Utilities privatisation in Nigeria improves sector's efficiency


As Africa’s largest and most populous economy, with a vibrant private sector and vast natural resources, Nigeria has strong potential for growth. However, that potential is consistently hindered by an underdeveloped utilities sector. Providing utilities remains one of Nigeria’s greatest challenges, as a sizeable portion of the population is still without reliable access to power, clean water and sanitation services.

Unreliable electricity is particularly damaging for the economy, with the annual cost tallied by the government at more than $25bn, partially due to reduced investment and higher overhead costs. Some estimates suggest that the lack of sufficient grid power shaves as much as half a percentage point off annual GDP growth.

As a result, successive governments have sought to overhaul the sector, encourage an increase in generation, and improve transmission and distribution. Strategies over the years have had varying degrees of success, but the recent push towards privatisation has begun to open up improvements in cash flow, captive consumption and project financing.


The government succeeded in establishing Africa’s first truly competitive market for wholesale power by privatising most of the state’s power plants and distribution companies, although it did retain its role as the grid operator. It also established a clearing house to facilitate trade between generators and distributors.

This rise in private participation has led to significant progress across the sector. For instance, collection rates have improved considerably as a result of distributors reforming and modernising their metering, billing and collections processes. Another positive effect is that more independent power producers (IPPs) have entered the market.

However, there are substantial challenges ahead for the sector. For example, although February 2016 saw a record high of 5074.7 MW of power generated in one day, output has generally fallen since. Moreover, the improvements in output and efficiency were much lower than anticipated. Gas supply remains a crucial bottleneck, affected by limited infrastructure and regular supply disruptions. This is a pressing problem for Nigeria, as it serves as the feedstock for 86% of existing generation capacity.

Two central external risks to the reform process are currency depreciated to and access to finance. The depreciation of the naira has driven up the cost of importing equipment and parts, while the subsequent impact on inflation has made raising tariffs difficult. Dolapo Oni, an energy analyst at Ecobank, told OBG that loans to oil, gas and power companies represent slightly more than a quarter of all outstanding credit in the Nigerian banking system. With non-performing loans and sovereign debt purchases on the rise, banks are becoming more reluctant to lend (see Banking chapter).


To provide for a country of 180m, Nigeria has a possible generation capacity of 7.5 GW, although actual output is usually slightly more than half of that. By comparison, in 2015 the US state of Connecticut had 8.7 GW of capacity for a population of 3.5m.

Accurately calculating demand in Nigeria is challenging, as the total amount of both grid and diesel generator power is generally assumed to be in the range of 10 GW, but this calculation typically fails to account for the pent-up demand created by the lack of access to reliable power. According to the World Bank, more than 40% of Nigeria’s population did not have access to power in 2014.

Diesel-powered generators are often used to compensate for the lack of consistent electricity, which is an expensive solution to the problem. A report by the International Finance Corporation estimated that this type of power costs $0.40 per KWh, compared with $0.15 for grid power. For energy-intensive sectors such as telecoms, this means overhead costs can be as much as one-third higher than in markets like South Africa, where grid power is more dependable.


Concerted efforts to reform the utilities sector began in earnest when the administration of President Olusegun Obasanjo passed the Electric Power Sector Reform Act of 2005. The bill mandated the unbundling of the state’s old monopoly power company, the National Electricity Power Authority, into 18 successor companies: six for power generation, 11 for distribution and the Transmission Company of Nigeria (TCN) as the grid operator. All but the TCN were sold in the 2013 privatisation programme undertaken by then-President Goodluck Jonathan. The TCN will remain in state hands for now, following the end of a three-year management contract with Canada-based Manitoba Hydro International in July 2016, which was not renewed. The state also still owns a handful of power plants through the Niger Delta Power Holding Company (NDPHC).

Government Oversight

Much of the authority over the utilities sector is held by the Federal Ministry of Power, Works and Housing, which is headed by Babatunde Fashola, the former governor of Lagos State. To ensure accountability, the sector now has two regulators: the Nigerian Electricity Regulatory Commission (NERC), an independent body that has the authority to regulate the power sector; and the Nigerian Electricity Management Services Agency, which the government created in 2015 to oversee technical inspections, testing and certification.

A third state agency, Nigerian Bulk Electricity Trading (NBET), buys power from generators and sells it to distributors. This agency is seen as a temporary fix, created to assist the market’s transition from a state monopoly. There is no specific date at which it is expected to leave power sales to the parties themselves, though progress towards a format in which buyers and sellers engage in these transactions directly is under way. In May 2017 the NERC announced that consumers using at least 2 MWh per hour on a monthly basis could buy power directly from generators instead of distribution companies, but the retail market is set to remain centralised.


As of 2016 there were 23 producing power plants in Nigeria, with a total installed generation capacity of 7.5 GW. Actual capacity fluctuates, typically in a range below 5 GW, as plants cope with turbine maintenance issues and an unreliable gas supply. Aside from three hydropower facilities, all are thermal power plants that use gas or oil.

The biggest plant in the country, Egbin Power, is owned by local group Sahara Energy and is located in Ikorudu, outside Lagos. With a capacity of 1320 MW, Egbin Power has at times accounted for up to a quarter of all electricity in the system. Among the country’s other large generating assets are the 1131-MW Alaoji Gas Power Station, which is located in Abia and owned by the NDPHC; and the 900-MW Ughelli Power Plant, which is owned by Transcorp Power and located in the Niger Delta region. Construction on the NDPHC’s 10 power plants began in the early 2000s under the National Integrated Power Project (NIPP). All 10 were operational as of September 2017, but were not functioning at their combined total capacity of 2000 MW; the NDPHC pointed to vandalism, ongoing repairs, security challenges and accumulated debt as contributing causes to reduced operation. The NIPP is expected to reach 4775 MW of planned capacity over time.

Captive Ipps

In 1998 the government passed legislation that allowed for private power generation, and plans for the first IPP project – the AES Barge IPP project, a joint effort between the federal government, Lagos State and the now defunct US energy company Enron – rolling out in 1999. The 270-MW plant has been operational since 2001, although securing a reliable fuel supply has been an ongoing problem for the plant. There were over 80 licensed IPPs in the country as of 2016, with the largest three producing around one-quarter of Nigeria’s electric power: 642-MW Afam VI, operated by Shell; 480-MW Okpai, operated by Agip; and the 270-MW AES Barge.

Increasingly, IPPs are also serving captive consumers. Local firm Geometric Power, for example, built the 141-MW Aba IPP in 2014 in a ring-fenced system in Enugu State to service a nearby industrial park. The project faced delays over the question of whether the local distribution company, the Enugu Electricity Distribution Company (EEDC), had exclusive rights to sell to customers. The matter was settled in March 2016 when Aba was awarded the right to supply power and collect tariffs in its allotted area, with any excess power transferred to the EEDC’s system.


In May 2017 the NERC announced that it would permit the direct sale of power from generators to major users to enable power producers to bypass distribution companies, a move that is in keeping with the broader decentralisation trend in the power sector. This means that generators can deal with their main consumers more directly and efficiently, while also encouraging the emergence of smaller generator projects outside the national grid, such as captive IPPs like Aba that produce energy for a specific community or market.

Other small IPPs outside the national system are typically built by major users themselves in order to secure their own supply. These are not necessarily private sector actors. For example, the governmental Lagos State Electricity Board has built embedded IPPs – those distributing to a small area through local transmission lines – that now have some 47.5 MW. The state has plans to develop another 3 GW through embedded IPPs, and wants to collaborate with private investors to build multiple plants with capacities in the range of 5-100 MW.

Model Structure

Cash flow issues and difficulty accessing feedstock for power producers means that funding IPPs can be problematic, because the risk of these long-term projects is considered high. It is not uncommon for returns to take years to materialise, if at all, so it can be difficult to attract investors.

One of the country’s larger IPPs has taken an innovative approach to overcome this by offering investors comprehensive protection against risk. The 450-MW Azura-Edo IPP, to be built by Mauritius-based Amaya Capital Partners, will be Nigeria’s first IPP that produces power for the grid. To finance this endeavour, Azura has a package of $876m in debt and equity at a 70:30 ratio, bringing together a mix of commercial providers and development banks.

In addition, it has negotiated a gas supply agreement at a special price, instead of the official one set by the government. Azura safeguarded a rate of $3 per million British thermal units (Btu) with Seplat Petroleum Development, which does not include a transport fee of $0.80 per million Btu. In order to reach financial close, several risk-mitigation measures were utilised in the deal, including political risk insurance from the World Bank’s Multilateral Investment Guarantee Agency and the US government’s Overseas Private Investment Corporation.

Additionally, the Ministry of Finance will protect both sides in case of a default by the NBET or a problem with gas supply. It releases Azura from its legal obligations and gives its owners the right to sell the plant to the government at a price settled in a standard arbitration process. A partial risk guarantee (PRG) from the World Bank worth up to $117m can be drawn on in the case that the NBET fails to pay for the power provided. The use of PRGs in Nigeria has long been suggested as a way to help address risk in the power sector, but it remains to be seen whether the government will continue to implement them in more projects moving forward.

Sourcing Supply

Supply disruptions due to the vandalism of gas pipelines cut total power production to as low as 2662.2 MW in January 2017. Overall, however, the amount of gas available has climbed in recent years, with the Nigerian National Petroleum Corporation (NNPC) reporting that the average national daily gas supply to power plants rose by 64% year-on-year in May 2017 to reach 729m standard cu feet (scf) of gas per day. To further aid a steady supply, the Nigerian Gas Company, a division of the NNPC, is rolling out two new major pipeline expansions. One is an east-west trunk line from the Obiafu/Obrikom Central Processing Facilities in the Niger Delta region. The other is the double-tracking of the Escravos-Lagos Pipeline System, an existing line crucial for moving gas from the south-eastern fields to the western users clustered in Lagos.

Increasingly, local investors are investing in their own pipelines and gas-processing facilities to safeguard feedstock, as Seplat did in the Azura project. Seven Energy has also invested in pipes and processing; for instance, its 62-km Uquo to Ikot Abasi pipeline has been delivering gas to its Uquo Gas Processing Facility since 2014. Another pipeline project, with backing from local firms Dangote Group and FIRST Exploration & Petroleum, is set to bring at least 1.5trn scf of offshore gas to a new petroleum complex in Lekki in Lagos State. If successful, the developers plan to twin the pipe and boost capacity to 3trn scf. In the past the regulated price for gas sales was considered unattractive for upstream producers, but the price has since been raised from $1.50 per million Btu to $2.50 per million Btu, plus a transportation fee of $0.80 as of 2015. However, IPPs and other customers using gas from pipelines outside the NNPC network must negotiate their own prices.

Strategic Diversification

In 2015 the federal government’s National Renewable Energy and Energy Efficiency Policy outlined a formal goal of attaining 33 GW of capacity by 2020, of which 11% is to come from renewable energy. “As a whole, the renewable energy sector has massive potential, but it needs serious investment,” Femi Adeyemo, co-founder and CEO of Arnergy, told OBG. “It has not yet even addressed 1% of local market demand.”

As of yet, there have not been large-scale renewable energy generators in Nigeria, although there are a number of household solar-powered generators across the country, as well as major works under discussion. One example is Azura-Nova, a 100-MW facility in Katsina State to be built by Amaya Capital Partners. Increasing the number of small-scale, off-grid solar plants is also seen as a solution to the power problem that is exempt from the challenge of transmitting power over the national grid.

According to a Bloomberg report released in March 2017, Nigerian officials are aiming to generate some 1200 MW of off-grid solar power, which could help cut down on the $21.8bn that households and small businesses across the country currently spend on running diesel generators for additional power.

Nuclear power is another possibility, though it is still in the earliest stages of development. In April 2017 the new chairman of the Nigeria Atomic Energy Commission, Simon Malam, pledged to pursue legislation to develop nuclear power, which he estimated would take up to a year to accomplish. The commission had already received approval to develop a nuclear power roadmap at this time.

In an effort to meet its power objectives, the government announced in June 2016 that coal mining licences would only be awarded to companies that intended to use the coal to generate electricity. In line with this policy, the Enugu State government entered talks with Simang Group, a South Africa-based equity investor, in June 2017 on the prospect of a technical partnership to explore coal deposits for the purpose of power generation. Meanwhile, US power production company Milhouse Generation Services is set to invest $100m in what will be Nigeria’s first coal-to-power plant, which is expected to have a capacity of 60 MW.


The country’s 11 distribution companies serve a variety of areas. Operators such as Eko Electricity Distribution Company and Ikeja Electricity Distribution Company cover the densely populated areas of Lagos, providing services to commercial clients and residential users, while other companies cover the sparsely populated and geographically diverse areas of northern and rural Nigeria, where there are very few major consumers.

Each of the now-privatised distribution companies grapples with ongoing challenges, mainly caused by poor cash flow as a result of deficient collections, theft, low tariffs and other issues. This in turn creates problems in purchasing power. In 2016 these distributors collectively accumulated more than N107bn ($378.1m) in arrears for services provided by the six publicly owned service providers. The collection rates in the second quarter of 2016 ranged from 69.1% for Eko, down to 30.5% for the Kaduna Electricity Distribution Company, and as many as six of the 11 distributors had a rate below 50%.

These issues persisted under state ownership, leading many of the new owners to subsequently seek to overhaul revenue systems by placing greater emphasis on improved metering practices. “It’s a very difficult process to disconnect a customer once you learn that they are bypassing electricity or not paying their bill,” Wale Okunrinboye, an economist at Ecobank, told OBG. “As long as the distribution companies don’t have the ability to enforce collections, they are going to struggle.”

Benin Distribution Company leads the market in metering, with 65.3% of its customers on meters, and Eko is the only other company with a rate above 50%. Yola Distribution Company, which returned to government control in 2015, trails the group at 21.7%. In order to improve these rates it was decided that estimated billing would be stopped by the end of 2017; however, in June 2017 distribution companies announced that instead of enforced metering across the board, estimated billing would continue for residential customers while large-scale users would receive bills based on meter readings.


Government efforts, such as Lagos State’s move to criminalise power theft and the vandalism of utility equipment, should help to improve revenues by reducing damage costs. There have also been efforts to increase government engagement in the sector. Fashola proposed that the financial accounts of distributors be centralised and subject to an escrow system, telling local media that the NERC was seeking greater control over procurement to ensure that financial details are properly reported. Currency risk has been another area of focus in recent reforms. The slump in oil prices over the past two years has significantly weakened the value of the naira against the dollar; in 2012 $1 was equal to roughly N150, compared to approximately N300 in mid-2017. While adjustments in the tariff have mitigated some of the currency risk, it still causes complications in terms of recouping investment. “You cannot go and borrow dollars when your base income is in naira,” Aliko Dangote, chairman and CEO of Dangote Group, told local media in October 2016. “You are taking a huge exchange risk.’’ TRANSMISSION: The state-owned TCN now manages the transmission network, after Manitoba Hydro International’s three-year management contract was not renewed in 2016. It has been reported that the government has plans to privatise the TCN; however, there has been no confirmation on the matter.

A vast rehabilitation and expansion programme is the current priority for the TCN, as according to its estimates, the national grid cannot handle more than 5300 MW in the system. To tackle this issue, 46 transmission projects were prioritised for renovations in the 2016 national budget, as these locations were considered most important in achieving the government’s key objectives of increasing power supply to major cities, evacuating stranded generation, reducing the flow on overloaded circuits and delivering power to the north of the country.


Tariffs, which shift according to consumption levels, consumer classification and geography, are set by a formula maintained by the NERC. Setting tariffs is a difficult task in Nigeria, particularly for households. Poverty rates, inflation and underemployment are high, which means raising rates by too much will reduce access to power and slow growth; setting tariffs too low, however, means that distributors are unable to recover the costs of power purchases, maintenance and expansion.

Under the current multi-year tariff order (MYTO) introduced in mid-2015, nearly half the tariff comes from the cost of distribution, followed by the cost of generation, while transmission costs and taxes make up around 15% of the total price. The MYTO is scheduled to run through to 2024, with prices increased at the start of every year.

Tariff hikes tend to be highest for commercial and industrial consumers, although it varies by location; in the Ikeja distribution area, for example, between 2015 and 2016 they rose from N24.40 ($0.09) to N38.14 ($0/13) per KWh for the largest commercial customers, while in the Abuja distribution area, tariffs rose from N29.98 ($0.11) to N46.23 ($0.16).


While the privatisation process of the country’s power sector was long overdue, increases in output and efficiency have been slower to materialise, in part due to the significant structural issues that continue to bottleneck key parts of the sector. Despite the setbacks, there are some encouraging developments with IPPs, which are expected to increase in the coming years, while upgrades to trunk pipelines should improve feedstock supply.


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The Report: Nigeria 2017

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