintenance and a wider generation mix that can carry demand in dry years. New generation also needs the US$968.4 million transmission programme to move power to industrial and household demand.

Zimbabwe has the resources, a licensed pipeline, a functioning regional power pool, a larger coal base after Hwange 7 and 8 and a recovering Kariba reservoir. Capital, utility creditworthiness, tariffs, currency risk and transmission are the binding constraints. Private generators need to move from 356MW towards 2,440.5MW by 2030, about 500MW a year reaching financial close and commercial operation. Independent producers need to lift their 5% share of grid output, and ZETDC needs to reach full cost recovery by 2027. Licences without financial close will leave the gap between installed and dependable capacity where it stands today.

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