How a high cost of capital is holding back energy development in Kenya and Senegal

Power consumption in Africa is rising quickly, and renewable energy is set to play a major role in meeting the increase in demand. Based on today’s policy settings, 80% of new generation capacity in Africa by 2030 is projected to be from renewable sources, particularly solar PV, hydropower and geothermal. Meanwhile, achieving the goals on climate, energy development, and universal energy access laid out by African governments would require even faster uptake of renewable power. IEA analysis indicates that in this scenario, annual energy investment needs to roughly double from USD 110 billion today to over USD 200 billion by 2030, largely driven by growth in spending on clean power projects and the infrastructure to support them.

As investment needs grow in the power sector – where projects tend to have relatively high upfront costs – financing becomes especially important. However, many African governments face challenges in financing clean energy projects due to public funding constraints such as high debt servicing costs. This, combined with limited financial market maturity and low domestic savings levels, results in a reliance on external funding for clean energy projects from development finance institutions (DFIs) or international private financiers. While DFIs can offer lower or concessional rates, private financiers often have to price in higher project risks, resulting in a high cost of capital. This makes it harder for projects to be considered bankable or provide affordable power to end users.

As countries in Africa look to expand clean power, overcoming these barriers will be critical and require the adoption of effective solutions. 

In 2024, the IEA added Kenya and Senegal, both IEA Association countries, to the Cost of Capital Observatory, an IEA-led initiative that tracks the cost of capital in different countries based on surveys of investors and experts. Both Kenya and Senegal have benefitted from clear government targets and a growing share of renewables in their respective energy mixes. In the past decade, Kenya expanded its solar and wind sectors, and it is now home to the continent’s largest onshore wind development, the Lake Turkana Wind Project. Over the same period, Senegal secured over USD 1 billion in independent power producer (IPP) projects which financed over 310 megawatts (MW) of wind and solar projects, including the Ten Merina solar PV plant (30 MW) and the Taiba N’diaye wind plant (159 MW).

Despite clear interest from investors, the cost of capital for clean power projects in both countries remains high. For utility-scale solar power projects, our survey data suggests that the weighted average cost of capital (WACC) in Kenya and Senegal is between 8.5% and 9%. In North America or Europe, rates are between 4.7% and 6.4%.

Nonetheless, Kenya and Senegal see lower financing costs than South Africa and other emerging and developing economies covered in the Observatory, where the WACC is between 9.5% and 11%. This is primarily due to the role of concessional capital; about half of the projects analysed in Kenya and Senegal were funded by international financial institutions in the form of low-cost debt.

While concessional capital lowers the overall WACC for clean power projects in these countries, it complicates the comparison across emerging and developing economies as it does not reflect the risks assessed by most investors, or the rates of capital available in the local market. Businesses in the energy sector raising capital domestically often report rates of over 15%, with pay-back periods that are too short for most of their needs. Many larger energy projects therefore only go ahead if concessional capital is available.

Most renewable power projects in Africa that relied on concessional finance used tools such as political risk insurance or guarantees to help lower risks for other investors. Yet even with these mechanisms in place, the perception of political or macroeconomic risks at the country level drove up borrowing costs.

The cost of capital is made up of two components: a base rate, which reflects these country-level risks, and a premium that relates to the sector and technology. According to our analysis, the base rate accounts for 60% to 90% of the overall WACC for solar PV plants in Africa, compared with 35% in China and 10% in advanced economies.

Meanwhile, survey respondents said that, in Kenya and Senegal, the premiums associated with sector and technology were driven mostly by risks associated with the regulatory environment, the reliability of off-takers, and the health of transmission networks. As shown in the figure below, sector-specific risks result in a further 5% and 7% being added to the base rate in Kenya and Senegal respectively for solar PV projects. This is notably higher than in South Africa, where the country’s more mature utility-scale solar sector results in a lower premium of 3% to 4.5%. 

Current approaches to financing, which often involve a high proportion of foreign currency, can drive capital costs even higher. In Kenya and Senegal, off-taker risks were among the top three sector-specific concerns reported for clean energy projects. In both countries, state-owned utilities, Kenya Power and Senelec, act as the sole off-taker, and both have high debt levels, increasing the risk of non-payment to power producers. Notably, all Power Purchase Agreements (PPAs) in Kenya and Senegal covered by the IEA Cost of Capital Observatory were in hard currency. In Senegal, investments were primarily in euros, to which the West African CFA franc is pegged. In Kenya, investments were primarily in US dollars due to volatility of the Kenyan shilling, which depreciated 28% against the US dollar between 2018 and 2024. Given that clean power projects earn revenue in local currency, the cost associated with currency devaluations are passed on to the utility – increasing their debt servicing costs and worsening their overall financial health. The accessibility of foreign currencies can also lead to delays. For instance, in 2023, Kenya’s state utility had to delay payments because it struggled to source US dollars and euros.

Given the significance of off-taker risk, addressing concerns about potential non-payment by utilities is key to reducing capital costs. Using guarantees – often from external providers, given the unsustainability of current government debt levels – can help investors reduce risks to future revenue and potentially lower the sector-specific premium. Over the longer term, governments can also work to improve the financial health of utilities by implementing fully cost-reflective tariffs, improving collection rates and, if necessary, consulting with development finance institutions (DFIs) to support debt restructuring programmes.

Another major driver of a high cost of capital is the regulatory environment, which also ranked among the three top risks associated with clean energy projects in Senegal and Kenya – even though both were among the top five countries listed on the African Development Bank Group’s 2022 Energy Regulatory Index. That investors still highlighted this as a risk could indicate that they still carry concerns until markets are mature and regulation is shown to be stable and consistently enforced. It also highlights that small gaps in the regulatory environment can have a major impact. For example, in Kenya, a lack of clarity over the introduction of a new auction system for power projects led to a stalling in the procurement of new projects. Investors in Senegal also highlighted questions around the auction design for power projects and called for a simpler authorisation process.

Given the large role of the base rate in the WACC, many solutions to bring down financing costs come from outside of the energy sector. In Africa, as of January 2025, only two countries had investment-grade credit ratings (Botswana and Mauritius). This dramatically affects the ability of many international investors to invest in projects and pushes up financing costs. Organisations such as the AfDB have expressed the need to review how credit rating agencies assess risk in African countries, arguing the perception of the region as riskier can lead to disproportionate penalisation in the rating process, which has significant consequences.

Another longer-term solution is to expand local currency lending. In South Africa, where the domestic financial market is more developed, half of the projects covered by the IEA Observatory were in local currency. This removes any currency mismatch and some of the risks that are exclusive to foreign investors, such as currency repatriation or unfamiliarity with the country context. However, outside of some of the largest economies in the region, local currency financing is often priced higher than foreign currency, either due to high volatility (if the financing provider is international) or high local government lending rates (if the provider is domestic). Against this backdrop, credit enhancement mechanisms, such as currency hedging products or local currency guarantees from international finance providers, could support growth in affordable local currency financing.

Lowering the cost of capital represents one of several necessary steps for unlocking more funding for clean energy in Kenya, Senegal and other emerging and developing economies. Investors often report a lack of bankable projects, implying more equity capital needs to be made available for projects in early stages. Equally, an increase in grant funding and higher risk-taking from concessional providers, if paired with the relevant policy reforms and tailored approaches to structuring financing, are key to fostering an attractive environment for private investment.

Data gathering for this commentary was supported by Niccolò Hurst at ETH Zürich.