In Part I, we established that Nigeria had 13,625 megawatts of installed grid-connected generation capacity, but only about 5,174 MW was available on average between April 2025 and March 2026, according to quarterly reports by the Nigerian Electricity Regulatory Commission (NERC). Part II showed that generation averaged 4,312 MW. Part III followed that electricity into the eleven Distribution Companies (DisCos): they received 30.31 terawatt-hours (TWh), billed only 25.20 TWh, issued about ?3.00 trillion in customer bills and collected ?2.36 trillion. Their Aggregate Technical, Commercial and Collection (ATCandC) loss was about 35.9%.
Part IV, which completes the series, traces the financial chain.Across the twelve months, the 28 grid-connected plants operated by Generation Companies (GenCos) generated about 37.77 TWh. NERC’s transmission-loss identity indicates that 2.93 TWh was lost in transmission or consumed at substations and 30.31 TWh reached domestic DisCos, implying about 4.53 TWh went to international customers.The export ledger remains incomplete. The quarterly reports do not disclose the energy-sale invoices or settlements for the estimated 4.53 TWh. The US$74.15 million identified for international customers represents Market Operator service invoices-not the electricity’s full sale value.
The GenCoinvoice
NERC’s ?3.14 trillion total GenCo invoice covers electricity delivered to domestic DisCos, not all 37.77 TWh generated. For the 30.31 TWh received, the invoice averaged ?103.59 per kilowatt-hour.But the reports do not show how much each GenCo invoiced. That breakdown is important: it would allow comparison of individual GenCo invoices with plant availability in Part I and actual generation in Part II.
Under NERC’s DisCo Remittance Obligation (DRO) framework, about ?1.39 trillion was assigned to DisCos through DRO-adjusted invoices from the Nigerian Bulk Electricity Trading Plc (NBET), while ?1.75 trillion became a Federal Government tariff-subsidy obligation.The reports do not establish how much government actually settled during the period.
Put simply, about ?45.85 per kilowatt-hour was assigned to DisCos, and ?57.74 became Federal Government subsidy obligation. NBET bills DisCos for their DRO-adjusted share and the Federal Government for the balance.
These figures cover generation costs only, excluding transmission and market charges and DisCos’ operating and allowed revenue requirements. Customer tariffs vary across service bands. Band A customers pay tariffs much closer to cost-reflective levels, while Bands B-E remain subsidised.How much of the ?1.75 trillion subsidy obligation was associated with electricity supplied to each of Bands B-E, how much electricity did each receive, and were promised hours delivered? NERC should publish these data by DisCo and service band.Against the 25.20 TWh billed, the ?1.75 trillion obligation equals ?69.44 per billed kilowatt-hour-an analytical ratio, not a NERC tariff. It exceeds ?57.74 per kilowatt-hour received because 5.11 TWh was not billed, reinforcing Part III’s conclusion that reducing ATCandC losses is central to market sustainability.
The DisCos also had ?320.76 billion in Market Operator obligations for transmission and market services, bringing their combined adjusted NBET and MO obligations to about ?1.71 trillion.They remitted ?1.61 trillion, leaving about ?96.7 billion unpaid during the period under review.
Who gets the most subsidy?
Using Part III’s ATCandC categories-Strong, Moderate, Poor and Critical-the government share of associated GenCo invoices rises as DisCo performance deteriorates: 50.6% for Strong DisCos; 54.9% Moderate; 57.4% Poor; and 65.2% Critical.Yola had the highest share of its associated GenCo invoice covered by Federal Government subsidy, at 78.8%, followed by Kaduna at 64.7%. Yet the largest subsidy amounts in absolute naira were associated with higher-volume networks: Abuja, about ?256.3 billion; Ikeja, ?244.4 billion; Ibadan, ?219.5 billion; and Eko, ?206.5 billion.Percentage subsidy share measures dependence; absolute subsidy amount measures fiscal exposure. A smaller DisCo can therefore have a high subsidy share but modest naira amount, while a large-volume DisCo can have a lower share yet a much larger obligation.
While ATCandC measures how effectively electricity supplied to a DisCo becomes collected revenue, subsidy share and amount are shaped mainly by supply volume, allowed tariffs, service-band mix and generation cost. High ATCandC losses matter indirectly by weakening revenue recovery and a DisCo’s abilityto meet its market obligations. This distinction can guide targeted subsidies for productive small businesses and industrial users across the country.
How can the subsidy burden fallwithout burdening Nigerians?
NERC reported that in Q4 2025 Band A’s share of grid energy increased from 40% to 45%, while the quarterly subsidy obligation fell from ?458.75 billion to ?418.79 billion. It identified the increased Band A allocation as the principal driver.
However, this raises a distributional question: how should scarce electricity be allocated while protecting productive and vulnerable users? NERC should publish, by DisCo and service band, energy allocated, actual hours delivered and associated subsidy. The larger challenge is to reduce the fiscal burden without putting reliable, affordable electricity beyond the reach of productive users outside Band A.
The ?57.74 per kilowatt-hour subsidy burden can be reduced through several interventions.
Generation costs can fall through a more economic energy mix, efficient thermal plants, lower gas costs and stronger merit-order dispatch. In Q2 2025, Shiroro, Jebba and Zungeru hydropower plants were dispatched at 74.79%, 74.42% and 70.47%, respectively-below the 90% minimum under NERC’s mandatory-priority dispatch order for hydro, the cheapest generation source. Greater use of lower-cost hydro and utility-scale solar, particularly in Northern Nigeria where daily solar radiation reaches about 7 kWh/m²/day compared with about 4 kWh/m²/day in the South, could further lower generation costs.
System costs can fall through lower transmission losses, while better metering, billing and collection can enable DisCos to carry larger DROs without creating new arrears. More cost-reflective tariffs can also reduce subsidy, but tariff reform without improved efficiency and service risks transferring system failure to consumers.
Illustratively, a 10% reduction in the ?103.59/kWh GenCo invoice, with DRO unchanged, would reduce Federal Government subsidy by roughly ?314 billion. If lowering DisCo ATCandC losses from 35.9% to 25% enabled a sustainable ?10/kWh DRO increase, another ?303 billion could be saved. Together, the ?1.75 trillion obligation could fall by about ?617 billion, to roughly ?1.13 trillion.
A further option is structured federal-state co-funding of targeted subsidies. Under a 70:30 formula, the Federal Government would fund 70% of the subsidy for eligible consumers in each state, while states would fund 30%. Contributions would therefore vary with each state’s subsidy exposure, so larger electricity markets would contribute more in naira terms. Applied to the illustrative ?1.13 trillion remaining subsidy, the Federal Government’s burden would fall to about ?790 billion, with states providing about ?340 billion. Support could target productive small and medium-sized businesses, farms and factories that pay taxes, raising output, jobs and, over time, states’ internally generated revenue. These scenarios show that subsidy reduction need not depend principally on higher tariffs. It can also come from lower generation and system costs, better revenue recovery and targeted federal-state intervention.
Conclusion
Government says legacy power-sector debts accumulated between February 2015 and March 2025 were agreed at ?3.3 trillion as full and final settlement, with a ?501 billion inaugural bond already issued. Our period under review begins on April 1, 2025-immediately after that legacy-debt period. The question is whether the post-March 2025 market can prevent today’s shortfalls from becoming tomorrow’s legacy debt.
Government also intends to phase out electricity subsidies in 2027. It has announced a Power Sector Reset and other reform initiatives, but the key question is whether these will become an integrated, sequenced restructuring programme before subsidy withdrawal. The public needs to see how the 2027 phase-out will be tied to measurable improvements across the electricity value chain.
The four-part series has shown that Nigeria’s electricity crisis is a chain of failures. Breaking that chain requires fixing the system as a whole, not merely changing who pays for its failures.