Is a Single African Electricity Market Possible? Understanding Electricity Market Reforms in Africa

There are over 560 million Africans without access to electricity in Africa. Could more private sector participation and a flexible regulatory structure across the continent be the solution?

Editor’s note: This essay is available in our print issue, Pan-African Dreams. Buy the issue here.

The African Union (AU) officially launched the African Single Electricity Market (AFSEM) on 3 June 2021. AFSEM is expected to interconnect the five power pools that encompass the African continent by 2040, leading to the largest electricity market in the world. These pools include the Central African Power Pool (CAPP), Maghreb Electricity Committee (COMELEC), East African Power Pool (EAPP), Southern Africa Power Pool (SAPP) and the West African Power Pool (WAPP). This is important because while North Africa, which is mostly covered by COMELEC has a 99 per cent electrification rate, sub-Saharan Africa (SSA), which comprises about 48 countries, is at about 50 per cent. What this means is that almost 560 million people in SSA do not have access to electricity. The 20 least electrified nations in the world are also in SSA. In addition to low electrification rates in SSA, many people still experience unreliable power supply. For example, Nigeria, Niger, the Democratic Republic of Congo, Cameroon and Angola, experienced 191.7 days, 58.3 days, 34.6 days, 32.9 days and 31.7 days of power outages in 2018 respectively. 

According to the African Union the AFSEM is meant to, ‘achieve a fully integrated, competitive and harmonized electricity market in order to accelerate Africa’s development and improve access for the benefit of African citizens.’ Yet, it is not clear how these will be achieved. The amount of coordination between 55 member states of the African Union required to develop, finance and construct the generation, transmission and distribution infrastructure to achieve a fully integrated market in less than two decades is unprecedented in modern history. Africa’s installed generation capacity is about 286.7 GW. Compare this to China, the largest electricity market in the world, with an installed generation capacity of 2,564.05 Gigawatts (GW), serving about 1.4 billion people, as of 2022. To fully electrify its 1.3 billion people, AU member-states would have to install the energy infrastructure required to deliver over 2,380.9 GW to its citizens. While some scholars believe that the regional economic communities and geopolitical organizations—such as the Common Market for Eastern and Southern Africa (COMESA), the Economic Community of Central African States (ECCAS), The Economic Community of West African States (ECOWAS), the Southern Africa Development Community (SADC) and the Arab Maghreb Union (UMA)—will play an important role in achieving the AFSEM, it is not clear what that role will be. 

How then is the AFSEM going to be achieved? According to the AU, the power pools have a role to play in this. To be fair many of the member-states of the SSA power pools engage in bilateral trade of electricity. For example, Niger, Togo, Senegal and Benin are net importers of power from Nigeria, Ghana and Côte d’Ivoire. Tanzania is a net importer of electricity from Uganda and Zambia. Yet none of these countries has more than 90 per cent electrification and many of them suffer from inadequate capacity for their local populations. Hence, no comprehensive regional wholesale or retail electricity market has been developed on the continent. Regional markets go from the stage of simple market integration to deep market integration. Most of the power pools in Africa are still at an early stage of electricity market integration, where transactions are based on bilateral contracts. At the stage of deep market integration, the AFSEM would have a harmonization of market rules that will include an agreement on the currency of settlements and an independent continental systems operator with oversight of other regional systems operators, where various products will be sold, in energy, ancillary and capacity markets.  

It seems to be the case that for the AFSEM to be possible, each of Africa’s 55 countries needs to have a functional electricity market. These national markets can then translate into efficient regional power pools. Only when the regional power pools have reached the deep market integration can a fully functional AFSEM be possible. Hence, we cannot speak of an AFSEM without considering the electric power sector in AU member-states.


As of 2000, the energy access rate of SSA was 25.7 per cent. All countries in North Africa had an energy access rate of over 90 per cent, except Mauritania and Morocco, which were 19.1 per cent and 69.8 per cent respectively. At the turn of the 21st century, inadequate energy infrastructure was a major problem disproportionately affecting sub-Saharan Africa. Around this time, many SSA countries were served by state-owned vertically integrated utilities—vestiges of the colonial era—post-independence. These state-owned utilities experienced extensive problems, which include non-reflective cost tariffs by utilities to consumers, dilapidated and ageing infrastructure, bureaucratic inertia and political corruption. In addition, many of these state-owned utilities were government agencies and depended on the state treasury to cover their shortfalls. The political instability brought about by a series of military coup d’états and civil wars between the mid-1960s and 1980s, in addition to poor governance, monetary and fiscal policies, gave the continent a precarious economic foundation at the turn of the century. Between the 1980s and 1990s, many African countries had undergone some sort of Structural Adjustment Program and debt restructuring. This meant that the power sectors across Africa were also in dire straits and many of them suffered from severe liquidity crises. 

Hence, multilateral agencies such as the World Bank and International Monetary Fund (IMF) recommended market liberalization policies within the power sectors of many SSA countries. These policies were generally known as power sector reforms. In some cases, they were considered a prerequisite for any debt relief plan these countries were going to benefit from. While there was no strict set of rules for the implementation of electric power sector reforms, a general recommendation by the World Bank was to create an independent regulator to restructure the sector. This involved unbundling state-owned assets across the generation, transmission and distribution businesses of the value chain. It also involved introducing private sector participation (PSP) in the sector, and where possible, introducing wholesale and retail power markets. 

The effects of reforms in SSA have been mixed. As of 2021, the energy access rate in SSA is 50.6 per cent, yet disparities between various countries exist. For example, the energy access rates for South Sudan, Burundi and Chad are 7.7 per cent, 10.2 per cent and 11.3 per cent respectively, while Nigeria, Ghana and South Africa have energy access rates of 59.5 per cent, 86.3 per cent and 89.3 per cent respectively. In North Africa, only Libya and Mauritania have an energy access rate less than 90 per cent.  

Not all countries implemented electric power sector reforms and those that implemented reforms did so differently. For example, countries like Niger and Mauritania only established a regulator for their electric power sectors. Others like Botswana and Tanzania  introduced private sector participation in the generation business of the value chain; a few like Nigeria and Kenya unbundled their state-owned utilities into distribution, generation and transmission. Only 29 countries in Africa have some level of private participation in their electric power sectors, and just ten countries have restructured their sectors by unbundling state-owned utilities. The single buyer model is still the most common mode of reform implemented in Africa, where a single state-owned entity controls most of transmission and distribution but augments its generation capacity by procuring more from independent power producers. 

No SSA country has a wholesale or retail power market. In fact, wholesale power markets are exceptionally rare in developing countries. Those that exist are in India, Romania, the Philippines and Chile, among others. Retail power markets are virtually non-existent in developing countries. Part of the reasons for this includes the fact that power markets are complex and require not just liquidity and a backbone transmission infrastructure, which many African countries lack, but they also require strong institutions that can protect and enforce the property rights of investors and ensure technical performance for consumers. The AFSEM would have to overcome some of these issues to be a functioning power market.  

Since national and regional performance of the power sector is important for the realization of an integrated continental single market in Africa, discussing the current state of the regional power pools and their member-states is important. This way some of the problems the sector faces can be properly considered, and solutions can be proffered to the extent that they have been successful in other similar countries. 

The North African power pool is an association of five North African countries—Algeria, Libya, Mauritania, Morocco and Tunisia—adopted as a specialized agency of the UMA after its founding in 1989. All members of the COMELEC have a 100 per cent electrification rate except Mauritania and Libya. Mauritania with an energy access rate of 47.7 per cent has implemented no private sector participation (PSP) in its power sector, which is run by a single state-owned entity—Société Mauritanienne d’Electricité. Libya, which saw a steady decline in energy access from 98.6 per cent in 2001 to 70.2 per cent in 2021, has been mired with violent civil unrest and wars since 2011.  

Established in 2005, the EAPP is a specialized agency of COMESA. Its members include Burundi, Djibouti, DRC, Egypt, Ethiopia, Kenya, Rwanda, Sudan, South Sudan Tanzania and Uganda. While geopolitically considered to be a North African country, Egypt is a member of EAPP and not COMELEC. In EAPP, Egypt is the only country with 100 per cent electrification. Egypt, Kenya, Ethiopia, Uganda and Sudan are the only countries with unbundled utilities. Ethiopia, Sudan and Egypt still maintain government ownership and control of utilities. There is some degree of private sector participation in the generation business in most member-states, especially for renewable energy procurements, except for Burundi, South Sudan and Sudan. The DRC presents a unique situation because, while there is no national grid (the DRC has three regional grids managed by the state-owned utility), there are many mini-grid utilities operated by faith-based institutions and private entities. This is, in part, due to the DRC’s many years of civil unrest. Kenya and Uganda have been the most aggressive in electric power sector reforms in the EAPP. They have introduced some type of private ownership and control in transmission and distribution utilities. Trade between various EAPP member-states is common. For example, Djibouti purchases over 60 per cent of its electricity from Ethiopia. Tanzania is also a net importer of electricity from Uganda and Zambia. 

The CAPP was established in 2003 as a specialized agency of the ECCAS, the regional economic community for Central African countries. ECCAS members include Angola, Burundi, Cameroun, Central-African Republic, Chad, Congo, the DRC, Gabon, Equatorial Guinea and São Tomé and Principe. Gabon has the highest energy access rate at 91.8 per cent followed by Sao Tome and Principe at 78.5 per cent. These two countries have very small populations, at 2.34 million and 223,000 respectively. In addition, Gabon’s state-owned electric utility, Société d’Energie et d’Eau (SEEG), was operated under a 20-year concession by French company, Veolia, since 1997. This concession ended in 2019. Veolia maintained a 50 per cent share ownership of SEEG.  

The SAPP is a specialized institution under the auspices of SADC, which was established in 1995. Its members constituted the national electricity utilities of its member-states. Its member-states include Angola, Botswana, the DRC, Lesotho, Malawi, Mozambique, Namibia, South Africa, Swaziland, Tanzania, Zambia and Zimbabwe. Zambia did not unbundle its state-owned utility but allowed for private sector participation in the generation, transmission and generation sections of the value chain. Tanzania, Botswana, Malawi, Namibia and Mozambique still maintain state-owned vertically integrated utilities but have PSP in the generation business. Lesotho has partially unbundled utilities but no PSP. While Angola and Zimbabwe have unbundled utilities which are all still state-owned but only allow PSP to augment their own generation capacity. 

The WAPP was formed in 1999 as a specialized agency of ECOWAS. Its member-states include Benin, Burkina Faso, Côte d’Ivoire, Gambia, Ghana, Guinea, Guinea Bissau, Liberia, Mali, Niger, Nigeria, Senegal, Sierra Leone and Togo. Nigeria and Ghana have fully unbundled utilities, while Sierra Leone has partially unbundled utilities. Only Nigeria has private utilities in the WAPP. Côte d’Ivoire’s state-owned utility, CI Energies, has operated a management and concession agreement with the private entity, Compagnie Ivoirienne d’Electricité, since 1990. While other WAPP members have some sort of PSP in the generation section of the value chain, only Ghana, Nigeria, Côte d’Ivoire and Senegal have extensive PSP involvement in the sector. These four countries are also responsible for over 90 per cent of WAPP’s generating capacity. Cross-border trading takes place between only nine WAPP member states largely based on bilateral contracts due to inadequate infrastructure with Ghana, Nigeria and Côte d’Ivoire serving as the net exporters to Senegal, Niger, Togo, Mali and Benin as net importers.  

Based on power sector reforms across the various regions, some lessons can be distilled and could serve as a pathway for leaders in the African Union to adopt in support of the development and realization of the AFSEM. These lessons include the importance of cost-reflective tariffs; encouraging private sector participation and enforcing contractual agreements; ensuring political stability; a flexible regulatory structure which enables entrepreneurial dynamism and institutional evolution; and less direct interventions by governments or multilateral agencies.  


One major problem that has plagued the power sectors in Africa is the liquidity crisis brought about by non-cost-reflective tariffs and subsidies provided to different customers. The tariff a utility—state-owned or private—charges its customers for electricity is very important to the financial health of the utility. Utilities need to charge tariffs that cover their capital and operational costs. For electric power utilities, the tariff should at the very least be determined at the cost to produce 1kWh of electricity. But for Africa, the tariff needs to also consider other types of risks—for example, macroeconomic risks brought about by inflationary currencies, political risk of violence, and nuisance risk of vandalism. These considerations are very important especially for private investors because unlike state-owned utilities, they have no access to resources from the state-owned treasury to cover their shortfalls. For any utility to stay solvent it must be charging customers cost-reflective tariffs. A 2016 Word Bank study found that: 

In only 19 countries did the cash collected by utilities cover operational costs; just 4 of these countries were also covering half or more of capital costs, based on new replacement values of current asset. Such large funding gaps prevent power sectors from delivering reliable electricity to existing customers, let alone expand supply to new consumers at an optimal pace. 

According to that study, only Uganda and Seychelles were collecting revenues that cover their capital and operational costs. In addition to non-cost reflective tariffs, many African utilities have high Aggregated Technical and Commercial losses (AT&C). These losses stem from poor metering, non-billing of customers and, sometimes electricity theft. According to the Nigerian Electricity Regulatory Commission (NERC), in 2020, the total revenue collected by Nigeria’s distribution utilities was 542.73 billion (roughly $1.4111 billion at the then-official exchange rate) out of the 816.16 billion ($2.1220 billion) total bill. In Ghana, between 2017 and 2021 utilities experienced AT&C losses of about GH¢8.9billion ($1.1 billion).  

Hence, in addition to the cost of production, all associated risks and high AT&C losses must be taken into consideration when creating tariffs. The problem is that in the electric power sector, regulators must approve the tariffs that utilities—especially private utilities—can charge customers. It has been very difficult to get regulators to approve cost-reflective tariffs. When regulators such as NERC in Nigeria attempt to increase tariffs, they are usually met with political blowbacks and then the tariffs have to be rolled back. This has placed the sector in a liquidity crisis—in 2022, about five distribution companies in Nigeria went into receiverships and were taken over by creditor banks.


Power sector reforms that introduce PSP through various means across all the African countries, especially in SSA, revealed better performance of the sector. A 2020 study by the Copenhagen Business School showed the reforms in SSA led to an increase in installed generation capacity per capita and plant load factor. The study goes on to state that ‘the presence of an electricity law, sector regulator, vertical unbundling, and private participation in the management of assets have a positive impact on reform performance.’ This does not have to mean the direct privatization of the state-owned utility. Other forms of private sector participation such as management and concession agreements could be resorted to. For example, in 2000, Uganda’s energy access rate was 7.4 per cent. The country decided to unbundle the Uganda Electricity Board into three separate entities with a sector regulator. It sold a 20-year concession in 2004 to UMEME Limiteda private entityto distribute electricity to consumers. UMEME was meant to make the capital investments needed to upgrade the grid and then charge customers for its service. This led to an increase in Uganda’s energy access to about 45.2 per cent by 2021. In addition, the sector’s regulator showed independence and enforced the concession agreement even after pressure from opposition political groups in the country who were protesting UMEME’s high revenue requirement of 20 per cent.  

In addition, the model of selling transmission and distribution licenses and sub-franchises to private investors to facilitate focus on commercial and industrial (C&I) users, can free up state-owned utilities to focus on residential customers. Zambia’s Copperbelt Energy Corporation, a private entity, provides generation, transmission and distribution to industrial customers. Something similar is practised in Ghana, where a private utility, Enclave Power Company, serves the Tema Free Zone Enclave, an industrial park. 

Introducing PSP in the transmission business could help increase efficiency between generation and the customers. The 2020 study suggested that reforms did not reduce technical network losses. This is because many African countries have maintained government ownership and control of transmission assets. These state-owned transmission and distribution companies still experience the same problems their predecessor entities had.  


Political instability has been a major issue across the African continent post-independence. The 2020 Copenhagen Business School study on electric power sector reforms in Africa highlighted that perceptions of political stability, violence and terrorism have an influence on the outcomes of electric power sector reforms. From 1950 to 2010 there have been 214 coups in about 45 African countries with 106 of them successful and 108 failed. This is the highest, in terms of the number of successful coups and in the total number, by any region. More recently, Africa has seen a resurgence in the coups, coup attempts and political civil unrest in Sudan, Burkina Faso, Guinea, Chad and Mali. Electric infrastructure requires heavy capital investments that take years to make returns and, in some cases, returns on investment are uncertain. In addition, electric power infrastructure has high fixed costs, is illiquid and cannot be easily moved or substituted for another investment activity. Amid this, perceptions of political violence or actual political violence are precisely why investors stay away from making large infrastructural investments.  


Africa has seen a rise in non-traditional institutions to address the problem of energy poverty. These include the off-grid mini-grid developers, energy-as-a-service providers and solar homes systems companies. It has been estimated that the off-grid energy business has the potential to be a $4.5 billion industry by 2030. These smaller energy systems have been considered the least cost method for electrifying many rural communities that still don’t have access. While they are less expensive than traditional electric power infrastructure, they still require considerable capital investments. And since these projects are largely driven by private investment, investment returns are crucial. Based on the 2,380.9 GW shortfall, electricity is very expensive in Africa and in a continent where most people live below the poverty line affordability is an issue  

But when the regulatory system is flexible enough these various institutions evolve to address these problems by providing context-specific product and price differentiation to various consumer classes. C&I customers are willing to pay for expensive electricity because power outages affect their production processes and sometimes destroy their equipment. The economic cost of power outages in Nigeria is about $28 billion according to the World Bank. 

This has given rise to the energy services company that focuses on providing this service to these customers. They also help augment the traditional power systems services provided by the incumbent utility. Out of the 948 MW DERs commissioned in 2022, as verified by the African Solar Industry Association, C&I had the largest year-on-year growth at about 61.5 per cent, beating the total growth of 13.8 per cent (which included large-scale solar, mini-grids and Solar Homes Systems). 

Due to regulatory flexibility, Nigeria has one of the most sophisticated mini-grid markets in Africa, which has led to extensive deployment of these assets across the country. Since these developers can charge tariffs their consumers are willing to pay, without seeking NERC approval, they are able to manage default and currency inflationary risks by creating portfolios of between 20 and 40 projects across different parts of the country to diversify their risk and also to meet the minimum requirements for purchasing hedging products. This is the type of flexibility other African countries need to implement.  


While this may sound counter-intuitive, opportunities for subsidies lead to rent-seeking that do not improve the health of the sector. These subsidies have become very prevalent in the off-grid energy sector, largely driven by the need to achieve the United Nations Sustainable Development Goals of universal electrification by 2030. They are called performance-based financing (PBF). This could lead to misaligned incentives between the donor organizations, developers and the communities they serve. For example, one PBF scheme is largely dependent on the metric cost per connection. It may cost a developer $1,000/connection for a mini-grid serving in a village. The subsidies could be set at $700/connection. Hence, these connections are determined by the presence of an electric meter. This model incentivizes the developer to make, for example, 300 connections, where only 150 connections have actual customers behind those meters. To the donor agency, they count the village as having 300 connections, and the developer gets to misallocate resources by making sub-optimal connections to get the subsidy. This leads to an inflation of connection numbers that benefit the developer and the donor agency at the expense of the communities. One study by a major mini-grid developer suggests that this is becoming prevalent in the industry.  

Governments should instead remove regulatory and tax burdens on off-grid energy providers. These burdens increase the cost of entry into these industries and divert resources that could be used in addressing the problem of energy poverty in these countries. A 2018 study by the Rocky Mountain Institute, suggests that the impacts of heavy regulatory and tax burdens on off-grid energy developers in sub-Saharan Africa add about 50 per cent to hardware costs. The study estimated that reducing these burdens could improve mini-grid project economics by five per cent. 

Achieving the AFSEM will help improve continental integration. It will lead to an efficient use of resources in providing electric services to African customers. Other African regions could benefit from the extensive hydroelectric resources in East and Central Africa, the natural gas in West and North Africa, the solar resources in North Africa and the coal in South Africa. Through the AFSEM, Africa would be achieving not just universal electrification but also a successful deeply integrated and efficient electricity market. Yet many obstacles stand in the way of this. Introducing private sector participation, competition and flexible regulatory regimes in Africa’s power sectors at the national level would be a start in the right direction

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