Nigeria's utilities privatisation scheme breaks new ground

A shortage of electricity is among Nigeria’s greatest obstacles to growth, with a situation bad enough that residents often referred to the former utility provider, the Power Holding Company of Nigeria (PHCN), as Please Hold Candle Now. Chronic shortages affect all consumers, due to a legacy of underinvestment in maintenance and new facilities. The system typically functions at less than half of its installed capacity of around 12,000 MW. Successive administrations have made sector reform a priority, with partial privatisation of the national grid being a key pillar.

After years of delays, there have recently been some key investments made, and Nigeria has emerged as a test case for how development finance institutions can help catalyse the investment needed for power across the African continent.


Average Nigerian consumption of electricity on a per capita basis is 130 KWh, which is 3% of that in South Africa, the continent’s second-largest economy with a population one-third the size and a country against which Nigeria often benchmarks itself. Roughly 40% of Nigerians live in a home with a connection to the grid, according to a March 2015 International Finance Corporation (IFC) report titled “Nigeria’s Electric Power Sector: Converting Potential to Reality”. Losses of power produced due to technical, commercial and billing problems range from 35% to 40%, depending on the region, according to a June 2015 report on the Nigerian energy sector by Deutsche Gesellschaft für Internationale Zusammenarbeit (GIZ). Local businesses experience an average of 239 hours a month without electricity and 83% of them consider it to be their biggest problem, according to the World Bank. “The new administration has recognised that power is key,” Victor Ndukauba, executive director of Afrinvest West Africa, told OBG.

The temporary solution to Nigeria’s power problems is diesel-powered generators, which provide a noisy background to daily life in the country. There is an estimated 5 GW of active capacity diesel generation in the country, according to the IFC. This is a much more expensive option, however, at roughly $0.40 per KWh, compared with $0.15 for grid power.

During a December 2015 presentation on micro power for the grid, the Manufacturers’ Association of Nigeria reported that power accounts for 40% of costs among its members. “Even if there was just 10 days of steady supply, you would see a difference in the economy,” said Nicholas Barberopoulos, deputy managing director of Nigerian Foundries. “Every Nigerian would have more money in their pockets because they are not spending it on diesel.”

Size & Scope 

A true estimate of demand for power in Nigeria is difficult to calculate, because demand is presumed to be suppressed due to the unreliability of supply, which discourages new commercial investments and retail purchases of energy-intensive appliances. The state’s formal goal is to generate 20,000 MW by 2020, about 50% less than South Africa’s current production. There is certainly plenty of potential, as the country has a significant wealth of natural gas. Renewables, including solar power and more hydro plants, are also on the cards (see analysis). But natural gas is the most common feedstock for power, and as Nigeria has the ninth-largest natural gas reserves in the world that is not likely to change.

The future is seen as dependent on the ability of the state to create conditions for private investment in generation project to sell power to the national grid. “The lack of a truly cost-reflective tariff has hamstrung liquidity in the power sector.” Kola Adesina, CEO of Sahara Power, told OBG. “Resolving this issue will help attract foreign investors to the sector.” With a tariff hike implemented in February 2016, the hope is that the prices consumers now pay will be high enough attract private players. Indeed, efforts seem to be paying off. The first commercial independent power producer (IPP) that aims to produce for the grid, the 459-MW Azura-Edo IPP, reached financial close in 2015. Meanwhile, the 90-MW Magboro plant recently signed a power-purchase agreement (PPA) with Nigerian Bulk Electricity Trading (NBET). The sector was also galvanised by a 2013 privatisation campaign that saw PHCN, which handled transmission, distribution and generation, unbundled into several smaller regional distribution and generation firms, which were then sold to private investors. The national transmission grid remains publicly owned.


Electricity distribution in Nigeria is now handled by 11 regional distribution companies, all of which are privately owned. Seven formerly state-owned generating facilities were transferred to private investors, with four gas plants sold outright and three hydro plants in concession. The transmission grid remains in state hands and is operated under a management contract by Canadian utility Manitoba Hydro. Speaking in December 2015 at a public hearing on the activities of the Nigerian Electricity Regulatory Commission (NERC), Mark Karst, managing director and CEO of Transmission Company of Nigeria, said the target is to reach a transmission capacity of 20,000 MW by 2020, which will require $1bn annually.

While the state has thus far elected to retain ownership over the grid, it does hope to attract private investment in upgrading it. Until that point, IPPs are more likely to be located near existing substations, so that power can flow to distribution companies while also minimising reliance on the grid. The Azura-Edo IPP, for example, includes a new substation to be built at the site in south-central Nigeria (see analysis).

Budgeting Issue

Nigeria is suffering from a lack of power for multiple reasons, several of which date back to the federal government’s budgeting process three decades ago. From 1989 to 1999 the utilities sector received little to no capital, with the annual amount well below $50m, according to the Presidential Task Force on Power. Funding levels rose in 2000, once the country returned to democracy under former President Olusegun Obasanjo, but an electricity deficit has begun growing again. In its 2010 Roadmap for Power Sector Reform, the state estimated that self-generation from diesel and petrol generators was at least 6000 MW, while peak load demand for all 11 distributors could reach 9057 MW. “Distributions companies are hamstrung without adequate power supply,” Adekunle Odeyimka, managing director of local engineering firm Toptech, told OBG.

A plan to remedy this gap was first articulated in the 2001 National Electric Power Policy, which was then passed into law in 2005 with the Electricity Power Sector Reform Act. The act unbundled the National Electricity Power Authority into 18 companies under PHCN, which would own the individual power plants and distribution companies that would eventually be sold off. Obasanjo also tried to fast-track 10 plants in 2004 under the National Integrated Power Project, but as of May 2016 just one was producing power. These are now owned by the state’s Niger Delta Power Holding Company, and the ongoing privatisation process has been delayed multiple times. The 2005 act also established the current regulator, the NERC. Another regulator, the Nigerian Electricity Management Services Agency, was formed in 2015 to focus on technical inspections, testing and certification. Other key government actors in the current structure include the Federal Ministry of Power, Works and Housing, which is currently headed by Babatunde Raji Fashola, the former governor of Lagos State, and NBET, which acts as a middleman for generators and producers, buying from the former and allocating to the latter.


Nigeria’s 23 existing power plants producing on-grid power had an actual generation capacity of 3941 MW as of May 2015, according to GIZ, out of an installed available capacity of 6840 MW and installed capacity of 12,067 MW. Of that total, more than 85% came from the 20 gas-fired power plants, and the balance from three hydroelectric dams. Renewables in Nigeria have not historically played a significant role beyond the three hydro dams; however, the government has provided incentives through feed-in tariffs, which will set the formula for the prices that NBET will pay for power from renewables such as solar or wind farms (see analysis).

The biggest producer is the 1320-MW Egbin Power Plant, which is located 40 km north-east of Lagos. Depending on the availability of gas to the system, the plant accounts for roughly between 13% and 25% of overall production. In 2013 a 70% stake in Egbin was sold to a partnership between Sahara Energy, a Lagos-based company, and the Korea Electric Power Corporation for $407m. That transaction was separate from the 2013 privatisation process, as negotiations had dated back to 2007. In May 2016 Kola Adesina, CEO of Sahara Power, told the Abuja-based Premium Times that the new owners had restored the plant’s functional capacity to its maximum level, up from only 400 MW when ownership was transferred.

Investment Needed 

In 2013 four gas plants held by PHCN were sold to private consortia, and control of three hydro facilities was transferred to the private sector in concession agreements. Available capacity as of 2011 was above 25% of installed capacity at just one of the four privatised gas plants and at two of the privatised hydro plants. The gas facilities collected $184.6m in revenue in 2011 and the dams brought in $131m. As with Egbin, Nigeria expects that the new owners of these assets will invest in restoring them to full strength. However, access to finance has been an obstacle. In February 2016 Dolapo Oni, head of energy research at West African regional lender Ecobank, told news site AllAfrica that Nigerian banks had extended 40% of their loan capital to oil, gas and power as of March 2016.

Lenders are now concerned about being able to collect on loans already extended, and some have already warned the market that loan losses could be forthcoming from the energy and power sectors in the country (see Banking chapter).


A recent large-scale addition to this segment of the market is the 141-MW, gas-fired Aba IPP, developed by Geometric Power. Geometric Power has established a ring-fenced distribution network, not connected to the national grid and independent from the Enugu Electricity Distribution Company (EEDC), the existing distribution firm for the area that uses grid power. The IPP distributes power to industrial customers, as the region hosts a significant concentration of them, as well as the nearby city of Aba. Gas is supplied by Shell via a pipeline built to its processing facility 27 km away. The project was delayed over whether the EEDC had exclusive rights to the area. However, an agreement was reached between the parties in March 2016, and Geometric Power was ceded the right to supply electricity to Aba and the Ariaria industrial area, as well as collect tariffs, with any excess power is to be transferred to the EEDC.

One of the challenges in building IPPs to produce for the grid has been the difficulty their developers face in securing a PPA from NBET. Under the previous president, Goodluck Jonathan, these were not typically signed, but that too has changed with the presidency. In January 2016 Fashola announced that a new IPP, the 90-MW Magboro station, had signed a PPA. The plant is in Ogun State, to the north-east of Lagos, and is owned by Bresson AS Nigeria.

The first commercial IPP which is designed to produce for the grid reached financial close at the end of 2015: the Azura-Edo IPP. Most of the financing for the 459-MW plant comes from foreign investors, including commercial banks such as Standard Chartered Bank and South Africa’s Rand Merchant Bank, and national development finance institutions, including the US government’s Overseas Private Investment Corporation and the Development Finance Company of the Netherlands. Multilateral agencies, including the World Bank and IFC, and the Nigerian government also played key roles by providing risk-mitigation instruments such as guarantees against default, political and other risks. The Azura-Edo IPP’s financial structure is expected to be emulated in Nigeria and elsewhere to stimulate new investment (see analysis).

Gas Supply 

For gas-fired power plants, gas supply remains a key issue despite the country’s wealth of oil and gas fields. Supply is short for several reasons, including that, like with tariffs, the government has traditionally monopolised the ability to trade in gas. For most of the past decade, it set rates too low to incentivise producers to sell to the domestic market at below $0.10 per million British thermal units (mBtu). In comparison, following two recent gas concessions Egypt moved from its standard price of $2.65 per mBtu to a sliding scale dependent on market conditions with a high of $5.88.

Gradual hikes to Nigeria’s set price have since resulted in a two-tiered market. Gas-fired power plants that secured a long-term supply agreement before 2015 now pay $2.50, the formal regulated price. However, IPPs signing agreements from 2015 must negotiate a price with suppliers, with an additional $0.80 per mBtu going to the Nigerian National Petroleum Corporation for transmission fees.

Azura-Edo, for example, will pay $3 per mBtu initially, with inflation-linked increases over the course of its 15-year agreement with the Seplat Petroleum Development Company, a locally owned energy firm. The power plant will require 115,909 mBtu per day, and as a result of the contract Seplat Petroleum has agreed to build new processing capacity. Another recently negotiated deal came between Lagos-based Seven Energy and a government-owned power plant in Calabar, in Nigeria’s south-east.


Passing ownership from the state to the private sector has not yet resulted in the transformation of the country’s 11 distribution companies, and the fortunes of the entire sector are considered to be reliant on their success. If the distributors cannot collect tariffs from customers and pay their suppliers, then problems will reverberate through the whole value chain. Generators cannot pay for gas, and extraction companies lose their interest in selling to generators. The percentage of invoices paid fell from a system-wide average of 54% in November 2012, when the companies were still controlled by the state, to 47% as of January 2014, according to the World Bank. The bank’s analysis envisions three scenarios to 2017 in which the overall shortfall in cash-flow within the power system ranges from $900m to $4bn.

Two problems compound the challenges for distributors: end-user tariffs set too low to allow some revenue to be retained to maintain and develop their networks, and the distributors’ inability to accurately measure what their customers use and then collect accordingly. As of February 2016 roughly 70% of electricity customers were not metered.

With the recent tariff hike in February 2016, the government also eliminated a fall-back option distributors had previously relied on, known as estimated billing – making up for the shortfall when customers do not pay or are underbilled by charging more to customers who do pay their bills.


Tariffs are set by the NERC according to the multi-year tariff order (MYTO), which was established in 2008 and is structured similar to the process used in the UK. Under this mechanism, the NERC sets the rates distributors can charge users based on factors such as production costs, inflation and foreign exchange projections. Tariff levels are reviewed twice a year for minor adjustments, with a major overhaul undertaken every five years, in which the assumptions they are based on are updated as is deemed necessary. The current MYTO (effective since February 2016) has been accused of being inadequate due to material variances between its assumptions of the foreign exchange rate and inflation, among other statistics, and the actual figures.

In the past, the government has not stuck to the tariff review schedule, and participants and would-be investors in the system have been calling for tariff hikes in recent years. Given the suppressed rates, debts have built up across the system, according to Batchi Baldeh, the director of power at Lagos-headquartered international finance institution Africa Finance Corporation (AFC), which is funded by multiple African countries. Baldeh told OBG, “Cash-flows from the power sector have not been sufficient for the distribution companies to collect from everybody and pay their upstream partners. Thus, the distribution companies have built up payables.” In response, the Central Bank of Nigeria set up the N213bn ($674.4m at the time of printing) Nigerian Electricity Market Stabilisation Facility to help private owners cover their losses until the system is financially sustainable. To date, it has disbursed N120.2bn ($379.5m) to generators, distributors, service providers and gas firms. Examined within their individual territories, the distribution companies’ problems differ. In Abuja 40% of revenue comes from government offices, which have been frequently delinquent in paying their accounts. The Benin Electricity Distribution Company benefits from geography, as the national grid is relatively more functional in its part of the country thanks to multiple lines intersecting nearby. The AFC is a major investor in the Benin ownership consortium, and it has brought in Tata Power of India as a technical partner, hoping to leverage that company’s track record of reducing technical and collections losses in its home market. Eko Distribution Company is the only one with a collections rate above 90% over the 2012-14 period, according to the World Bank. It covers the southern part of Lagos, including the areas on the south side of Lagos Lagoon that serve as the city’s central business district and an industrial zone. At the other end of the spectrum is the Yola Distribution Company in the north-east of the country, for which records show a 0% collections rate for the duration of the period.


The hope in Nigeria is that as a commercial IPP market develops, distributors will be able to incrementally improve their operations and collections, and grid investment will scale up, allowing the three elements of the sector to grow together. Foreign investors can watch the World Bank and African Development Bank (AfDB) for signals on investment – their partial-risk guarantee (PRG) programmes, which helped catalyse the Azura-Edo IPP investment, will be applied to successors. Because PRGs are ultimately a sovereign guarantee, the government has the final say in which projects are eligible. A list of candidates is expected to be presented by the government to the two development banks before the end of 2016.

PRG Contenders 

A sense of what projects may populate the PRG pipeline could come from the World Bank’s 2014 programme-description document. So far one other project on that list has made it past the first stage of approvals for a PRG: a 533-MW plant in Qua Iboe State that was initially proposed by ExxonMobil and will use gas it produces. However, since a ground-breaking ceremony in 2010, there has been no further work on the power plant, and speculation has arisen over whether other firms are interested in purchasing the project. Beyond this, there were six other IPPs identified by the World Bank in 2014, including two renewables projects (see analysis).

The World Bank list also identified four distribution companies that were in the advanced stage: the Eko and Ikeja distribution companies, which split coverage of Lagos, and those in Abuja and Benin City. PRGs for power companies can be used to insure their owners against defaults by NBET. For distribution companies, they could also be used to enhance creditworthiness, and therefore increase access to finance, as well as to protect investors from the risk of the NERC failing to maintain tariffs at a cost-reflective level. “As tough as it is, if you want investment you have to have cost-reflective tariffs,” Ndukauba said.

The World Bank has offered $700m of PRG funding, of which $237m has already been spent on the two bundles of the final Azura-Edo PRG package. Funding for PRGs is on a first-come, first-serve basis. The overall amount for future PRG funding has not be made clear by either the World Bank or the AfDB.

Vertical Integration 

Investors in the sector are increasingly acquiring assets in both upstream energy and in electricity, and in the future they may be able to lower risks through vertical integration. Sahara Energy stands out as the only company to own both a power plant and a distribution company, with the firm’s Egbin Power Plant and Ikeja Distribution Company being the largest of their kind in the country. Utility sector regulations still prevent a company like Sahara Energy from selling its power to its own distributor, as NBET’s role as the bulk trader means electricity is always routed through that central control mechanism. However, NBET itself is meant to be a temporary solution that will be shuttered in the future when the power sector can stand on its own, with buyers and sellers able to interact directly.

Water & Sanitation 

The utilities sector in Nigeria also includes water and sanitation. Water sector policy is set by the Federal Ministry of Water Resources. State-level agencies are responsible for water supply, and municipal-level governments are charged with overseeing potable water. The National Water Policy of 2004 set out methods for meeting demand and achieving the UN’s Millennium Development Goals. World Bank statistics indicate that Nigeria has made significant progress in improving water access, but has been less successful in the sanitation segment. The percentage of the overall population with access to improved drinking water rose from 40% in 1990 to 69% in 2015. In urban areas this figure increased from 76% to 81% over the same period, and in rural parts of the country it surged from 25% to 57%.

Challenges in providing water are familiar to those in the power sector, including the difficulty of metering and billing. A study published by Enugu State University of Science and Technology in the European Scientific Journal in 2015 found that in the Niger Delta region, for example, the lack of steady access means paying more in private sector purchases. Increased investment in infrastructure and greater authority for sub-national agencies could result in better supply and lower rates of water-borne diseases, according to a study published in the Journal of Water, Sanitation and Hygiene for Development in February 2016.

The share of the overall population with access to improved sanitation facilities declined from 38% in 1990 to 29% in 2015. These figures can be further broken down into a fall from 38% to 33% in urban areas and 38% to 25% in rural areas. One of the biggest challenges in sanitation is the spread of improved toilets, which would combat diarrhoea, the second-largest contributor to child mortality.


Although meeting Nigeria’s massive and expanding electricity needs will require the development of its major offshore gas fields (see Energy chapter), in the short term the combination of reforms and local involvement continues to provide opportunities for investors willing to risk capital on the new, and as yet untested, systems now in place.


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The Report: Nigeria 2016

Utilities chapter from The Report: Nigeria 2016

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