By Prof. Ken Ife1 and Dr. Paul Alaje2

Summary

A key conversation at BRICS, 2026 should be how BRICS’s local currency financing commitment can become an industry driver in Global South countries. BRICS already has the commitment to and the vehicle — NDB; it needs 2 things: ambition beyond projects (toward industrial plays), and an anchor country to prove this ambition and framework. Nigeria can become a BRICS industrial powerhouse in Africa as a model for the Global South. At a time when renewable energy is becoming the most affordable industrial input around the world, Nigeria’s opportunity lies in building strong industries on renewable energy. The unique BRICS opportunity is arming Nigeria with affordable finance, in the form of local currency, for not just renewable energy projects but for the real economic outcome: green industries.

For long, Nigeria has been characterised as a complex country with a deep energy gap and a fast-growing population of more than 200 million people. This is the old perspective. Today, the question should be how Nigeria’s industrial powerhouse potential can be achieved with affordable, reliable, accessible energy. A key conversation at BRICS, 2026 should be how Nigeria can become a BRICS industrial powerhouse in Africa as a model for the Global South. At a time when renewable energy is becoming the most affordable industrial input around the world, Nigeria’s opportunity lies in building strong industries on renewable energy. The unique BRICS opportunity is arming Nigeria with affordable finance, in the form of local currency, for not just renewable energy projects but for the real economic outcome: green industries.

BRICS is at an inflection point testing its ability to move from a mere global alliance to delivering real economic impact particularly in Global South countries. India, assuming the BRICS Chairmanship in January this year, provided the alliance with intellectual credibility, with India’s theme for BRICS focusing on ‘Building Resilience and Innovation for Cooperation and Sustainability’. However, the coalition still needs a clear and unique development model for Global South countries. Aiming to be different from global talk shops, BRICS’s best shot at global strength and credibility is enabling key Global South countries to become industrial powerhouses.

There is no better country in Africa to test this than with Nigeria. One of Africa’s largest economies, Nigeria combines the continent’s most diverse and complex industrial base with the most acute foreign exchange vulnerability, making it the ideal place to prove that BRICS can turn an innovative development vision into reality through local currency financing.

While renewable energy projects focus on building energy systems, green industrialization goes further and opens bigger opportunities to establish industries, manufacture products and process minerals. Nigeria does not suffer a lack of natural resources or green industrial inputs. Nigeria has an abundance of solar and wind; in fact, harnessing just one percent of Nigeria’s landmass for solar infrastructure can produce enough energy to address the entire country’s energy needs. Further, Nigeria is endowed with critical minerals such as bauxite, lithium, iron ore all of which are essential for the global clean energy supply chain.

The missing input is a very crucial one: affordable finance to turn ambition and natural resources into industry. Most financing for green industrialization is expensive because it is structured in foreign currency, particularly the Dollar, while the outputs are paid for in Naira, increasing FX risk. BRICS’s New Development Bank (NDB) has the institutional mandate to finance development projects in Global South countries in local currency. The NDB has already financed projects in South Africa in local currency; it needs to go further — a green industrial pilot, in Nigeria, in Naira, would create a powerful case study for BRICS.

Going beyond renewable energy projects and financing green industrial plays in the Naira has outsized benefits for both Nigeria and BRICS; it will be an effective mechanism to open doors to Nigerian Alpha for investors in BRICS countries – in assets larger than renewable energy projects, and it will turbo-charge Nigeria’s industrial and economic growth in one of the largest countries and economies in Africa, which would also generate employment opportunities in a country where a significant proportion of its population, 56%, lives below the poverty line. For context, 56% of Nigeria’s population is more than 135 million. A model that works in Nigeria, that demonstrably unlocks clean industrial investment at scale using local currency mechanisms, is exportable. To Kenya. To Senegal. To Egypt. Nigeria as a pilot is not Nigeria as an exception. It is Nigeria as proof of concept for the continent.

As India hosts the BRICS Foreign Ministers’ Meeting, it has the unique opportunity to turn BRICS South-South commitments into a strong industrialization model that will enhance BRICS’s credibility and economic strength globally.

A model that works in Nigeria, that demonstrably unlocks clean industrial investment at scale using local currency mechanisms, is exportable. To Kenya. To Senegal. To Egypt. Nigeria as a pilot is not Nigeria as an exception. It is Nigeria as proof of concept for the continent.

Note

This is not another argument about the mismatch between solar, wind, and geothermal potential and investment. Neither is it a reminder of the fact that financing towards African clean energy is generally inadequate. By showing 5 realities and 5 insights from them, this memo uncovers African clean energy finance maldistribution & contradictions and argues that DFIs and private capital are overcrowding, missing the right places to make real frontier impact/return, and gives practical points for geopolitical deciders1, DFI allocators, and private capital allocators to consider.

Africa

Most Africa (clean energy) finance literature assumes Africa is a landmass altogether leapfrogging in the energy transition. For instance, private investment in clean energy in “Africa” rose from about $17B to about $41B in the last 5 years; but as you will see below, this is not an African story — it is the story of 6 countries in Africa distorting the finance statistics of the other 48 countries. DFI is not necessarily active in ‘Africa′, neither is substantial private necessarily flowing into ‘Africa’ — they are flowing into individual countries, and there are questions whether DFIs and private capital are optimizing their mandates in Africa. One thing is certain though: the big headlines are blinding of the realities of clean energy finance in Africa.

5 realities

1: $60B

The $60B annual clean energy finance that Africa receives is not a unitary package; $40B (67%) of it is private finance, and $20B (33%) is public/DFI.

Hypothetically

Distributing each part of the whole equally in Africa, each country would receive ~$740M in private capital and $370M in DFI/public capital. Even with these hypothetical figures (equal share among African countries), Africa lags behind ‘comparable’ “frontier” markets across the world.

The comparison raises 3 uncomfortable truths:

1. DFI $$ — functionally misplaced? A country with over $4,000 GDP per capita and relatively high private capital confidence receives more DFI finance than African countries majority of whose individual GDP per capita is less than $1,700 and enjoy less private capital confidence. If DFI finance should crowd in private capital, and solve for greater need/impact, then they should double or triple down on a country with a lower GDP per capita and lower private capital confidence, greater structural challenges but better natural resources and better fundamentals.

2. Natural resource concentration compounds the contradiction. Ideally, natural resource abundance (solar, wind, geothermal heat) should equal more financing. Africa’s Sahel, for instance, enjoys more solar irradiance than most of the countries in the above table, but receive less DFI & private financing. Africa holds the world's largest untapped renewable energy resource base than any comparable region on earth. Its population is the youngest and fastest-growing, meaning the demand for electricity will compound for decades. It has the highest rate of energy poverty of any inhabited region (4/5 of the world’s energy poverty cases are in Africa). By every measure of need, resource endowment, and long-run demand, Africa should be the world's premier destination for renewable energy investment; public and private.

3. Policy constrains the power of resources and fundamentals. The paradox is not just that Africa receives less despite having more. It is that the countries receiving more have, in some cases, structurally identical problems to Africa and solved them through policy design, not through better resources or better fundamentals. Vietnam does not have better sunshine than Senegal. The Philippines does not have better wind than Kenya. Pakistan is not a more creditworthy sovereign than Ghana. The gap is institutional and political, not physical or financial.

Note: Africa’s real (not hypothetical / per country equal share) shows a worse situation than the above comparison for reasons shared in the risk section below.

2: Private 3x; 3 stories

Annual private investment in Africa's clean energy has tripled, from about $17B in 2019 to over $40B in 2024.

The tripling from $17B to $40B is not a continental story. It is 3 stories/mechanisms in 6 countries that happened to compound in the same 5-year window:

• Policy changes in South Africa, Nigeria. Domestic policy changes unlocked C&I solar markets that had been structurally suppressed.

• Gulf equity in 3 countries. Post-COP27 geopolitical repositioning drove Gulf sovereign equity into North African utility-scale projects in Egypt, Morocco, Mauritania2 at unprecedented scale — about $101.9B3.

• Geothermal in Kenya. A decades-long geothermal development pipeline reached financial close in 2023, producing a record single-year investment figure of $3.2B (the largest single-year geothermal investment figure in Africa’s history) — spread across multiple projects, like Menegai.

Absent those three drivers, the private investment picture across the remaining 48 African countries is roughly flat over the same five years.

Interestingly

3: DFI 1/3 decline

In the same decade that annual private investment in Africa’s clean energy has tripled, over $40B, annual DFI/public financing has fallen by about one-third from a peak of around $28–30B in 2014/2015 to around $20B today.

This is largely due to a steep 85%+ withdrawal from Africa of Chinese DFI financing to just under $2B. China has not filled that gap with alternative capital. And no one else has either. The danger is that no credible commitment exists to fill it.

4: Risk: concentration

This is where the actual data tells a starker story than the hypothetical one above ($60B shared equally among 54 African countries). Most clean energy investments went to 10 or less countries, leaving the majority 44+ behind.

4.1: Destination concentration

Over 50% of Africa's combined public+private clean energy investment (over $30B/yr) flows into just 4 countries: South Africa, Egypt, Morocco, and Kenya.

4.1.1: Private concentration

Only 3 countries account for over 54% of all private investment in Africa’s clean energy: South Africa, Egypt, Nigeria. Top 10 countries (those 3 included) account for about 78%, while the rest 44 countries share only 22% ($8.8). One country, South Africa, receives more private capital ($10.5B) than the bottom 44 countries combined ($8.8B).

The implication of this concentration is stark.

Why this is the case:

4.1.2: DFI/public concentration

Only 3 countries account for over 52% of all DFI/public financing in Africa’s clean energy: Egypt, South Africa, Morocco. Top 10 countries (those 3 included) account for about 74%, while the rest 44 countries share only 22% ($4.3). One country, South Africa, receives almost equal financing ($4B) to the bottom 44 countries combined ($4.3B).

4.2: Source concentration

4.2.1: 40%+

Most of the flowing into African clean energy comes from the European private sector at 28%. Gulf (13%), China (12%), the US (9%), Africa (6%), India (2%) account for much smaller percentages.4

Sourcing more than 40% from one region (Europe) is a concentration risk for Africa. The risk is not European intent; it is African exposure. A clean energy investment portfolio 40%+ dependent on a single source facing domestic fiscal pressure, political will erosion, and competing strategic priorities is a portfolio with concentration risk that no institutional investor would accept in any other context.

4.2.2: African capital — constrained

Pension fund regulation reform needed. Africa’s institutional capital in most African countries, with the exception of South Africa, is structurally constrained and unable to invest substantively in Africa’s clean energy as most of their capital is tied by regulators to government securities (pension fund regulators often require about 50% to 80% of assets to be held in government securities), a prudential framework that was designed for a past era and needs reform.

4.2.3: Euro DFI concentration

The World Bank/IFC account for most (28%) of DFI $$ flowing into Africa. The AfDB follows at 18%, and EIB Global at 16%. Most other DFIs are European (again, European concentration).5

Energy diplomacy opportunities: AfDB, NDB, Gulf

Africa’s energy diplomacy can diversify by focusing on:

• Stretching the AfDB’s share, and stretching the AfDB to serve countries that actually need DFI $$ — see above analysis on destination concentration.

• Getting NDB $$ into more and strategic African countries on “beyond-energy” projects (clean energy projects that lead to bigger plays — like industrial plays)

• Attracting more Gulf funds into countries beyond North Africa.

If $$ from the AfDB, the NDB (BRICS), and IsDB+ADFD (Gulf) are each stretched by at least 10% in the next 5 years through aggressive energy diplomacy, then African countries will enjoy more optionality, less concentration.

5: Danger: Stark inequality

When 1 country gets almost as much clean energy financing as 44 countries combined, energy transition will happen mostly in 1 country and distort the data of 54 countries. When over 50% goes to countries with almost universal energy access at the expense of those with deep energy poverty, 3 things will happen:

• The DFI mandate will fail. When the granular data, not the headlines, become clearer, questions will arise as to whether DFIs actually addressed energy poverty.

• Private capital will be constrained to overcrowded markets, missing potential Alpha in so-called “secondary” and “less privileged” markets.

• “African clean energy success” will happen in only a few countries, constraining opportunities in 5+ countries, constraining opportunities in 49+.

5 insights

1. The capital is not missing. The architecture is wrong.

Africa’s clean energy problem is frequently framed as a capital shortage. It isn’t. Private clean energy investment on the continent has tripled in five years, from $17B in 2019 to nearly $40B in 2024. Gulf sovereign entities have quietly deployed over $100B into African clean energy since 2010, mostly as equity, mostly without the concessional scaffolding Western DFIs insist is necessary before private capital can move. The capital exists and it is moving.

What is failing is the system designed to route it where it’s most needed. Countries with near-universal electricity access, like Egypt, attract 50 times more international renewable investment per capita than countries where most people have no electricity at all, like Sudan. That is not a market imperfection at the margins. That is the architecture failing at its most basic purpose.

The question worth asking, for DFIs, for allocators, for anyone deploying concessional capital in Africa right now, is why so much of what already exists is flowing to markets that have already benefitted from it, while the markets that do need it get the residual.

More finance is definitely needed, but more in the same distribution will not cure Africa’s energy poverty or unlock opportunities for private capital.

2. The DFI mobilisation ratio tells what’s wrong with the system.

Development finance institutions defend their presence in South Africa and Egypt partly on the grounds that their capital catalyses private investment. The data makes that argument harder to sustain than it used to be.

Between 2016 and 2022, every $ of DFI energy finance mobilised approximately 33 cents of private capital. To meet Africa’s energy access goals by 2035, that ratio needs to reach seven $ of private capital per one $ of public. That is a 20-fold improvement on current performance, and it will not happen by doing more of the same.

The reason the ratio is so low is not a lack of commitment. It is a structural problem. DFIs are predominantly acting as senior lenders, sitting at par in the capital stack as commercial banks, in markets where commercial banks are already willing to lend without concessional support. In South Africa’s renewable auctions, European IPPs, Gulf equity, and domestic commercial banks all compete actively for deals where DFIs also participate as senior co-lenders. The private wascomingregardless.Theconcessional did not move it.

Repositioning DFI capital into first-loss positions, subordinated equity, and guarantees in less privileged markets, the instruments that genuinely change the risk-return calculus for private capital, is what moves the mobilisation ratio. It is also, not coincidentally, what the markets that need it most are asking for and not getting.

3. Policy has outperformed finance as a catalyst. We are not drawing the right lesson.

The two largest mobilisation events in African renewable energy in the last five years were not produced by blended finance. They were produced by governments changing rules.

South Africa removed generator licensing thresholds in January 2023 and introduced a business solar tax incentive in March 2023. Within a year, small-scale solar investment had grown fivefold, contributing over $6B to the market, with no concessional finance involved. Nigeria removed fuel subsidies in 2023, made diesel generation uncompetitive overnight, and triggered a private solar boom across West Africa’s largest economy. Both interventions cost governments nothing in capital terms. Both unlocked billions within months.

More than 40% of African countries still have unproven renewable energy auction or tender programmes. That single gap, the absence of a structured procurement framework with a creditworthy offtaker, explains more of the investment shortfall than any capital constraint. The World Bank aggregated four West African countries into a single competitive solar tender and cut costs by over 70%. That result has not been replicated at scale.

The most leveraged use of upstream public capital in Africa right now is not project-level co-financing in established markets. It is building the policy and regulatory conditions — auction frameworks, PPA templates, grid connection rules — under which private capital moves without needing to be subsidised into every individual transaction.

4. The risk premium is not reflecting the actual risk. That difference has a price, and ordinary people are paying it.

A solar project in Senegal with a structured PPA, a proven contractor, and an IFC partial guarantee is priced at 12 to 15 percent cost of debt. The same project in Spain costs 4 to 6 percent. That gap, 300 to 400 basis points, is not primarily a function of what is happening inside the project. It is a function of sovereign credit ratings being applied as a proxy for project risk in the absence of better data.

Actual default rates on African renewable energy projects, where they have been recorded, are materially lower than what the sovereign premium implies. The problem is that the dataset is thin, inconsistently published, and not systematically used by the institutional investors whose credit committees rely on rating agency signals because nothing more granular is available.

The result is a loop that sustains itself. High perceived risk keeps the cost of capital elevated. Elevated cost of capital raises the electricity tariff. Higher tariffs either kill projects or price electricity out of reach for the households that need it most. Fewer projects generate less performance data. Less data keeps the perception intact.

The entry point for breaking that loop is not a structural reform programme. It is a rigorous, regularly updated, publicly accessible dataset of project-level performance across secondary African markets: construction completion rates, PPA payment histories, actual default rates — that gives allocator committees something real to price against, rather than a sovereign rating that was never designed to answer the question being asked of it. That dataset does not exist in consolidated form. Its absence is not incidental to the problem. It is the problem.

5. For the first time, African governments have genuine alternatives. Most are not fully using them.

For most of the last three decades, the terms on which development finance reached Africa were largely set by the providers. Western MDBs and bilateral DFIs determined the conditionality, the instruments, the currency, and the timeline. African governments negotiated within those terms because there were few credible alternatives.

That is no longer the situation. Gulf sovereign developers are deploying equity at world-record low electricity costs, with no conditionality, no fossil fuel exclusions, and faster execution than any Western DFI can match. China’s retreat from infrastructure lending has been partially replaced by a green pivot, Chinese companies agreed to participate in over 20 GW of African solar projects between 2021 and 2024. The EU’s Global Gateway and the JETPs are now explicitly motivated by supply chain security and geopolitical positioning, not purely development logic. Capital is competing for African renewable energy in a way it simply was not a decade ago.

This has created something that did not previously exist: a seller’s market in African development finance, at least in bankable markets. Governments running explicit multi-alignment strategies, borrowing from the NDB, accepting Gulf equity, negotiating JETP terms with Western partners, and using each to improve the conditions of the others, are extracting meaningfully better financing terms than those engaging with a single source.

For DFIs, the strategic implication is clear. The comparative advantage of Western concessional capital is now concentrated in the frontier markets that Gulf and Chinese capital will not enter — fragile states, post-conflict re-entry markets, LDC mini-grid programmes, small island aggregation vehicles. Deploying it in markets that Gulf equity already serves is not just inefficient. It is a misallocation of whatever development finance leverage remains. For African governments and their advisors, the competition between blocs has produced more negotiating power than is currently being used. The countries that understand this are getting better deals. The countries that don’t are not.

Beyond Menengai

This memo on Menengai is not about Menengai. Neither is it about geothermal, even though it is about geothermal. The Menengai projects are a masterclass in derisking renewable energy projects which are traditionally state-dominated and high risk. They are also reflective of how innovative structuring can overcome stacked risks in renewable energy in Africa (African markets are very nuanced). These Kenyan geothermal projects (“Menengai”) leveraged public finance to mobilize private finance to the ratio of 1:2+, rare for this class of projects.

The Menengai model is a breakthrough. Due to its success, the model has birthed the Kenya National Geothermal Strategy, 2026–2036. This means that the model will be replicated across a number of geothermal projects. We expect that the stacking / model will be used across other investments – solar, wind, hydro, further creating billions of dollars of investment opportunities in Kenya ($600B opportunity over the next 24 years – according to the Kenya Energy Transition & Investment Plan) and in other countries – due to the replicating nature of African markets.

Risk Context

5 endemic risks have curtailed geothermal (and other renewable) investments in Africa for decades:

Drilling risk. You can spend $5M per well with a high probability of finding nothing. Commercial lenders almost never touch this phase, and private equity demands astronomical returns to cover it.

Offtaker risk & liquidity risk. Even if the plant works, the sole buyer (KPLC) is often perceived as fiscally fragile. Investors fear “payment delays” that could trigger a debt default on their own project loans.

FX risk. Energy is sold in local currency (KES), but the debt is often in USD. A 10% currency slide can wipe out an investor’s entire equity return overnight.

Political risk. A new administration might decide the feed-in tariff was too high or try to renegotiate the 25-year contract.

High cost of capital. African projects are often hit with a 300–500 basis point “Africa premium” just for being on the continent.

Menengai solution

The Menengai model has addressed the 5 endemic risks by stacking various derisking instruments & mechanisms as follows:

Drilling risk. The state-owned Geothermal Development Company (GDC) absorbed the exploration risk using concessional funding from the African Development Bank (AfDB). Private IPPs like Globeleq were engaged once the steam was proven. This effectively flips geothermal from a speculative “mining” bet into a standard infra project.

Offtaker risk & liquidity / FX risk. The Regional Liquidity Support Facility (RLSF) provided by ATIDI is a revolving standby letter of credit that acts as a 6-month cash buffer. If KPLC hits a cash-flow crunch, the project draws from the RLSF to stay current on its debt.

Political risk. By securing Breach of Contract (BOC) coverage from MIGA, a local contractual dispute is elevated into a World Bank-level event. It puts the risk of default on a global balance sheet, making it incredibly painful for any local government to walk away from its obligations.

High cost of capital. By blending commercial debt with low-interest loans from the Clean Technology Fund (CTF), the overall WACC is dragged down. This allows the project to sell power at competitive baseload tariffs (around $0.07/kWh), making it both politically and economically defensible against cheaper, dirtier alternatives.

Leverage stacking

By using roughly $145 million in public/concessional finance to de-risk the “unbankable” parts of the project, the Kenyan government + AfDB unlocked over $300 million in private investment and commercial debt for the three IPPs: Globeleq, Sosian, and OrPower 22. The public-to-private finance mobilization ratio was about 1:2, a very high ratio globally. Here’s the rest of the stack and what it unlocked.

Risk implication

This stacking model turns geothermal projects from state-controlled to private participation while mitigating risks for both the sovereign and investors. Specifically, it has changed geothermal projects from mining traps – risky, monolithic, slow business – to a modularized model with multiple revenue streams.

For decades, state utilities like KenGen carried the entire chain—from the high-stakes “mining” risk of drilling $5 million dry holes to the massive capital expense of building the plants. This vertically integrated approach meant that projects only moved at the pace of the national budget or when a major multilateral provided a sovereign guarantee. Private investors largely stayed on the sidelines, held back by geological uncertainty and the “all-or-nothing” nature of early steam exploration.

The structural shift at Menengai changed the business by unbundling these risks into a horizontal market. By having the Geothermal Development Company (GDC) absorb the upstream exploration risk using concessional funding, Kenya effectively mitigated risk for the private sector. Instead of a speculative bet, an IPP like Globeleq now enters a plug-and-play field where the steam is already proven. This modular approach, separating steam supply from power generation, allows multiple private players to build simultaneously, dragging down the cost of capital and turning geothermal into a bankable, institutional-grade asset class.

Replicability implication

This stacking model turns geothermal projects from state-controlled to private participation while mitigating risks for both the sovereign and investors. Specifically, it has changed geothermal projects from mining traps – risky, monolithic, slow business – to a modularized model with multiple revenue streams. We know that variations of this model will be replicated across different projects in geothermal, wind, solar, hydro – in Kenya and in other countries across Africa. Therefore Mennengai, or its model, is in this sense a breakthrough, providing a risk allocation structure that can inspire countries in Africa to turn “risky” projects into asset classes, opening billions in investment opportunities in renewable energy projects across Africa.

Utility risk

Offtaker risk is one of the heaviest contributors to renewable energy investment risk (and therefore cost of capital) in Africa, weighting at over 30%. Many utility companies in Africa are considered high risk. For decades, state utility companies have been the default offtaker, making investment in renewable power risky. Emerging models have ‘created’ a different offtaker — private businesses — changing the math.

Notable occurrence

In February 2026, IPP SolarAfrica reached a $94 million financial close to build SunCentral 2, a 114 MW solar farm project in the Northern Cape. This followed the late 2024 financial close of SunCentral 1. This is part of the over 3GW solar power that SolarAfrica will wheel to private buyers — mining companies, data centres, and manufacturing companies.

What’s changed

Under the traditional B2G model, this project would have been unbankable due to the utility company’s (Eskom’s) negative solvency — or it would have attracted very high interest rates making SunCentral power expensive. SunCentral’s B2B model has shifted credit risk to a different offtaker — private buyers — and therefore creditworthiness is based on the private buyers’ financials, significantly reducing interest rates and making the project overall more bankable.

In this B2B model, the financial structure has changed. Because the risk is lower (due to diversified private offtakers), the Cost of Capital has stabilized. Investors are accepting slightly lower yields in exchange for “utility-like” stability without the “utility-like” default risk.

• Standard Tariffs: B2B wheeling now offers electricity at rates up to 50% cheaper than standard utility (Eskom) tariffs.

• Infrastructure Investment: A significant portion of the SunCentral funding is being used to build private transmission substations (MTS), allowing the private sector to physically take over the job of grid expansion where the state has stalled.

Emerging trend

Other African countries are adopting the B2B model — out of necessity — at different maturity levels. While South Africa is the largest market due to the sheer scale of its industrial energy deficit, several other African nations have hit a “regulatory tipping point” in 2025 and early 2026. These countries are moving away from the Single Buyer Model (where everyone must sell to the state utility) toward an Open Access or Modified Single Buyer (MSB) framework.

Investor implication

The B2B wheeling model essentially swaps the shaky credit of state utilities for the balance sheets of blue-chip firms. These firms can’t afford abandoning their power deals, which turns a "high-risk" African energy play into a stable, infrastructure-grade investment. Investors no longer bet on a utility’s ability to pay; but on the fact that the buyer needs power to run their business. With secondary markets already heating up and the cost of capital dropping as a result, the "utility risk" that used to kill these deals is finally being priced out of the equation.

These models are expected to spread all over Africa, and larger deals are expected to be made in already practising countries, which creates a multi-billion dollar opportunity for investors in Africa in the next decade.

Fossil risk

Over the last decade, there has been a remarkable shift in energy investments in Africa: Major capital withdrawing from Africa’s fossil fuel projects, while more capital is entering the renewable energy scene in Africa.

Major capital is withdrawing from fossil fuels in Africa for various risk-related reasons, such as the cost of capital (due to increased litigation exposure) — currently costs 3x to 4x what it costs in Europe to invest in Africa; risk of stranded assets, and infrastructure gap.

Below are a few examples that signal this systematic withdrawal.

Withdrawal timeline

The table below shows the changes major capital has been making that is growing the fossil capital drought.

As 2026 progresses, major cuts will be made towards Africa’s fossil projects due to the stranded asset risk.

The decline

Fossil fuel investments in Africa have more than halved in the last decade, with a plateau since 2022. It is not expected that major capital will return and turn up the graph due to increased systemic risks to fossil investments (see above). One notable risk is that fossil litigation is becoming more structural, and expected to balloon in key African countries like South Africa and Kenya moving forward.

Alternative investment?

Just a decade ago, investment in fossil fuels was ~10x investment in renewables in Africa. Today, fossils and renewables are at par in investments. And given increased (1) global focus on renewable energy, (2) global policy (3) the economic competitiveness of renewables, (4) country policy shifts towards renewables, and (5) risks associated with fossil investments; renewable energy investments in Africa are likely to surpass fossil fuel investments, which are projected to decline further.

Risk competitiveness

Increasingly, investors in the African energy market are comparing the risks and economics of fossil fuel vs. renewable energy projects. Data shows how risk is shifting: Renewable energy projects are increasingly becoming more competitive in Africa.

Summary

What’s happening: Africa’s highest-ever solar panel imports shows that (1) Africa’s power demand is growing faster than grids and utility power, (2) consumer solar confidence is outpacing institutional capital, and (3) structurally, risk is shifting to the end consumer.

Parallel opportunity: Paradoxically, two opportunities for RE investors: (1) aggregate, finance, and integrate these systems; and (2) invest to accelerate grid & utility pace

Why now: Where solar imports surge without parallel grid, financing, and regulatory reform, institutional capital is lagging reality; and future entry costs are rising.

Solar surge

Africa recorded its highest-ever year of solar panel imports in 2025, driven largely by rooftop systems, commercial installations, and off-grid and hybrid setups across East, West, and Southern Africa – according to the Global Solar Council.

On the surface, this looks like a simple climate success story. In reality, it is a deeper signal about how Africa’s energy transition is currently being financed, and where risk is shifting to.

This surge in imports reflects demand that has moved faster than utilities, regulators, and institutional capital. Households, SMEs, telecom towers, farms, and industrial users are increasingly choosing to self-provision power rather than wait for grid expansion, utility reform, or large-scale IPP projects to materialise. In effect, energy risk is increasingly being privately absorbed.

Risk shift

Instead of being carried by public balance sheets, sovereign guarantees, or structured finance vehicles, risk is now shifting to end users in the form of upfront capital costs, performance uncertainty, maintenance obligations, and currency exposure. This is a quiet but important shift in Africa’s energy landscape.

Investor implications

For investors, this carries two contrasting implications.

It sharply reduces technology risk in Africa. High import volumes indicate that solar equipment, installation capacity, and supply chains are now widely trusted. The question of whether solar “works” in African conditions has largely been answered by the market itself.

It exposes unresolved system risk. When consumers bypass utilities at scale, it signals limited confidence in grid reliability, offtake stability, and formal financing structures. Solar is proven. Power systems are not. This immediately reads like a system risk, but for discerning investors it is a system opportunity – investing in grids to catch up to high, growing demand.

Parallel opportunity

The result is a parallel energy economy: decentralised, fragmented, and growing quickly outside traditional infrastructure channels. This creates a paradox that investors should pay attention to.

Africa’s solar market is expanding fastest in environments where institutional capital remains hesitant. Demand is being met, but inefficiently, through equipment traders, informal financiers, and balance sheets not suited to long-term infrastructure risk. Returns exist. They are simply being captured upstream and off-balance-sheet.

Risk: This represents a reallocation rather than a reduction of uncertainty.

Opportunity: Record imports indicate bankable demand without bankable structures. There is a growing base of decentralised assets that lack standardisation, long-term finance, and scalable platforms. Investors able to aggregate, finance, and integrate these systems stand to enter a market that has already been validated by users.

The deeper message is this: Africa’s energy transition is advancing without waiting for institutional capital.

Where solar imports surge without parallel grid, financing, and regulatory reform, institutional capital is lagging reality; and future entry costs are rising.

And it suggests that the next phase of Africa’s renewable non-utility market will be defined less by technology adoption and more by who succeeds in re-intermediating a fast-growing, decentralised energy economy into bankable infrastructure.

Risk context: Transmission, risky

Two key risks have disincentivized investment in transmission in Africa for decades: The grid is largely state owned, and sovereign debt levels are high. Yet, at the same time, grid reform is too expensive for governments without external funding. This tension has stalled or slowed grid reform in many African countries for decades, leading to stranded renewable energy generation.

What’s changed: Transmission moves from risky state project to investment opportunity

A recent $311 million PPP deal between KETRACO, Africa50, and PowerGrid of India enables the State to hive the transmission project off its balance sheet, maintaining its sovereign debt level, while mitigating the investors’ exposure to sovereign debt limits. Similar models are emerging in South Africa and Nigeria, and expected to be replicated across Africa.

How it works

The deal runs on a 30-year build-own-operate-transfer (BOOT) concession which enables the developer to own and operate the transmission line being financed, and the state simply pays for its use.

• The Special Purpose Vehicle (SPV): Africa50 and PowerGrid of India (the technical partner) lead the development through an independent entity

• Privately financed: They raise the capital, meaning the asset cost does not sit on Kenya’s national books as debt

• Risk allocation: The private sector takes on the construction and operational risk, while Kenya pays for the service of transmitted power over time, rather than the asset upfront

Status: Capital mobilization

The main agreement was signed in December, 2025. The parties are now securing $34 billion from commercial banks. Groundbreaking expected in August, 2026.

Investor relevance: Sovereign debt risk mitigation, billion-dollar pipelines, emerging asset class across Africa

The success of this model will unlock a much larger $5 billion pipeline KETRACO needs over the next 20 years to build 8,000km of new lines. By proving the $311M ‘pilot’ is bankable, Kenya is essentially creating a standardized asset class, and a template across Africa, that large funds can eventually buy into – similar models are emerging in South Africa and Nigeria, and expected to be replicated across Africa.

Executive snapshot

Over November–December 2026, energy reform activity across Africa continued to shift away from generation policy and toward the harder parts of the system: grid capacity, transmission planning, and financing structures. In several markets, renewable generation is no longer the binding constraint. Execution, particularly around infrastructure and capital mobilisation, now defines risk. Therefore the emerging frontier in renewable energy infrastructure investment is transmission & grid infrastructure.

A quiet but important transition emerges: policy permission is largely in place, but system readiness is uneven – both a constraint and an opportunity.

Key reform signals

South Africa

• Transmission reform remains the centre of gravity

• The unbundling of Eskom and the operationalisation of the National Transmission Company (NTCSA) continue

• But grid congestion, especially in renewable-rich regions, remains acute. The legal architecture is now clear; delivery speed is the open question.

Nigeria

• Subnational power regulation under the Electricity Act is beginning to shape reform dynamics

• Following the Electricity Act 2023, states such as Lagos are now licensing and overseeing distributed and embedded renewable projects directly, shortening approval timelines and reducing exposure to federal regulatory bottlenecks

• This shifts renewable-energy risk in Nigeria from national policy uncertainty to state-level execution capacity, allowing investors to treat strong states as distinct, investable power markets rather than as part of a single federal risk profile

Senegal

• Attention has moved from policy frameworks to financing

• The Renewable Energy & Energy Efficiency Fund (REEF) has shifted the conversation toward blended finance and capital structuring, with investors watching closely for evidence of deployment and governance clarity

Kenya

• High renewable penetration has sharpened focus on grid stability, storage, and transmission upgrades

• Infrastructure readiness is emerging as the dominant constraint and therefore investment opportunity.

Zambia

• Reform discussions continue to centre on transmission rehabilitation and utility viability

• Generation frameworks are largely established; system resilience and balance-sheet repair now dominate risk assessments.

Risk trend to watch

Across these markets, reform is no longer about allowing renewables; it is about absorbing them. The core risk has migrated downstream, from policy uncertainty to infrastructure and financing execution. Investors relying on older risk narratives that treat generation policy as the primary hurdle may be misreading where friction now sits.

Where capital may move

• Transmission and grid infrastructure are emerging as system-critical investment needs, particularly in South Africa and Kenya

• Blended and catalytic finance vehicles are becoming more central to project viability, as seen in Senegal

• Distributed and subnational energy models are gaining relevance where central systems remain constrained, notably in Nigeria

These are conditional opportunities, dependent on execution, governance, and clarity on cost recovery.

What to Watch Next (Q1, 2027)

• Evidence of grid-expansion financing translating into physical delivery

• First disbursements and deal flow under new financing vehicles

• Subnational regulatory decisions affecting renewable projects

• Court or regulatory actions that materially affect fossil or grid-related assets

Methodology note: AERS tracks regulatory, legal, and institutional developments that materially affect energy investment risk across African markets. Signals focus on direction and structure, not deal promotion.

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Precedent

The UK’s and Netherlands’ withdrawal of over $2Bn from a Total-led LNG project in Mozambique sets a precedence that countries / financiers could withdraw or withhold up to billions from a project that violates their public image of decency.

The convergence of these two factors might lead to more financiers following the precedent:

• The extractive nature of fossil fuel projects has heightened public scrutiny and legal action.

• At the same time, countries and financiers are actively protecting their reputational and geopolitical stances.

What this would mean for investors

• Higher cost of capital: Reputational risk is likely to raise a project’s risk premiums.

• Project delays: Withdrawals / protracted financing processes will cause project delays.

• Possible project halts: Significant capital withdrawal could risk projects.

Signs of impending risk

• Once scrutiny begins, investigations and bad PR kick in.

• Communities how have greater access to litigation - which is increasingly becoming constitutional and structural (as stated in our signal here)

• Which is increasingly getting out of investors / financiers’ / project owners’ control

IPPs have historically been considered high-risk, accessing private financing only at a premium, making investments unattractive. REEF is projected to be a $200M+ first loss fund to de-risk IPPs in Senegal, enhancing their access to lower cost finance. The table below has what investors need to know.

Courts have become more progressive.

Across Africa, courts are stepping into a new, more assertive role — something you can clearly see in the landmark cases of the past few years. In South Africa, the Thabametsi judgment (2017) forced regulators to consider climate impacts before approving a coal plant. In Kenya, the courts went even further: the Lamu Coal Plant judgment (2019 & 2021) didn’t just question the environmental impact assessment — it challenged the entire approval process as incompatible with constitutional environmental rights. And in Nigeria, the revival of Gbemre v. Shell reaffirmed that gas flaring violates fundamental rights.

Beyond these three heavyweights, the trend is spreading. Uganda’s High Court has pressed for transparency in oil licensing, Zambia’s courts are tightening oversight of mining pollution, and Senegal’s administrative courts are scrutinising offshore gas EIAs more seriously. Ten years ago, these kinds of rulings would have been outliers. Now they’re becoming the norm.

Fossil litigation has become increasingly constitutional and structural.

What used to be procedural fights over EIA paperwork are now constitutional battles about rights, justice, and the state’s duty to protect people. South Africa’s Deadly Air judgment (2022) declared that Mpumalanga’s air pollution violates constitutional rights — a decision with massive implications for coal-heavy regions. Kenya regularly treats environmental disputes as constitutional questions under Articles 42 and 70, which is how the Lamu case was able to reach such sweeping conclusions.

Elsewhere, Uganda’s EACOP challenges are grounded almost entirely in rights to life, health, and property. Ghanaian courts have seen petitions attacking mining pollution via constitutional provisions. Senegal’s coastal communities are now framing offshore gas issues around socioeconomic rights tied to fisheries. Once a fossil project enters constitutional terrain, it becomes a long-term structural risk — not a technical compliance matter.

Communities have become more aware and better equipped.

This shift in litigation isn’t happening in a vacuum — communities themselves are becoming more organised and better supported. The EACOP coalition is the prime example: Ugandan and Tanzanian groups coordinating across borders, filing multiple cases, and engaging international mechanisms. In Kenya, the Lamu petitioners brought technical experts, heritage specialists, and climate evidence — something unheard of in Kenyan environmental litigation 15 years ago.

The pattern repeats elsewhere. Senegal’s fishing communities, backed by NGOs, are challenging offshore gas projects. Zambian communities affected by mining are increasingly turning to the courts to enforce environmental licence conditions. People now understand both their rights and the legal pathways available to defend them — and that makes litigation far more potent.

Liabilities on fossil projects are widening.

The legal risks fossil developers face today are no longer one-dimensional. In Kenya’s Lamu case, liability extended to cultural heritage, pollution risk, and climate impacts. South Africa’s Deadly Air ruling opened a new front: state liability for failing to address harmful air quality. Nigeria’s gas-flaring cases, including Gbemre and more recent Niger Delta judgments, add human-rights liability on top of environmental compliance.

Across the continent, courts are widening the perimeter of what counts as harm. Ghana’s water pollution disputes tie mining impacts to constitutional duties. Ugandan oil cases raise questions about long-term displacement and community protection. Senegal’s offshore gas disputes revolve around livelihoods, marine ecosystems, and economic rights. The result? Fossil projects now face a broader risk landscape than at any point in Africa’s legal history.

Courts are borrowing from each other.

One of the most fascinating trends is how quickly ideas now travel across jurisdictions. Kenyan judges frequently cite South Africa’s climate jurisprudence, including Thabametsi. Ugandan litigants explicitly reference Kenyan participation and rights cases in EACOP filings. Even Nigerian judgments have noted comparative reasoning from East Africa when addressing environmental rights.

This cross-referencing isn’t limited to the big three. Ghanaian scholars draw on South African precedent in mining rights cases. Senegal’s administrative courts increasingly rely on rights-based interpretations that echo East African decisions. Once a principle succeeds in Nairobi or Pretoria, it can appear in Kampala or Accra within months. Fossil investors can no longer assume a ruling is “contained” within one country — legal risk now moves across borders.

Regulations and courts are increasingly becoming self-reinforcing.

Recent energy and environmental reforms across the continent are giving courts stronger legal frameworks — and courts, in turn, are pushing regulators to enforce them properly. In South Africa, the removal of licensing caps for embedded generation (2021–2022) has strengthened the legal basis for private renewables, and courts have reinforced transparency requirements for major energy decisions.

Kenya’s climate law, updated grid codes, and public participation rules give judges clear standards to enforce — as seen in the Lamu rulings. Nigeria’s Electricity Act 2023 empowers state-level regulation and gives courts a clearer handle on rights and responsibilities in the energy sector. In Senegal, new renewable energy laws have led courts to scrutinise fossil EIAs more seriously. Zambia’s mining and environmental reforms have also enabled firmer judicial oversight.

It’s a loop: reforms empower courts; courts reinforce reforms — and both jointly tilt the landscape toward renewables.

Nigeria’s Electricity Act 2023 didn’t make headlines in the way it deserved — but for anyone building or financing renewable energy, it is one of the most meaningful structural reforms in Africa in recent years.

For the first time, the sector is no longer locked inside a single, centralised federal bottleneck.

States can now create their own electricity markets, issue licences, set tariffs, run tenders, regulate distribution, and approve renewable energy projects within their borders.

The Act effectively replaces “one entry door into Nigeria’s power sector” with 36 potential entry doors — each depending on the capacity, competence, and urgency of individual state governments.

What changed — in practical terms

The Electricity Act creates several new rights and pathways that directly affect renewable energy developers and investors. In plain language:

1. Investors can now get licences directly from states — not only from Abuja.

This bypasses years of regulatory bottlenecks and helps projects move faster.

2. Investors can now build and operate intrastate renewable projects with state-level approval.

Solar, wind, hybrid, mini-grid, and embedded generation projects can be licensed locally.

3. Investors can now work with states to set cost-reflective tariffs.

States can approve tariffs independently, which improves bankability.

4. Investors have clearer legal protection for mini-grids and embedded generation.

This is crucial in Africa’s largest mini-grid market.

5. Investors can now compete in DisCo territories through franchising and sub-franchising.

This breaks the old monopoly structure and allows private players to legally serve underserved areas.

6. Investors can legally build private solar, hybrid, and cluster-based distribution systems.

Industrial parks, new towns, estates, universities, commercial districts — all now have lawful pathways.

7. The boundary between federal and state regulators is clearer.

Disputes, licensing questions, and interconnection issues now have defined processes.

8. Investors can now enter state electricity markets run by new state regulators.

Some states (Lagos, Kaduna, Edo, Enugu) have already passed their own electricity laws.

9. Investors can participate in state-led energy tenders and procurement rounds.

States can now run their own renewable procurement programmes.

10. Off-grid developers now operate under more predictable rules.

Mini-grids and C&I developers get stronger regulatory certainty.

Why this matters for investors

Nigeria is still a complex market — none of these reforms erase that.

But the Electricity Act 2023 fundamentally changes where the opportunities are and who controls them.

The most important shift is this:

Nigeria is no longer a single market.

It is becoming 36 different electricity markets moving at different speeds.

• Fast-moving states will attract capital quickly.

• Slow states will continue struggling.

• Developers now have strategic choice — which state to engage, which regulator to work with, and which licensing route to pursue.

This introduces competition between states, improves responsiveness, and reduces the historical reliance on federal bottlenecks that slowed down renewable energy projects for years.

In short:

The risk profile isn’t magically low — but it is now more navigable, more flexible, and more open than anytime in the last two decades.

What to expect next

Over the coming weeks, we will break this master reform into individual, investor-focused signals, each covering one of the Act’s most important clauses:

• “Renewable energy investors can now get licences directly from states…”

• “Renewable energy investors can now develop mini-grids under clearer rules…”

• “Renewable energy investors can now compete in DisCo territories…”

• “Renewable energy investors can now build private solar or hybrid distribution systems…”

…and more.

Each one will explain the practical opportunities and risks inside this new legal landscape.

Why this timeline matters

Kenya has been making steady, almost quiet changes to its energy sector for years.

Individually, each reform looks small.

Together, they’ve shifted the country’s risk profile in a real way.

This timeline pulls the last five years into one place so investors, developers, and analysts can see:

• what changed,

• when it changed, and

• why it matters for investment decisions today.

No noise. No spin. Just the story.

2020 — The groundwork

1. Kenya Power starts modernising the grid

KPLC began a long-term programme to strengthen transmission lines, reduce losses, and improve reliability.

Why it matters: A more stable grid is the foundation for integrating more renewables.

2. EPRA starts reviewing old regulations

This was the year the regulator quietly opened up old rules—Grid Code, mini-grid frameworks, tariffs—for revision.

Why it matters: These reviews set the stage for the reforms that followed.

2021 — Early alignment

3. LCPDP 2021–2030 is released

This plan clearly shifts Kenya’s future generation toward wind, solar, geothermal—and away from expensive thermal.

Why it matters: Investors care about where future demand is heading. This plan made it obvious.

4. Mini-Grid Regulations come into force

For the first time, private mini-grids had proper rules: licensing tiers, standards, and interconnection procedures.

Why it matters: More certainty = more investment in distributed solar.

2022 — Cleaning up and rebalancing

5. Kenya starts renegotiating legacy PPAs

Government agencies began a coordinated push to clean up old, expensive PPAs.

Why it matters: A fairer, cleaner procurement environment benefits future IPPs.

6. KPLC opens the door to battery storage pilots

A sign that Kenya was ready to start planning for a grid that can handle more variable renewables.

Why it matters: Storage is key to unlocking large-scale solar and wind.

2023 — The rulebook starts to change

7. Energy Act 2019 finally gets full subsidiary regulations

Licensing rules, tariff guidelines, energy trading provisions—everything was clarified.

Why it matters: Sudden clarity reduces the “regulatory fog” developers often complain about.

8. New Distributed Generation and Net-Metering rules

These made life easier for C&I solar developers by clarifying interconnection standards.

Why it matters: Kenya’s C&I solar market is fast-growing, and this gave it structure.

9. Move toward standardized PPAs

Government pushed for simpler, uniform PPAs.

Why it matters: Standardization reduces negotiation risk and cuts lead times.

2024 — The big technical reset

10. The Grid Code gets a major update

This is one of the most important technical reforms in recent years.

It updated rules for solar, wind, hybrid systems, and storage—and cleaned up interconnection processes.

Why it matters: Developers get faster, clearer grid approvals.

11. EPRA speeds up licensing

A new digital system made approvals more predictable.

Why it matters: Delays are expensive. Predictability is a de-risker.

12. KETRACO opens its transmission lines for private access

For the first time, developers could apply transparently to use national transmission corridors.

Why it matters: Transmission access has long been one of Kenya’s biggest bottlenecks.

2025 — Opening the market

13. Energy Trading Regulations start rolling out

Early steps toward allowing power to move more freely—and toward an eventual open-access market.

Why it matters: This is a long-term structural shift. It creates room for more private generation.

14. New PPA Guidelines issued

The new guidelines are clearer, with better-defined risk allocation.

Why it matters: Bankability improves when rules are predictable.

15. Renewable energy auctions framework takes effect

Kenya begins moving toward competitive tenders for new utility-scale renewables.

Why it matters: Auctions reduce risk and increase transparency for developers.

Why this matters for investors

Across these five years, Kenya has quietly—steadily—become more investable.

Here’s the simple version:

• Licensing is clearer.

• Grid rules are updated for modern renewables.

• Procurement is more transparent.

• Transmission access is less opaque.

• And the market is inching toward more competition.

No single reform transformed the landscape on its own.

But together, they’ve shifted Kenya into a position where renewable developers face fewer unknowns, fewer delays, and fewer hidden risks.

For investors, that matters.

A lot.

On 16 October 2025, Kenya’s Environment and Land Court (Malindi) upheld the decision to revoke the environmental licence for the proposed 1,050 MW Lamu Coal Power Plant. The court found that the project’s Environmental & Social Impact Assessment (ESIA) was inadequate, that public participation fell short of constitutional standards, and that the approval process violated environmental rights under Articles 42 and 69 of the Kenyan Constitution.

The judgment, rooted in the Environment Management and Coordination Act (EMCA) and its EIA regulations, confirms a long-standing trend: coal projects in Kenya face high and rising legal and permitting risk, even when backed politically or included in past national energy plans.

Civil society reacted strongly.

“Justice for Lamu is justice for the planet. This ruling shows that when communities are heard, the law protects both people and nature.”
— Save Lamu

“This decision reinforces Kenya’s constitutional commitment to environmental justice, public participation, and the rule of law.”
— Natural Justice

With this ruling, the coal project is effectively halted indefinitely, and a legal precedent is reinforced: fossil projects must withstand intense judicial scrutiny, strong community oversight, and elevated environmental-rights litigation.

The Risk Matrix — Lamu Coal Case (Kenya)

A concise view of how the ruling raises fossil-project risk across key dimensions.

Investor takeaway:
Developers cannot rely on quick or stable approvals for fossil projects under Kenya’s environmental-rights framework.

Investor takeaway:
Litigation risk is structural and persistent. Courts are willing to suspend or cancel fossil projects regardless of political support.

Investor takeaway:
It is now more difficult for coal and similar projects to progress to construction or financing under current legal and societal conditions.

Overall signal

The Lamu coal ruling is a structural signal, not a one-off.

We expect that fossil projects will face stricter scrutiny, will be subject to more litigation, delays, and possible halts.

Read an expert legal opinion on the coal case here.

South Africa’s decision to remove generation-licensing requirements for private renewable projects—first lifting the threshold to 100 MW in 2021 and later broadening the exemption in 2023—remains one of the most transformative de-risking reforms in Africa’s energy sector.

Before the change, even modest embedded-generation projects required a full NERSA licence, a process widely criticised for long delays and unpredictable timelines. As energy expert Anton Eberhard noted, the old system was “a major blockage to investment in embedded generation,” while industry groups called its removal “a watershed moment” for private renewables. Legal analysts similarly described the reform as eliminating “one of the key regulatory hurdles” to large-scale renewable project development.

The exemption immediately unlocked a surge in private solar and wind investment. By 2023, more than 100 embedded and private-generation projects—totalling over 9 GW—were in the pipeline, including major programmes by Sasol, Air Liquide, Anglo American, ArcelorMittal South Africa, and leading mining and industrial firms. Corporate PPAs, previously constrained by licensing, now dominate new-build activity, making embedded generation the fastest-growing segment of South Africa’s power market.

Investor relevance: This reform continues to shape South Africa’s risk landscape today. It permanently lowered regulatory and timeline risk for private renewable generation, enabled corporate offtake markets at scale, and catalysed a multi-GW pipeline that is still accelerating.

Africa’s energy landscape is changing faster than global perception.

Reforms across the continent are making renewable energy safer to invest in, while court cases and regulatory actions are steadily increasing the risks facing fossil fuel projects. Yet these signals often remain invisible to the investors, policymakers, and institutions that depend on them to make decisions.

Africa Energy Risk Signals exists to change that.

We track and translate the reforms, rulings, policy shifts, and institutional behaviours that reshape energy-sector risk in Africa. Our focus is simple: where investment risk is falling, where it is rising, and what that means for Africa’s energy transition.

This project begins with five countries — Kenya, South Africa, Senegal, Nigeria, and Zambia — and will build both a historical archive and real-time monitoring system of the signals shaping their energy futures.

More soon.

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