Powering Zimbabwe: energy sector reforms and reasons for cautious optimism

By Ryan Kitcat, Partner, Bowmans

Zimbabwe’s economy has demonstrated  growth and resilience of late, despite being buffeted by global geopolitical turbulence, volatile commodity and energy prices and climate-related risks. After a drought-hit 2024, growth rebounded strongly in 2025 and is forecast at around 3.5% in 2026. The International Monetary Fund’s August 2026 review noted that Zimbabwe “has continued to consolidate stabilization gains under the [IMF] Staff-Monitored Program (SMP) despite external shocks”, with inflation low, the exchange rate broadly stable and a window opening to “advance reengagement toward arrears clearance and debt resolution”.

Power remains fundamental to Zimbabwe’s economic recovery and its efforts to achieve sustainable development. The World Bank estimated in 2023 that shortages cost Zimbabwe about 6.1% of GDP a year. Hence the Government’s drive to implement energy sector reforms to improve energy security and meet the needs of industry and a growing, increasingly urbanised population.

Energy mix, targets and climate commitments

Zimbabwe’s installed capacity of about 2 962MW is dominated by coal (56.7%, mainly at Hwange) and large hydro (35.4%, at Kariba), with independent power producers (IPPs) contributing under 8%. Dependable capacity is somewhat lower, with imports via the South African Power Pool (SAPP) supporting some of the shortages experienced.

The National Energy Compact targets universal electricity access by 2030, some 1 607 km of new transmission lines and a share of non-hydro renewables of between 29% and 31% of generation, up from around 8%. The second National Development Strategy (NDS2) for 2026-2030 targets an increase in generation capacity from about 2 950 MW to 6 000 MW by 2030.

Climate risk affects Kariba’s output, which depends on rainfall, and outages at Hwange Units 7 and 8 show how vulnerable the system is to a single point of failure. Heavy reliance on these two sources of supply entails system vulnerability that recent sector reforms are intended to address.

The Compact seeks to mobilise more than USD9 billion, more than USD4.42 billion of it from the private sector, and its 55 prioritised generation projects, 41 of them solar PV, are expected to draw 90% of their estimated USD3.8 billion cost from private investors.

These targets sit alongside Zimbabwe’s climate commitments. Its revised Nationally Determined Contribution (NDC) commits to a 40% per capita reduction in greenhouse gas emissions against business as usual by 2030. The 2025 NDC 3.0 statement sets out 27 actions, 12 of them in energy, at an estimated cost of about USD19 billion.

Noteworthy projects

Hydro. The USD294 million rehabilitation of Kariba Dam is near complete and will secure the system’s largest asset. Small hydro IPPs in the Eastern Highlands have fed the grid for more than a decade. The 2 400 MW Batoka Gorge project with Zambia remains the long-term prize but is not expected before 2034.

Thermal. Hwange Units 7 and 8, commissioned in 2023 at a reported cost of USD1.5 billion, became the backbone of supply during the 2024 drought when generation from Kariba hydro dropped considerably.

Captive power. Mining electricity demand is growing rapidly, and miners have taken up power-to-mine opportunities rather than wait for the grid. Zhongjin Heli has commissioned a 100 MW first phase of its captive plant, with a 135 MW second phase in progress. Prospect Lithium Zimbabwe, a Huayou Cobalt subsidiary, has been building a 70 MW solar plant to power its lithium sulphate complex near the Arcadia mine. Zimplats and Caledonia have built their own solar plants.

Commercial and industrial (C&I) solar. Manufacturers, farms, schools and hospitals are increasingly turning to behind-the-meter solar, and some 118 MW of net-metering capacity is connected.

IPPs. In 2026, ZESA Holdings (ZESA) reported to Parliament that 635 MW of private capacity was under construction and a further 730 MW was concluding financing. Vungu Solar, a joint venture led by the UK’s Private Infrastructure Development Group, signed a 25-year power purchase agreement (PPA) with the Zimbabwe Electricity Transmission and Distribution Company (ZETDC) in January 2026. The project is noteworthy for its use of a standardised PPA and a Government Project Support Agreement (GPSA), intended to address political risk, currency convertibility risk and PPA bankability risk. On financial close, Vungu will be the first internationally financed project of its kind in Zimbabwe.

Wheeling. The Limpopo Way Power Project, once commissioned, is expected to deliver around 7 MW generated from rooftop solar through the national grid to a private offtaker under a use-of-system agreement with ZETDC. This is an important test case for the wheeling framework, which exists but needs greater certainty on tariffs, wheeling charges, and grid connectivity and capacity if it is to be commercially attractive to IPPs and offtakers. The Zimbabwe Energy Regulatory Authority (ZERA) has contracted a Spanish consultancy, MAI Group, to help develop a cost-reflective, non-discriminatory and transparent framework for transmission and distribution tariffs.

Trading. Intermediaries have recently been granted retail supply licences. ZimGreenCo, a subsidiary of Africa GreenCo, for example, holds a retail supply licence, has grid access agreements with ZETDC and has Reserve Bank of Zimbabwe approval to trade in US dollars. Prospective traders will need to consider the recently introduced export controls.

Blended finance. Blended finance is reaching smaller projects: REF Zimbabwe, backed by the UN Joint SDG Fund and Old Mutual, has financed a 720 kW solar plant at Mater Dei Hospital in Bulawayo and approved a USD6 million facility for a 10 MW solar plant in Guruve.

Energy sector reforms

The Government has implemented and is implementing reforms with a view to creating conditions that are more favourable to attracting the private capital that will be necessary to achieve the targets mentioned above.

Pricing and tariffs. The weak finances of the power utilities have historically been a cause of supply deficits. Tariffs lagged the exchange rate, falling almost 18% below cost recovery in US dollar terms in August 2022 and requiring costly subsidies. ZERA has since moved most customer categories to cost-reflective tariffs, with the average tariff rising from 11.3 to 16.08 US cents per kWh. Whether tariffs keep their value over time remains a question, and the World Bank’s recommendation of an automatic adjustment mechanism within defined bands is still relevant. A tariff methodology review under the African Development Fund-financed Energy Sector Reform Support Project offers an opportunity to adopt one.

Payment reform. Revenue collection has been tightened through prepaid metering: most domestic customers are now on prepaid meters, and smart metering is being rolled out to larger users. The Compact targets full operational cost recovery by the utilities, in both local and foreign currency, by the end of 2027.

Procurement. Historically, power projects have largely been self-sourced: a developer obtained a generation licence and then negotiated a PPA directly with ZETDC. The World Bank and ZERA observed that many licences ended up with speculators rather than serious investors. Plans to introduce competitive bidding are now being acted on, with World Bank support for transaction advisers, model bidding documents and a pilot procurement of around 370 MW.

Licensing and market access. On 31 July 2026 the Government gazetted ten statutory instruments (SIs) to reform the market, including:

• The Energy Regulatory (Designation of Energy Source) Notice, 2026 (SI 129 of 2026), which designates solar, wind, geothermal, biomass, biogas, water, nuclear, coal bed methane, coal, petroleum products, ethanol and waste-to-energy as energy sources.
• The Electricity (Licensing) (Amendment) Regulations, 2026 (No. 2) (SI 125 of 2026), which distinguish commercial projects from generation for own consumption and remove licence fees for commercial projects of up to 10 MW and for own-use and non-commercial off-grid plants.
• The Electricity (Own Consumption Undertakings Licensing Capacity) Regulations, 2026 (SI 126 of 2026), which raise the licensing threshold for own-use plants to 10 MW, so that plants between 100 kW and 10 MW need only register with ZERA before construction.
• The Electricity (Net Metering) (Amendment) Regulations, 2026 (SI 127 of 2026), which extend net metering, building on the 118 MW already connected; ZETDC is waiving upfront connection fees until March 2027 and recovering them from customers’ energy credits instead.
• The Electricity (Provision of Backbone Infrastructure) Regulations, 2026 (SI 128 of 2026), which allow companies other than ZETDC to distribute and sell electricity under renewable 25-year licences awarded by competitive bidding, with tariffs capped at ZETDC’s approved rates.
• The Electricity (Energy Management) Regulations, 2026 (SI 122 of 2026), which make energy management compulsory for designated facilities, including factories, mines, farms and commercial and institutional buildings, with an installed capacity of at least 100 kVA or which are maximum demand customers of a distribution licensee.
• The Electricity (Export Control) Regulations, 2026 (SI 118 of 2026), which apply to licensed generation and retail supply companies and limit exports to 30% of available capacity for generation licensees and 20% of contracted capacity for retail supply licensees. Exports require ZERA’s prior approval and, for sales into SAPP, confirmation of SAPP membership, and must use the national transmission network.

ZERA published revised Electricity Licensing Guidelines and Requirements in June 2026, set out the documents required for each licence category, from generation (whether selling to the grid, for own consumption or to identified customers) to transmission, distribution and retail supply. For grid-selling projects, applicants must provide current irrevocable financing commitments from both equity and debt providers, a grid impact assessment by ZETDC, a proposed PPA, an EPC contractor commitment and a full bankable feasibility study, with incomplete applications not processed. If applied consistently, this goes some way to addressing the speculative licensing that has long clogged the pipeline.

Utility restructuring. Against the regional trend towards unbundling, ZESA Holdings is being re-bundled with the Zimbabwe Power Company and ZETDC into a single vertically integrated utility under the Mutapa Investment Fund. The stated aim is to shore up the balance sheet with a view to simplifying debt restructuring, as part of the national arrears clearance and debt resolution process.

Jan Oberholzer, former chief operating officer of Eskom, has been brought in as special adviser to the chief executive. For IPPs, the test is whether all this delivers full cost recovery and a creditworthy offtaker.

Regional integration and SAPP

Zimbabwe hosts the SAPP coordination centre in Harare and has relied on the pool as a relatively expensive safety valve, importing up to 500 MW, mainly from Eskom.

SAPP presents a medium- to long-term opportunity. Selling into a regional market can spread offtaker risk beyond a single national utility, and Zimbabwe’s central location suits wheeling and cross-border trade. The building blocks are being put in place: studies on the MOZISA and ZIZABONA interconnectors have been completed, SAPP’s Regional Transmission Infrastructure Funding Facility aims to mobilise finance for cross-border lines, and protection coordination between the ZESA and SAPP grids is being strengthened to reduce system failures. Access is not unconditional, however, as the export controls show.

Risks remain but the direction of travel is positive

Developers and lenders will test any power project, in any market, against a familiar set of risks: country risk, the creditworthiness of the offtaker, currency convertibility and exchange controls, tariff and regulatory predictability, policy and legal certainty, grid access and curtailment, and the ability to secure long-term, affordable finance. These matter most where investments are capital-intensive and contracts run for 15 to 20 years or more. Some of these risks are sharper in Zimbabwe, but there is momentum in the right direction.

Recent reforms suggest that the direction of travel is positive. Cost-reflective tariffs, competitive procurement, a modernised licensing regime, standardised PPA and GPSA documents, the opening of distribution and retail supply and the restructuring of the utility all address risks that have long deterred potential investors. Some of the projects that have been and are being built, notably miners’ captive plants and behind-the-meter solar, have been driven by necessity rather than choice, but they show that private capital will move where the framework allows.

Further measures that could improve the environment for private capital include: ring-fencing IPP payments through escrow or liquidity facilities backed by multilateral guarantees; introducing automatic tariff adjustment within defined bands; strengthening regulatory independence; adopting a bankable third-party access and wheeling framework; investing in transmission and storage; and adopting a procurement framework informed by international best practice and lessons from South Africa’s Renewable Energy Independent Power Producer Procurement Programme (REIPPPP).

This article is for general information only and does not constitute legal advice.

Ends