By Franklin Iyamah | More than a decade after the 2013 privatisation exercise, Nigeria’s electricity sector remains in a state of arrested development. Starting with the 2001 National Electric Power Policy through to the landmark Electricity Power Reform Act of 2005, Nigerian policymakers pursued fundamental adjustments to the electricity sector with the stated objective of changing the nature of ownership, control and regulation of the sector and ultimately improving power supply to households and businesses.
A key pillar of these policy moves was to unbundle the old vertically-integrated, government-owned monopoly (Power Holding Company of Nigeria, PHCN or better known by its more popular name National Electric Power Authority, NEPA) and replace it with a sector built around private generation companies (GenCos), private distribution companies (DisCos), a government-owned but privately managed transmission company, and an independent regulator – the Nigerian Electricity Regulatory Commission (NERC). The reform programmes also included adjustments to the nature of electricity pricing with the introduction of Multi-Year Tariff Orders (MYTO) I & II in 2008 and 2013 respectively. However, despite the resulting industry structure, alongside a myriad of presidential initiatives, these interventions have not produced the level of reliable electric power for Nigerian homes and businesses that the original reforms were expected to deliver.
By year end 2025, Nigeria’s electricity system still reflected the central weakness of the post-privatisation market: significant installed capacity but limited dependable supply. Across 28 grid-connected plants, installed capacity stood at 13,625MW, yet actual output remained far below this level with average electricity generated across the four quarters of about 4,474MW/h slightly above 2024’s level of 4,223MWh/h. Furthermore, NERC’s quarterly reports show that the average plant availability factor remained around 39–40% throughout 2025, meaning that, at any point in time, more than 60% of installed grid-connected capacity was unavailable for dispatch. Per NERC, the national grid recorded two system disturbances in 2025: one total collapse on 10 September and one partial collapse on 29 December. This was a meaningful reduction from the nine system collapses recorded in 2024, but it did not eliminate the underlying reliability problem. The transmission network remains a structural bottleneck in the electricity value chain, particularly because it was excluded from the 2013 privatisation and remains government-owned, while generation and distribution were transferred to private investors.
The supply weakness is also tied to the fuel-to-power problem. Nigeria’s grid-connected generation fleet is heavily dependent on gas, yet gas supply to power plants remains constrained by pricing disputes, unpaid invoices, weak payment security, inadequate gas infrastructure, and the inability of the electricity market to support bankable gas contracts. This helps explain why installed capacity does not translate into dependable dispatchable power. The electricity crisis is therefore not only a DisCo, tariff, or transmission problem; it is also a gas-payment and gas-infrastructure problem.
In a similar vein, the commercial position of the sector remains weak as DisCos continue to record Aggregate Technical Commercial & Collection (ATC & C) losses far above the levels assumed in their tariff models. For context in 2025, NERC reported quarterly ATC&C losses of 39.61% in Q1, 37.92% in Q2, 33.27% in Q3, and 34.90% in Q4, all materially above the 2025 target loss projection of 20.54%. These underperformances translated into cumulative DisCo revenue losses of approximately ₦606.5 billion over the year. In practical terms, this means that even where electricity was generated and delivered into the distribution network, a large share of its value was lost through technical losses, commercial losses, and weak collections.
Taken together, the 2025 data-points demonstrate that Nigeria’s post-privatisation market has not yet achieved the objectives of the 2013 privatisation programme: reliable dispatchable power supply, stable electricity grid operations, efficient distribution, disciplined collections, and a revenue base strong enough to attract investment.
Although the dominant narrative about the persisting challenges has coalesced around the absence of ‘cost-reflective tariffs’, this explanation is incomplete as the reform process already recognised tariffs as a central issue before the 2013 asset transfer. NERC introduced MYTO in 2008 to create a predictable tariff path and gradually move the sector toward cost reflectivity, which means that privatisation was not undertaken in a tariff vacuum. As such, the continued weakness of the sector cannot be explained by the absence of cost-reflective tariffs. Nigeria’s electricity problem is rooted in deeper structural weaknesses in the design and operation of the market.
Unlike in most electricity markets, Nigeria has witnessed an exodus of large industrial and commercial users into off-grid captive and self-generation power systems. The exit of this critical customer base is one of the clearest signs of a deeper system failure. It matters because these users are usually the anchor customers of electricity markets. But the same unreliability that pushed them into captive power also affects households, SMEs, schools, hospitals, and informal businesses that cannot afford full self-generation. Accordingly, this is the classic market failure problem in public utilities when anchor customers exit: the cost base must be recovered from a smaller and less creditworthy pool of remaining users. This pushes the cost-reflective tariff above what it would have been under full market participation — which in turn accelerates further exit. The equilibrium level that cost-reflective tariff reform advocates are chasing is therefore not the market equilibrium; it is the depleted market equilibrium. Already, Nigeria appears to be living this out as Band A tariffs now exceed levels in many developed electricity markets yet deliver lesser electricity supply hours.
Sources: Reuters; EIA; Eurostat; author's conversion of Euro values at approximately US$1.08/€.
A further complication is the decentralisation of electricity regulation under the 2023 constitutional amendment and the Electricity Act 2023, which removed the restriction confining state electricity activity to areas outside the national grid. States may now establish their own regulatory authorities, with powers over licensing, tariffs, consumer protection, and market oversight within their jurisdictions, while NERC retains responsibility for states yet to complete the transition and for broader federal electricity functions. Decentralisation is both an opportunity and a risk. States such as Lagos could design power solutions around local industrial demand, embedded generation, mini-grids, and bilateral contracting — potentially recapturing industrial load that the national grid has lost. Thus, decentralisation risks producing a balkanised market where stronger states ring-fence bankable commercial demand while weaker states remain dependent on an underfunded national grid and financially distressed DisCos.
Although current reforms include tariff adjustments, debt refinancing, transmission initiatives (such as Siemens-backed Presidential Power Initiative), decentralisation, and renewable mini-grid programmes, the dominant fiscal and market-stabilisation lever remains tariff adjustment. The problem is that while tariff adjustment can reduce subsidy pressure, it cannot by itself solve the deeper constraints of unreliable supply, weak metering, DisCo underperformance, gas-payment risk, transmission bottlenecks, and customer exit.
The central reform question, therefore, is no longer only whether tariffs are cost-reflective or whether generation capacity is sufficient, but whether Nigeria can build a coordinated federal-state electricity market that attracts industrial users back into the formal grid system without producing regulatory fragmentation. This paper argues that Nigeria's post-privatisation reform remains incomplete because it changed ownership without creating the conditions for reliable electricity supply to households and businesses. In particular, the failure to retain industrial and large commercial users has eroded the sector's revenue base and undermined the commercial assumptions behind privatisation. The 2023 decentralisation adds a further balkanisation risk if state markets develop without adequate coordination on grid operations, interstate trading, tariff regulation, and distribution restructuring. A sustainable reform agenda must therefore move beyond tariff fixation towards rebuilding the financial and operational foundations of Nigeria’s electricity sector.
Electricity is not merely a sectoral reform issue; it is a welfare, productivity, industrialisation, and national-development issue. Poor electricity affects household welfare, education, healthcare, food storage, digital access, small businesses, manufacturing costs, employment, and national competitiveness. Nigeria’s power-sector reform should therefore be judged not only by whether tariffs are cost-reflective or whether market contracts are bankable, but by whether the sector can deliver adequate, reliable, and affordable electricity at scale. World Bank data show Nigeria’s electricity access was about 61.2% in 2023, meaning roughly 40% of the population still lacks access, making Nigeria the most energy-poor country in the world and gravely undermining Nigeria’s quest for economic growth and development.
Perennial Epileptic Power Supply and the Vaunted Appeal of Privatisation
The 2013 electricity privatisation in Nigeria was neither an isolated policy event nor simply an ideological decision to transfer public assets to private investors. Rather, it was the culmination of a longer reform process driven by deep dissatisfaction with the state-owned electricity model, which had become both operationally ineffective and fiscally unsustainable. For most of Nigeria’s post-independence history, electricity supply was organised around a vertically-integrated public monopoly, first under NEPA and later under PHCN, with the federal government retaining control over electricity generation, transmission and distribution. NEPA was created in 1972 through the merger of the Electricity Corporation of Nigeria and the Niger Dams Authority and was saddled with the responsibility for generation, transmission, distribution, and supply across the country. Although this model was originally justified by the need to coordinate national infrastructure development and extend electricity access across the country, it had become clear by the late 1990s that NEPA, and later PHCN, could not provide reliable power, recover costs, maintain ageing infrastructure, or mobilise the investment required to expand capacity, while the government continued to bear the financial burden of a sector that was failing households, businesses, and industry.
The account by the Bureau of Public Enterprises (BPE) of the pre-reform era describes a system in which only 19 of 79 generation units were functional, average daily generation was around 1,750MW, no major transmission line had been built since 1987, and technical and non-technical losses exceeded 50%. Tariffs covered only a fraction of actual costs, meaning the utility could neither fund its operating requirements nor finance the capital expenditure required to expand and modernise the network. In 2009, the World Bank estimated that Nigeria had about 3,000MW of available grid-supplied generation against demand of roughly 10,000MW. This shortfall forced a large share of households and almost all private enterprises to rely on expensive self-generation. According to the World Bank, only about 40% of the population had access to electricity as at then, while transmission and distribution infrastructure suffered from poor reliability, high technical losses, poor billing, weak collections, below-cost tariffs, and widespread theft.
The first major policy response after the return to democratic rule was the National Electric Power Policy of 2001, which set out the objective of transforming Nigeria’s electricity industry into a more efficient, commercially-viable, and private-sector-led market. The policy aimed to attract private investment, establish a transparent regulatory framework, promote competition, and move the industry toward cost-reflective pricing. These principles were given legal force by the Electric Power Sector Reform Act of 2005, which became the statutory foundation for restructuring the sector.
The 2005 law provided the legal basis for dismantling NEPA’s monopoly. It established NERC as an independent regulator, created PHCN, and provided for PHCN to be unbundled into eighteen (18) successor companies across six (6) GenCos, one (1) transmission company, and eleven (11) DisCos. In 2010, as part of the implementation roadmap for electricity reform, the President Goodluck Jonathan administration created the Nigerian Bulk Electricity Trading (NBET) company as a transitional bulk buyer designed to provide payment certainty between GenCos and DisCos while the market moved toward full commercial operation.
What was thought as the final stage of the reform came with the 2013 privatisation of PHCN successor companies which was handled by Technical Committee of the National Council on Privatisation (NCP) and led by renowned investment banker, Mr. Atedo Peterside. Under the privatisation framework, generation and distribution assets were transferred to private investors, while (for national security concerns) the transmission would remain under federal government ownership through the Transmission Company of Nigeria (TCN). The FGN would later enter into a management contract with Canada-based Manitoba Hydro International (MHI) to operate and manage TCN, with focus on grid‑planning, system‑operation, and market‑operation capacity. The agreement would run into several hiccups and would ultimately be revoked. The privatisation programme itself began with an Expression of Interest (EOI) stage where the BPE received 331 proposals from investors and pre-qualified 207 investor groups. These groups were invited to enter into the Request for Proposal (RfP) stage from which bids were invited for the outright sale of three thermal GenCos, the concession of three hydroelectric power plants, and sale of 60% of the shares of across the eleven DisCos.
BPE retained the services of a Canadian firm, CPCS Transcom as transaction adviser for the DisCo privatisation and adopted an ATC&C loss-reduction model. Rather than requiring bidders to compete on price, each DisCo was assigned a fixed transaction value, while bidders were evaluated on their proposed plan to reduce losses over five years. The bidder offering the highest loss reduction commitment became the preferred bidder. As we shall see, the result of this largely theoretical exercise was that it created a winner’s curse problem because bidders made aggressive commitments for an asset with limited visibility over the underlying customer data, actual asset conditions, and baseline losses.
The logic of privatisation was therefore straightforward: NEPA and its successor PHCN had failed to provide adequate electricity, and government could no longer carry the financial burden of rehabilitating and expanding the sector. Private ownership was expected to bring capital, efficiency, commercial discipline, and better service delivery. Independent regulation was expected to protect consumers and investors, while tariff reform was expected to make the sector financially viable. In theory, the combination of private generation, private distribution, a regulated transmission network, independent regulator, and a transitional bulk trader would create the conditions for a competitive electricity market.
However, this reform design also contained an important weakness. It assumed that changing ownership and improving tariffs would be sufficient to restore the sector’s commercial viability. Yet the pre-privatisation crisis had already pushed many industrial and commercial users into making large-scale investments in self-generation. These users were not simply ordinary customers; they were the high-volume, creditworthy demand base that any electricity market needs in order to become financially sustainable. As a result, the post-privatisation market inherited not only weak assets and poor infrastructure, but also a damaged customer base, weak payment discipline, and a grid that many large users no longer trusted.
Six Design Flaws Embedded in the 2013 Power Sector Privatisation
The comparative literature on power-sector reform provides a useful benchmark for assessing Nigeria’s 2013 electricity privatisation because it shows that reform outcomes depend less on adopting the formal architecture of unbundling, regulation, private participation, and competition, and more on whether the sector has the enabling conditions required for those reforms to work. In the landmark study “Rethinking Power Sector Reform in the Developing World” (Foster and Rana, 2019), the World Bank notes that the standard electricity sector reform model pursued by many developing countries post 1990 has produced uneven results, particularly where market reforms were introduced before the underlying commercial, institutional, and regulatory foundations had been established. This paper, which reviewed power sector reforms between 1990 and 2015 across 88 countries (with 15 in-depth country case studies) notes that the textbook reform model of having well-drafted legal and regulatory frameworks, private participation, and competition rarely worked as a universal template. Instead, the study notes that country outcomes are highly context dependent, and good results have only been achieved through a variety of institutional arrangements, starting conditions and reform sequencing — not only through privatisation.
The first critical design flaw was that Nigeria treated privatisation as an end in itself and not a means to an end. At the heart of the electricity sector reform plan was a desire to drive greater private participation in power generation and distribution. This was in part driven by an implicit analogy to the telecoms sector (as noted in the 2010 Electricity Sector Road Map) that shaped expectations in the lead-up to Nigeria’s power sector privatisation. Nigeria’s successful telecoms liberalisation in 2001 created the impression that privatised infrastructure assets could rapidly unlock pent-up demand once private capital entered the sector. Electricity distribution, however, is structurally different from telecoms. Private operators in the telecoms industry could build parallel networks, grow around prepaid demand while restricting access for non-paying users. In contrast, DisCos inherited monopoly service territories with fragile distribution networks and obligations to serve customers whose payment capacity and willingness to pay were uncertain. The assumption that electricity privatisation could replicate the telecoms liberalisation story underestimated the operational and commercial complexity of power distribution.
Against this telecoms benchmark, Nigeria’s electricity sector reform was unusually ambitious even though the sector was built on commercially-fragile foundations. Rather than first testing private participation in a limited number of commercially-dense urban franchises or allowing public and private distribution models to coexist while the regulatory framework matured, Nigeria transferred the entire distribution segment to private majority ownership at once. The post-privatisation market therefore depended on eleven regional DisCos rapidly reducing losses, improving collections, metering customers, rehabilitating weak networks, and rebuilding consumer confidence, even though the underlying commercial conditions of those franchise areas were highly uneven and, in many respects, poorly understood.
The second design flaw was that distribution was privatised before the distribution business had been made sufficiently commercially knowable. In its review, the World Bank (Foster and Rana, 2019) identified some key enabling conditions for successful distribution privatisation: 1) Cost recovery ratio >70%; 2) revenue collection ratio >90% with enforcement; 3) system losses <15%; 4) electrification rate >80%; 5) internationally-compliant audited financial accounts; 6) modern IT systems for operational data; 7) regular regulatory tariff adjustments; 8) and a politically-supportive environment. In contrast, the DisCo bidding process in Nigeria as advised by the Canadian consultants CPCS Transcom placed heavy emphasis on ATC & C loss-reduction commitments, which made theoretical sense because losses were central to the sector’s commercial failure, but became problematic because the true starting conditions (baseline losses, customer numbers, asset condition, and network quality) were not sufficiently reliable or complete before handover. This created a winner’s-curse dynamic in which bidders were rewarded for aggressive loss-reduction promises in a market where the starting point was uncertain, and where the winning bids could only be fulfilled through levels of investment, enforcement, tariff recovery, and operational capability that many investors were not positioned to deliver. The World Bank’s own assessment of Nigeria’s power sector identified the rapid privatisation of the last mile without robust customer enumeration, asset mapping, or reliable baseline-loss estimates as one of the original flaws of the process.
The third design flaw was the adverse selection created by these weak preconditions. The empirical literature on infrastructure concessions shows that where assets are distressed, information is poor, tariffs are politically uncertain, and regulatory enforcement is weak, the investors most willing to bid are not necessarily those best equipped to execute a technical turnaround. In Nigeria’s case, the weak starting conditions discouraged a deep pool of experienced strategic utility operators and encouraged a bidder profile tilted toward domestic high-net-worth sponsors, politically-connected consortia, purpose-formed acquisition vehicles, and financial buyers willing to accept uncertainty because they expected future tariff adjustments, regulatory accommodation, government intervention, or debt restructuring. The World Bank (2020) paper was unusually direct on this point, identifying the sale of sector companies to high-net-worth Nigerians with limited managerial and technical experience in the power sector as one of the original flaws of the process, while Roy et al. similarly argue that the process produced adverse selection because technically competent international investors had limited appetite for a market where due diligence was weak and political risk was high. (Guasch, 2004; World Bank, 2020; Roy et al., 2023).
The fourth design flaw was the financing structure. The World Bank notes that DisCo acquisitions were funded with leverage of around 70%, that the acquisition loans were denominated in US dollars, and that Naira depreciation after 2016 significantly increased repayment burdens, contributing to weak remittances to NBET and arrears to GenCos and gas suppliers. This was particularly damaging because the new owners were expected to invest heavily in metering, customer enumeration, network rehabilitation, billing systems, and loss reduction, yet many had acquired the assets using debt that had to be serviced from the same weak utility cash-flows that were supposed to fund the operational turnaround.
Most accounts of the 2013 privatisation financing reported that only around 30% of the roughly US$2.5billion spent on the 17 privatised assets came from owner equity, while around 70% came from banks, mostly domestic lenders (World Bank, 2020). To worsen matters, the privatisation also failed to pair asset transfer with a ring-fenced infrastructure financing plan. Although labour union settlement was politically necessary for completing the transaction, the broader weakness was that asset sale completion was not matched by an equally visible programme to channel proceeds and public support into transmission upgrades, distribution rehabilitation, customer enumeration, feeder metering, and end-user metering. In effect, Nigeria transferred distressed assets without ensuring that the financial architecture of the transaction would recapitalise the infrastructure required to make the new market work.
The fifth and most revealing design flaw was NBET itself. The World Bank study (Foster and Rana, 2019) finds that many developing countries that adopted the single buyer model as a transitional step toward competition remained stuck there indefinitely. This is the story of NBET, which was not in the original plan but was incorporated in 2010 under the roadmap plan as a wholly federal government-owned bulk trader. NBET was created with a mandate to buy and sell electricity in the wholesale market, take over federal government’s obligations under existing Power Purchase Agreements (PPAs), and support obligations linked to gas-supply guarantees. This arrangement exposed the internal contradiction of the privatisation design: the reform purported to create a private, contract-based electricity market while simultaneously acknowledging that the newly privatised DisCos were not creditworthy enough to serve as direct counterparties to GenCos and IPPs. Without doubt, NBET was a well-intentioned response to a real problem: the DisCos were not creditworthy enough to support bankable PPAs directly. However, the institution also created a perverse incentive by shielding upstream participants from the full credit risk of the downstream market. What began as a transitional credit bridge became a mechanism through which market failure was converted into receivables against NBET and, ultimately, the federal balance sheet. NBET became less a bridge to a competitive market than a tactical bailout structure for the generation segment, one that helped attract investment into a market whose downstream payment capacity had not been proven. Though this arrangement may have made the privatisation executable, but it also embedded moral hazard into the market.
The industrial exodus dimension compounded these design weaknesses because Nigeria’s grid did not only inherit weak DisCos but also a damaged demand base in which many large commercial and industrial customers had already migrated to captive and self-generation before privatisation was completed. These customers are normally the anchor customers of an electricity market because they consume large volumes, are easier to meter, and provide the stable revenue base needed to support investment. Their prior defection meant that the post-privatisation market was expected to achieve financial sustainability through DisCos that were under-capitalised, under-metered, highly leveraged, operationally unproven, and deprived of precisely the load that could have underpinned sector revenues.
The economics of industrial load exit can be illustrated using a regulated utility average-cost framework. Electricity networks have large fixed and quasi-fixed costs, including distribution infrastructure, transmission charges, system operation, capacity payments, debt service, and regulatory revenue allowances. A cost-reflective tariff is therefore not determined only by the marginal cost of supplying an additional kilowatt-hour of electricity, but by the total revenue requirement spread over effective billable and collectible demand. When industrial users remain on the grid, their high-volume and relatively creditworthy demand lowers the average cost per unit for the system. When they exit into captive generation, the same fixed-cost base must be recovered from a smaller and less reliable customer pool, raising the tariff required for cost recovery. The tariff level pursued in such a market is therefore not the equilibrium of a complete electricity market, but the higher equilibrium of a depleted market.
Lastly, Nigeria’s placed an undue focus on tariff adjustments without underlying improvement in metering and collections. In the cross-country study by the World Bank (Foster and Rana, 2019), cost recovery was very difficult to achieve and sustain, and where progress occurred it came more from efficiency gains and loss reduction than from tariff increases alone. The study notes that average system losses fell from 24% to 17% in countries that improved cost recovery, which means that better collections, lower losses, and improved utility performance are central to financial viability. A cost-reflective tariff imposed on a high-loss, under-metered, low-trust system will not produce a healthy electricity market. Tariff reform must be joined to metering, feeder-level accounting, measurable ATC&C loss reduction, service-quality enforcement, and customer confidence.
The key design flaws can therefore be summarised clearly. Nigeria privatised distribution before the distribution business had been made commercially knowable; it used an ATC&C bidding model that rewarded aggressive promises despite uncertain baselines; it attracted a bidder universe shaped more by domestic financial and political capacity than by deep strategic utility expertise; it allowed dollar-denominated leverage to place debt-service pressure on utilities that needed patient turnaround capital; it used NBET as a sovereign-backed credit wrapper that made GenCos bankable while disguising downstream payment weakness; and it attempted to build a liquid electricity market after many of the industrial customers needed to anchor that liquidity had already moved off-grid.
The central lesson is that reform design must be adapted to starting conditions; countries with weak institutions, high losses, low access, fragile utilities, poor payment discipline, and politically constrained tariffs are unlikely to succeed simply by adopting the formal structure of a liberalised electricity market. It is not that private participation is inherently unsuitable for electricity markets, but that private participation becomes fragile when introduced into a market that lacks the enabling conditions required for private ownership to translate into performance. Nigeria’s privatisation changed ownership faster than it changed incentives, operating capability, data quality, payment discipline, customer confidence, and regulatory credibility. What it ultimately achieved was a formal electricity-market architecture without the commercial foundations of a functioning electricity market, and this gap between legal restructuring and market readiness became one of the structural reasons the post-privatisation sector struggled to deliver reliable power, retain industrial users, attract sufficient investment, or achieve financial sustainability.
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Box 1: Rethinking Power Sector Reform in the Developing World Foster and Rana’s cross-country review of power-sector reforms shows that reform outcomes depend less on whether a country formally adopts privatisation, unbundling, regulation, and competition, and more on whether the reform design fits the country’s starting conditions. Countries with stronger institutions, lower losses, higher electrification, and better cost recovery were more able to sustain ambitious reform, while countries with weak utilities, unreliable data, high losses, and politically-constrained tariffs often experienced reversals, circular debt, or persistent underperformance. The Nigerian experience fits this latter pattern: the 2013 reform created a formal market architecture before the commercial foundations of that market had been established.
Source: Foster and Rana (2019) |
Options for Reviving Nigeria’s Incomplete Power Sector Reform
A credible rescue of Nigeria’s power sector has to begin from a simple premise: adjusting tariffs are necessary, but they are not sufficient. The current reform trajectory has been built largely around targeted tariff increases for higher-consuming customers, especially Band A users, combined with periodic debt refinancing. A higher-tariff model improves the revenue model only where electricity is actually supplied, metered, billed, collected, and remitted; where those conditions do not exist, tariff increases may reduce fiscal subsidies at the margin but will not automatically create a functioning electricity market. It should be underscored that the objective is not a functioning market for its own sake; the objective should be an efficient electricity sector capable of delivering adequate, reliable, and affordable power. A bankable market is necessary because investment, fuel supply, metering, collections, and maintenance require cash-flow and contract discipline, but market bankability is a means to the larger public goal of electricity adequacy and affordability.
Nigeria needs to embark on a comprehensive reset rather than getting fixated on tariff adjustments alone. This would require the government to treat the sector as distressed infrastructure requiring recapitalisation, ownership restructuring, contract enforcement, and industrial-demand recovery, rather than as a tariff problem to be solved by gradually passing higher costs to consumers.
- Restructure distribution: The first priority should be a decisive restructuring of the DisCos because distribution remains the commercial heart of the value chain. Nigeria should move beyond the fiction that all eleven DisCos can be repaired through tariff adjustments alone. The FGN via the Ministry of Power and NERC should conduct a detailed technical and commercial assessment of electricity distribution with the objective of classifying DisCos into three groups: viable utilities that can be recapitalised to fund capex requirements of the distribution zone; weak utilities that require management intervention, sub-franchising, or partial restructuring; and failed utilities that should be placed into regulatory administration, broken into smaller service territories, or re-concessioned to new operators with technical abilities. This segmentation is necessary because NERC’s Q4 2025 data show that every DisCo except Eko (EEDC) failed to meet its ATC&C target, while Kaduna (KEDC) recorded losses of 69.45% against a target of 21.32%. Distribution reform should be practical rather than ideological. Where a DisCo has viable feeders, industrial clusters, or high-payment urban corridors, those areas should be carved into ring-fenced business units with dedicated metering, feeder-level energy accounting, service-level obligations, and enforceable performance targets. Where a DisCo cannot serve a particular area effectively, the regulator should impose the threat of mandatory sub-franchising, embedded distribution concessions, state-backed distribution partnerships, and industrial feeder concessions. The objective should not be renationalisation for its own sake, but the creation of credible distribution operators with the adequate capital to fund capex, technical capacity, and incentives to deliver reliable service.
- Phase down NBET: NBET was created as a transitional credit bridge because DisCos were not creditworthy enough to support bankable PPAs directly, but its continued centrality has allowed market failure to accumulate as claims against the federal balance sheet. Nigeria should therefore stop NBET from entering new PPAs, audit and classify all NBET-related receivables, securitise only verified obligations, cap or renegotiate disputed claims, and gradually novate existing contracts to creditworthy DisCos, eligible industrial customers, licensed traders, embedded generators, and state electricity markets. NBET should remain only as a residual stabilisation vehicle for legacy obligations and non-creditworthy segments, with a clear sunset path and a declining contract book. This transition must be disciplined because direct contracting with weak counterparties would simply move the NBET problem elsewhere. No DisCo or state market entity should inherit NBET contracts unless it provides credible payment security through escrow accounts, letters of credit, revenue locks, guarantees, or other enforceable mechanisms. The transition away from NBET should also be used to create a direct contracting market in which GenCos, embedded generators, state-backed suppliers, and licensed traders can sell power to industrial customers, while DisCos and transmission operators earn transparent wheeling charges for the use of their networks.
- Build a gas-to-power industrial policy backbone: Nigeria needs a credible gas-to-power industrialisation strategy because no country can build a competitive manufacturing economy if electricity generation remains dependent on gas supplied through high-risk private contracts that are inherently expensive. Delivering low-cost gas for power should be treated as part of Nigeria’s industrial policy rather than merely as a private commodity sale. The federal government should create a Gas-to-Power Infrastructure and Industrialisation Fund to finance the delivery of pipelines, processing plants, compression stations, storage, metering, and last-mile gas connections to power plants and industrial corridors. The objective should be to reduce the delivered cost of gas by lowering infrastructure financing costs and payment-risk premiums as against the current approach of setting tariffs for gas producers. This fund should be paired with a commercially-run, government-owned gas infrastructure company that operates on open-access principles, enters long-term gas supply and transportation contracts, and sells gas or gas-transport capacity to GenCos, embedded generators, state electricity markets, and industrial corridors under enforceable payment arrangements. The company should be publicly-owned but commercially-governed, with independent audits, regulated tariffs, project-level accounts, and a prohibition against accumulating hidden arrears. Where government chooses to subsidise gas for public-grid supply or industrialisation, the subsidy should be explicit and budgeted; it should not be hidden through unpaid invoices to gas suppliers. In this model, the public balance sheet is used to finance strategic infrastructure and reduce the delivered gas cost, while payment discipline is preserved through escrow accounts, industrial offtake contracts, state guarantees, and transparent settlement rules.
- Recapture industrial demand and integrate captive capacity through lower gas costs: Nigeria cannot build a financially-viable grid while large industrial and commercial users remain outside it. As such, one cardinal goal of policy must be to work to recapture Industrial load as well as the generation capacity that industrial users have already built. Many large firms invested in gas-fired captive plants because the grid could not provide reliable supply, and those assets should not be stranded or treated simply as evidence of market defection. Therefore, the policy objective should be to deliver a lower cost of gas to captive plants for industrial users as part of an industrial policy bargain that qualifying plants make surplus capacity available to DisCos or state markets on transparent commercial terms. In this way, Nigeria can use industrial captive power not as a competitor to the grid, but as a bridge toward a more decentralised, reliable, and liquid electricity market. The goal would be to make grid-connected or grid-integrated power demonstrably cheaper and more reliable than self-generation — and in doing so, bring high-volume, creditworthy demand back into the formal electricity market.
This approach would address one of the central weaknesses of the current reform trajectory. Nigeria has tried to make the electricity market viable mainly through tariff adjustments, but tariffs cannot stabilise the sector if the fuel supply behind generation is unreliable or financially distressed. A public gas-to-power backbone would allow Nigeria to support low-cost industrial electricity while avoiding another NBET-style accumulation of unpaid obligations. It would also help recapture industrial load by making grid-connected or grid-integrated gas-fired power cheaper and more reliable than isolated self-generation.
- Coordinate decentralisation and protect left-behind states: Nigeria needs to coordinate decentralisation rather than allow it to become balkanisation. Under the Electricity Act 2023, states are now able to regulate intrastate electricity markets, and NERC reported in May 2026 that 15 states had transitioned to state electricity regulation. Nigeria should use decentralisation to build state electricity markets around local demand while creating a federal-state coordination compact covering technical standards, tariff principles, wheeling rules, grid access, consumer protection, cross-border transactions, and dispute resolution. This matters because state electricity markets can help Lagos, Ogun, Rivers, and other industrial states move faster, but without coordination they could also fragment the national market and leave weaker states stranded with poorer customers and weaker infrastructure.
Decentralisation also requires a left-behind states plan. Stronger states may be able to attract embedded generation, industrial PPAs, private distribution concessions, and state-backed electricity markets, but weaker states with low industrial demand, poor metering, weak institutions, and distressed DisCo territories may not be able to do so quickly. Without a federal support mechanism, decentralisation could create a two-tier electricity federation in which bankable states improve while weaker states remain trapped in low supply, poor collections, weak infrastructure, and permanent subsidy dependence.
Nigeria should therefore create a time-bound federal electricity recovery vehicle for distressed territories, operated on commercial principles and with a clear viability timeline. This entity should not recreate NEPA; it should be a transitional platform that completes customer enumeration, feeder mapping, transformer metering, end-user metering, network stabilisation, subsidy targeting, and feeder-level accounts in states or territories that cannot yet attract private capital. Within three to five years, viable feeders or districts should be transferred to state-backed operators, private concessionaires, cooperatives, or sub-franchisees, while the federal vehicle remains only as a last-resort operator where electricity access is still a public-service obligation.
- Roll-out a fully-funded national metering and customer enumeration plan: Nigeria needs to prioritise metering and customer enumeration as part of public infrastructure, not as a narrow DisCo procurement matter. Without customer enumeration, feeder mapping, transformer metering, and end-user metering, Nigeria cannot know where losses occur, which feeders are viable, where subsidies are needed, which customers can pay, and which territories can attract private capital. A national metering plan should complete feeder, transformer, and end-user metering for all high-value customers and premium-service feeders, including industrial, commercial, Band A, and government loads, so that service hours, consumption, billing, collections, and losses can be verified. The plan should also improve enumeration in weaker states and distressed DisCo territories. Stronger states may already have the demand density and institutional capacity to attract private investment, but weaker states will need federal support to generate the customer data and feeder-level accounts required for credible planning. Metering data should feed into a national electricity customer registry that is accessible to NERC, state regulators, DisCos, market operators, and approved state electricity authorities, while protecting customer privacy and preventing multiple taxation or duplicate levies. A national metering and customer enumeration programme should also create a unique, centrally-administered electricity customer ID linked to each verified meter. Such a registry could also support broader financial inclusion as it would create a reliable record of consumption and payment behaviour. With appropriate privacy safeguards and customer consent, this history could become an input into credit assessment for households and SMEs, especially those with limited formal banking records. In this sense, metering reform would not only improve the power sector’s revenue base; it could also deepen Nigeria’s financial credit infrastructure.
- Diversify supply through mini-grids, distributed solar, storage, and regional grids: Rethinking the sector should not mean forcing all demand back onto the national grid. Nigeria’s electricity deficit is too large, and the grid is presently too fragile, for a single-supply model. A credible reform strategy should diversify supply sources while preserving the financial viability of shared networks. Indeed, the World Bank 2019 review noted that market models are not designed to deliver universal electrification, and that access expansion has often required sustained public investment and clear political targets. The way to think of it is that policy focus should be towards ensuring that large industrial users be served through shared network systems, while households, SMEs, and rural communities particularly those outside urban centres in underserved states can be supported through distributed solar mini grids. Policy support can come in the form of government-to-government bulk procurement, local assembly incentives, and low-interest long-tenor financing. Pakistan’s recent solar experience offers a useful lesson as rapid declines in solar-panel costs allowed households and businesses to bypass weak grids and expand electricity access quickly, with large imports of solar panels and batteries. Nigeria should take distributed solar and mini-grids seriously as part of the supply mix but should also avoid creating a new form of untracked load defection. Distributed energy should be integrated through the use of net-billing rules, transparent grid-service charges, concessional consumer finance and planning frameworks that ensure customers who benefit from shared networks contribute fairly to their costs.
Conclusion
Nigeria's power-sector crisis cannot be solved by tariff adjustment alone because the market's weakness is structural. Tariff increases can reduce subsidies and improve revenue where customers are metered and reliably supplied, but it cannot salvage a sector in which DisCos lose over one-third of commercial value through ATC&C losses, gas suppliers remain unpaid, transmission cannot deliver power, and industrial users and households continue to exit the grid.
The key lesson from Nigeria’s post-privatisation experience is not that private participation is inherently wrong, nor that the country should return to the old NEPA model. Rather, that ownership change is not a substitute for market readiness. While the 2013 reforms created a new electricity market, it did not sufficiently address the conditions required for that architecture to work: credible distribution companies, adequate transmission capacity, and a customer base broad and creditworthy enough to support investment.
Nigeria’s unfinished power sector reform therefore requires a shift from tariff fixation to sector reconstruction. Policymakers must focus on restoring financial discipline, reforming distribution, and securing cheaper gas-to-power supply as a means towards integrating industrial captive capacity. To complete the loop, Nigeria must do a lot to better coordinate state electricity markets, execute a national metering for all customers, protecting weaker states, and expanding alternative energy for rural underserved households. Anything less will leave the sector trapped in the same cycle that has defined the post-privatisation decade: higher tariffs without adequate reliability, private ownership without market discipline, and reform announcements without electricity transformation.
Appendix A: 2013 Asset Winners, Investor Profiles, and Financing Evidence
Distribution assets
|
Asset |
2013 winning bidder / core investor |
Investor profile |
Financing / transaction evidence |
|
Abuja DisCo |
KANN Utility Consortium / KANN Utility Co. |
JV between Zambian based Copperbelt Energy Corporation Africa (75%) and Nigerian minorities (25%) |
Acquisition cost was US$164m financed with $122m loan from UBA. |
|
Benin DisCo |
Vigeo Power Consortium |
Domestic corporate (Vigeo Holdings) led by Mr. Victor Osibodu alongside Africa Finance Corporation. Tata Power joined as Technical Partners. |
Acquisition cost was US$129m; financed with acquisition loan from Fidelity Bank and Afreximbank. |
|
Eko DisCo |
West Power & Gas |
Nigerian based consortium comprising: Charles Momoh, Tunji Olowolafe, Tien George, George Etomi, Dere Otubu and others) |
Reported bid around US$135m; . |
|
Enugu DisCo |
Interstate Electrics Ltd |
Domestic politically connected. Sir Emeka Offor (Chrome Group). Technical partner was Metropolitan Electricity Authority of Thailand |
Bid value of US$126m. |
|
Ibadan DisCo |
Integrated Energy Distribution & Marketing Co. |
Politically connected / domestic high-net-worth consortium. Tunde Ayeni and Gen Abdulsalami Abubakar. Technical Partners were Manila Electric Company (Philippines) |
Bid value of US$59m. Largely financed via debt by a consortium of Nigerian banks led by UBA. |
|
Yola DisCo |
Integrated Energy Distribution & Marketing Co. |
Same investor profile as Ibadan. |
Acquisition US$146m. Financed via debt by a consortium of Nigerian banks led by UBA. |
|
Ikeja DisCo |
NEDC / KEPCO consortium |
Domestic Consortium comprising Sahara Group. Technical Partner was Korea Electric Power Corporation (KEPCO) |
Reported bid around US$131m; UBA states that it financed the 75% balance payment for the 60% stake acquisition. |
|
Jos DisCo |
Aura Energy |
Domestic financial/corporate sponsor. |
Reported bid around US$81.9m |
|
Kano DisCo |
Sahelian Power SPV |
Consortium comprising the Dantata Group, Umaru Abdul Mutallab, Kashim Shettima Bukar and others. |
Reported bid around US$102m; later creditor action by Fidelity Bank and Afreximbank following acquisition-loan problems. |
|
Port Harcourt DisCo |
4Power Consortium |
State-linked / regional consortium associated with Niger Delta interests. (Bayelsa, Akwa Ibom, Taleveras and others). Technical Partner was Indian based Calcutta Electricity Supply Company. |
Reported bid around US$130m |
|
Kaduna DisCo |
North-West Power Consortium / Ltd |
North West Consortium comprising Tajudeen Dantata, Adamu Mustapha, Abubakar Yussuf and Jamil Gwamna |
Preferred bidder after main 2013 process; later taken over by Afreximbank and Fidelity Bank following debt problems; Reuters reported sale process around US$130m debt. |
Generation assets and hydro concessions
|
Asset |
2013 winning bidder / core investor |
Investor profile |
Financing / transaction evidence |
|
Geregu Power |
Amperion Power Co. |
Domestic corporate / energy-investor profile. Mr. Femi Otedola via his Calvados Group and State Grid Shanghai Municipal Electric Power Company |
Reported bid around US$132m for 51%; |
|
Ughelli Power |
Transcorp / Woodrock Consortium |
Domestic conglomerate / corporate sponsor. Transcorp Group. |
Reported bid around US$300m; UBA states it provided US$120m financing for the Ughelli acquisition. |
|
Sapele Power |
CMEC / Eurafric JV |
Eurafric is promoted by Mr Anthony Onoh held 95% of the JV with the rest held by China Machinery Engineering Corp (CMEC) as the technical partner |
Reported bid around US$201m; financed with US$140million in debt sources including Afrexim (US$51million) |
|
Kainji / Jebba Hydro Concession |
Mainstream Energy Solutions Ltd |
MESL Consortium comprises: Colonel Sani Bello (Rtd) with direct and indirect (via All Energy Solutions) stakes cumulatively at 67% and the rest held by Nigerian Businessman Tunde Afolabi via Amni Petroleum (33%). |
Concession arrangement comprising an Annual fee of US$50.8m and Commencement fee US$257m; |
|
Shiroro Hydro Concession |
North-South Power Co. |
NSP Consortium comprising Niger State (26%), Ibrahim Aliyu via Urban Shelter (19%), Bunmi Peters (16%), CEC Africa (20%) and others |
Concession arrangement comprising an Annual fee of US$24m and Commencement fee US$112m; |
|
Afam Power |
Taleveras Group |
Domestic oil-and-gas / energy-trading sponsored by Igho Sanomi |
Preferred bidder with reported US$260.05m bid; transaction completion was problematic and initially inconclusive. |
|
Egbin Power |
KEPCO Energy Resources / Sahara Power Group |
Sahara Group |
70% of federal government stake sold for US$407.3m; specific acquisition debt structure not fully disclosed in public sources reviewed. |
Source: BPE, NERC, Author’s Compilation.
References
Bureau of Public Enterprises. (2018). Final Review of the Performance of the Privatised Electricity Distribution Companies (DisCos). Bureau of Public Enterprises.
Foster, V., & Rana, A. (2019). Rethinking Power Sector Reform in the Developing World. Washington, DC: World Bank.
Guasch, J. L. (2004). Granting and Renegotiating Infrastructure Concessions: Doing It Right. Washington, DC: World Bank.
National Council on Privatisation. (2012). NCP Approves Recent Bids for PHCN’s GENCOs and DISCOs. NigeriaFirst / National Council on Privatisation.
Nigerian Bulk Electricity Trading Plc. (n.d.). Our Mandate. NBET.
The Nigerian Electric Power Sector Reform Act 2005
Nigerian Electricity Regulatory Commission. (2024). Order on the Transition to Bilateral Trading in the Nigerian Electricity Supply Industry, Order No. NERC/2024/058.
Oxford Business Group. (2015). Privatisation of Power Generation Assets in Nigeria. Oxford Business Group.
The Presidential Action Committee on Power (2010). Road Map for Power Sector Reform (A Customer Driven Sector-Wide Plan to Achieve Stable Power Supply).
Roy, P., Watkins, M., Iwuamadi, C. K., & Ibrahim, J. (2023). Breaking the cycle of corruption in Nigeria’s electricity sector: Off-grid solutions for local enterprises. Energy Research & Social Science, 101, 103130.
Reuters. (2024). Nigeria Hikes Electricity Tariff for Bigger Consumers in Subsidy Cut. https://www.reuters.com/world/africa/nigeria-hikes-electricity-tariff-bigger-consumers-subsidy-cut-2024-04-03/
Reuters. (2025). Nigeria Cuts Electricity Subsidies by 35% After Tariff Hike. https://www.reuters.com/world/africa/nigeria-cuts-electricity-subsidies-by-35-after-tariff-hike-2025-04-17/
World Bank. (2020). Nigeria — Power Sector Recovery Operation. Washington, DC: World Bank
