The Physical and Financial Losses in Nigeria’s Power Sector (Part III): 5.11 TWh Unbilled, ₦637.5 Billion Uncollected

In Parts I and II, we followed Nigeria’s grid electricity from installed capacity to available capacity and actual generation, using Nigerian Electricity Regulatory Commission (NERC) data from April 2025 to March 2026. Of 13,625 megawatts (MW) installed, only about 5,174 MW was available on average and about 4,312 MW was generated.

Part III now examines the electricity that reached the eleven Distribution Companies (DisCos): how much was accounted for and billed, how much of the bills became cash, and why some DisCos perform much better than others.

Electricity Received, Billed and Cash Implications

During the twelve months, the DisCos received about 30.31 terawatt-hours (TWh) of electricity at their trading points but billed customers for only about 25.20 TWh. About 5.11 TWh—more than five billion kilowatt-hours, or “units” as consumers commonly call them—did not become billed energy. In other words, for every 100 units received by the DisCos, about 83 units were billed to customers and roughly 17 were not.

The unbilled electricity reflects a combination of physical losses through distribution lines and transformers and commercial losses arising from inaccurate metering, unmetered consumption, meter bypass, erroneous billing, poor customer enumeration and electricity theft.

Across the four quarterly reports, NERC’s reported values for electricity supplied to the DisCos sum to about ₦3.69 trillion. Dividing that value by the 30.31 TWh received gives an implied weighted-average value of about ₦121.68/kWh. This is not a wholesale tariff or an NBET invoice rate, but an analytical average derived from NERC’s reported energy and monetary values.

Customer bills totalled about ₦3.00 trillion for 25.20 TWh of billed energy, implying an average billed rate of about ₦119.07/kWh. Because customers pay different tariffs according to service band and customer category, this is also a weighted system-wide average rather than a uniform retail tariff.

Roughly ₦688 billion of potential billing value therefore did not become customer bills. Of the approximately ₦3.00 trillion actually billed, only about ₦2.36 trillion was collected, leaving roughly ₦637.5 billion uncollected.

The DisCos therefore converted about 81.4% of the value of electricity supplied into customer bills and collected about 78.8% of those bills. Put together, only about 64% of the original value of electricity supplied became collected revenue.

Put simply, for every ₦100 worth of electricity supplied to the DisCos, only about ₦81 became customer bills. Roughly ₦17 of the original ₦100 was billed but not collected, leaving only about ₦64 in cash.

These two stages are combined in a common distribution measure called Aggregate Technical, Commercial and Collection (ATC&C) loss:

ATC&C loss = 1 − (Billing Efficiency × Collection Efficiency).

Using the twelve-month figures, Nigeria’s eleven DisCos recorded an aggregate ATC&C loss of about 35.9%.

How Does Nigeria Compare?

India provides a useful international benchmark, although the methodologies are not perfectly identical. In FY2024/25, India recorded a national AT&C loss of 15.04%, with billing efficiency of 87.59% and collection efficiency of 97%. The larger difference is in collections: about 79% in Nigeria against 97% in India.

Ghana’s two principal distribution utilities report ATC&C losses of about 25%. In Pakistan, K-Electric’s FY2024/25 T&D-loss and revenue-recovery figures imply an AT&C loss of about 22.8%. Reporting systems differ, but all three benchmarks are substantially better than Nigeria’s 35.9%.

Nigeria’s distribution losses are therefore not an unavoidable feature of supplying electricity in a developing economy.

DisCos Performance Classification

The aggregate figure conceals enormous differences among the eleven DisCos. I calculated a day-weighted twelve-month average of each DisCo’s quarterly ATC&C losses and classified them as Strong at 25% or lower; Moderate at above 25% up to 40%; Poor at above 40% up to 55%; and Critical above 55%. These are my analytical classifications, not NERC ratings.

Only two DisCos were Strong: Eko at 15.4% and Ikeja at 18.2%.

Three were Moderate: Abuja at 32.1%, Port Harcourt at 36.3% and Enugu at 39.8%.

Three were Poor: Benin at 43.1%, Kano at 43.8% and Ibadan at 44.2%.

And three were Critical: Yola at 58.0%, Jos at 61.1% and Kaduna at 70.3%.

Six of the eleven DisCos therefore lost more than 40% of the potential revenue represented by electricity supplied to them. Kaduna’s roughly 70% ATC&C loss means, broadly, that only about ₦30 of every ₦100 of potential revenue became collected revenue.

Why Such Wide Differences?

Metering provides one important clue. As of March 2026, 88.50% of Eko’s active customers and 87.96% of Ikeja’s were metered—the two highest rates among the eleven DisCos. By contrast, the three Critical DisCos had much lower metering rates: Yola 33.16%, Jos 34.58% and Kaduna 36.43%. Nationally, only 59.13% of active registered customers were metered.

Geography and economics also matter. Eko and Ikeja serve densely populated Lagos, with concentrated commercial and industrial demand and a strong network backbone. Yola, Jos and Kaduna cover much larger territories containing many less densely populated and lower-income communities. Lower purchasing power can affect collections, while dispersed settlement requires longer networks and greater infrastructure investment.

But the relationship is not absolute. Ibadan serves Ogun and important industrial corridors yet falls in the Poor category; Benin serves economically important states including Ondo, Edo and Delta but is also Poor. Performance therefore appears to reflect an interaction among metering, customer density, purchasing power, economic activity, distribution-network condition, transmission access and management effectiveness.

Conclusion and Recommendations

The forensic chain is becoming clearer. Of Nigeria’s 13,625 MW installed capacity, only about 5,174 MW was available and about 4,312 MW was generated on average. The DisCos then received 30.31 TWh but billed only 25.20 TWh. They issued bills worth about ₦3.00 trillion but collected only about ₦2.36 trillion.

For every ₦100 worth of electricity supplied to Nigeria’s DisCos, only about ₦64 ultimately became collected revenue.

Nigeria’s 35.9% ATC&C loss compares poorly with India’s 15.04%, K-Electric’s approximately 22.8% in Pakistan and Ghana’s roughly 25%. Within Nigeria, the disparity is equally striking: only two of eleven DisCos were Strong, while six were Poor or Critical.

These comparisons show that such losses are neither inevitable nor simply a consequence of Nigeria’s size or development challenges. There is substantial recoverable value in electricity already generated. The remedies should follow the causes: network rehabilitation for technical losses; enforcement against meter bypass and theft; metering and accurate enumeration for unmetered customers; and credible billing, customer service and stronger collection systems.

Accountability must also improve. Under the Service-Based Tariff, Band A customers are promised at least 20 hours of supply daily, Band B 16 hours, Band C 12 hours, Band D 8 hours and Band E 4 hours. Yet the quarterly reports do not provide a simple DisCo-by-DisCo account showing what share of electricity went to Bands A–E and whether each band received its promised hours. While Band A tariffs are much closer to cost-reflective levels, Bands B–E remain supported by Federal Government tariff subsidy. Such reporting would help the public see what service taxpayers are subsidising and whether it is actually being delivered.

Nigeria therefore needs a transparent Distribution Recovery Account tracking electricity from each DisCo’s trading point to customers. NERC should require publication, by DisCo, of energy received and billed, technical and commercial losses, billing value, revenue collected, metering rate, ATC&C loss and principal causes. It should also publish, by service band, electricity allocated, actual average hours delivered and the percentage of feeders meeting their service commitments.

That takes us to Part IV, where we follow the money upstream. After these losses, how much did the DisCos remit to the electricity market, how much did the GenCos invoice, how much did the Federal Government subsidise—and who ultimately carried the burden?