Nigeria's federal government still pays for about half the electricity that its distribution companies buy. The Nigerian Electricity Regulatory Commission (NERC) said so directly in its report for the second quarter of 2026, published at the end of September: because end-user tariffs remain "frozen at the rates payable in July 2024", the government covers roughly 50% of generation costs. The obligation for April to June 2026 was ₦321.26 billion, or 49.60% of the ₦647.72 billion that generation companies invoiced for power delivered to the eleven DisCos.
A year earlier the same line was ₦514.35 billion, 59.60% of a ₦863.02 billion invoice. The year-on-year fall is ₦193.09 billion, or 37.5%. Tariffs did not move over that period for most customers, so the question is where the saving came from.
NERC's quarterly reports give a different driver each quarter. Its second-quarter 2026 report attributes the latest decline to a 3.40% fall in DisCo offtake. Earlier reports cited lower offtake and a 0.98% lower generation cost per kilowatt-hour (third quarter 2025), and an increase in the share of energy allocated to Band A customers from 40% to 45% (fourth quarter 2025). None of the reports puts the four quarters side by side. TEI took the six reports covering January 2025 to June 2026 and rebuilt the series from their own totals.
How the subsidy is calculated
Under the DisCo Remittance Obligation (DRO) regime, which replaced the Minimum Remittance Obligation in January 2024, the Nigerian Bulk Electricity Trading company (NBET) bills each DisCo only the part of the GenCo invoice that the DisCo's allowed tariffs can cover. The rest, in NERC's words, NBET "directly invoices … to the Federal Ministry of Finance for immediate settlement". The subsidy is therefore an arithmetic residual: the total GenCo invoice minus the DRO-adjusted invoice to DisCos. In the second quarter of 2026 that was ₦647.72 billion minus ₦326.46 billion. The residual checks to within ₦0.01 billion in every quarter from April 2025 onward.
The cost side moves every month. NERC's monthly supplementary orders to the Multi-Year Tariff Order (MYTO) 2024 update the naira exchange rate, inflation, available capacity and the gas price used to set each DisCo's cost-reflective tariff. The July 2025 order for Kaduna Electric, for example, used ₦1,566.49 to the dollar, a gas-to-power price of $2.13/MMBtu, and a generation cost of ₦109.4/kWh against a weighted allowed tariff of ₦113.0/kWh, leaving a projected shortfall of ₦14.1 billion a month for that DisCo alone. The allowed tariff side is fixed: Band A at ₦209.50/kWh since July 2024, Bands B to E at their December 2022 levels.
Because the allowed tariffs are fixed, the subsidy moves with three things: how much energy the DisCos take, what that energy costs per kilowatt-hour, and how the DisCos' sales are split between the high-tariff Band A and the cheaper bands.
The series
The table below uses energy received by the DisCos (offtake) as the denominator, which is the energy the GenCo invoice pays for. All naira figures are from NERC's quarterly reports; the per-kilowatt-hour figures are TEI's division.
- Q2 2025: offtake 7,824.43 GWh; GenCo invoice ₦863.02bn (₦110.30/kWh); DRO ₦348.66bn (₦44.56/kWh); subsidy ₦514.35bn (₦65.74/kWh)
- Q3 2025: offtake 7,348.95 GWh; GenCo invoice ₦782.46bn (₦106.47/kWh); DRO ₦323.70bn (₦44.05/kWh); subsidy ₦458.75bn (₦62.42/kWh)
- Q4 2025: offtake 7,991.22 GWh; GenCo invoice ₦804.93bn (₦100.73/kWh); DRO ₦386.13bn (₦48.32/kWh); subsidy ₦418.79bn (₦52.41/kWh)
- Q1 2026: offtake 7,148.47 GWh; GenCo invoice ₦689.72bn (₦96.48/kWh); DRO ₦331.40bn (₦46.36/kWh); subsidy ₦358.32bn (₦50.13/kWh)
- Q2 2026: offtake 6,982.32 GWh; GenCo invoice ₦647.72bn (₦92.77/kWh); DRO ₦326.46bn (₦46.76/kWh); subsidy ₦321.26bn (₦46.01/kWh)
The GenCo invoice per kilowatt-hour fell in every one of the four quarters after the second quarter of 2025, by 15.9% in total. The DRO per kilowatt-hour, which is what customers' tariffs can carry, rose by ₦2.20 over the same year, with most of the step in the fourth quarter of 2025, when the Band A allocation went up.
Splitting the ₦193 billion
A standard decomposition separates the year-on-year change into a volume effect, a cost-per-unit effect and a DRO-per-unit effect. Holding the Q2 2025 subsidy rate of ₦65.74/kWh and applying it to the 842.11 GWh fall in offtake gives the volume effect. The cost effect is the Q2 2026 offtake multiplied by the ₦17.53/kWh fall in the GenCo invoice per unit. The DRO effect is the same volume multiplied by the ₦2.20/kWh rise in the DRO per unit, which reduces the subsidy because DisCos cover more of each unit.
By TEI's calculation:
- Lower offtake: −₦55.36 billion, 28.7% of the fall
- Lower GenCo cost per kWh: −₦122.42 billion, 63.4%
- Higher DRO per kWh (tariff mix): −₦15.32 billion, 7.9%
The three parts sum to −₦193.10 billion against the reported −₦193.09 billion; the ₦0.01 billion gap is rounding in NERC's tables. Reordering the calculation shifts the shares by a few points without changing the ranking.
Lower consumption contributed. Offtake fell 10.8% year on year and generation fell 10.6%, from 9,830.31 GWh to 8,784.93 GWh. The cheaper kilowatt-hour counted for more than twice as much.
The quarterly reports do not explain that unit cost decline in any of the 2026 editions. Some of the physical evidence points in the expected direction. Hydropower supplied 30.19% of generation in the second quarter of 2025 and 34.22% in the second quarter of 2026, and NERC's own footnote on subsidy risk names "generation cost variation arising from changes in supply mix (more thermal = higher generation cost)". Hydro's share peaked at 38.31% in the fourth quarter of 2025, the quarter in which the cost per kilowatt-hour dropped most sharply in naira terms. The other levers are the exchange rate and gas price inputs in the monthly MYTO orders, since the gas price in those orders is set in dollars. TEI has not reconstructed those inputs month by month, so the split between plant mix and currency is left open here.
Cash, as distinct from obligations
The subsidy is an obligation booked by NBET against the Ministry of Finance. What customers actually pay is a separate series, and here the trend runs the other way.
DisCo collections were ₦564.71 billion in the second quarter of 2025 and ₦603.64 billion a year later, up 6.9% even though offtake fell 10.8%. Per kilowatt-hour of energy received, collections rose from ₦72.17 to ₦86.45. Set against the falling GenCo cost per unit, the gap between what customers pay and what generation costs has nearly closed:
- Q2 2025: DisCo collections equal to 65.4% of the GenCo invoice
- Q3 2025: 72.9%
- Q4 2025: 78.4%
- Q1 2026: 86.6%
- Q2 2026: 93.2%
That ratio overstates how close the market is to paying its own way. Collections have to fund transmission charges, the market and system operators, DisCo operations and any network investment, on top of generation. The NBET remittance alone, which is the cash that reaches GenCos through the DRO, covered 47.3% of the GenCo invoice in the second quarter of 2026 (₦306.62 billion of ₦647.72 billion), against 38.7% a year earlier. In every quarter of the series the federal obligation was larger than the cash DisCos sent to NBET; the margin has narrowed to ₦14.64 billion.
Collection efficiency itself improved, from 76.07% of billed revenue to 81.06%. Energy billed as a share of energy generated stayed near two-thirds (65.61% a year ago, 66.16% now), which reflects transmission losses and the DisCos' aggregate technical, commercial and collection losses. Those losses were 36.23% in the second quarter of 2026, against a regulatory target of 16.92%; NERC valued the revenue lost to the excess at ₦129.07 billion for the quarter. Kaduna Electric's figure was 67.70%.
Overall remittance performance slipped slightly. In the second quarter of 2026 the DisCos remitted ₦385.44 billion of the ₦410.38 billion billed to them by NBET and the Market Operator together, or 93.92%, against 95.65% a year earlier. NERC reconciled the latest figures as of 23 September 2026, so they may still change.
The monthly trajectory
NERC reports the subsidy by month in footnotes. From April 2025 to June 2026 the monthly figure went from ₦175.35 billion to ₦99.93 billion, a fall of 43.0%. Five months rose on the month before (May, July and October 2025, January and May 2026), none by more than ₦12 billion. June 2026 was the first month in the series below ₦100 billion. Per day, the obligation went from about ₦5.84 billion in April 2025 to ₦3.33 billion in June 2026.
Summed, the five quarters from April 2025 to June 2026 carried a subsidy obligation of ₦2.07 trillion. The first half of 2026 accounted for ₦679.58 billion, compared with ₦1,050.75 billion in the first half of 2025.
These are obligations. The reports do not show how much the Ministry of Finance actually paid NBET against them. The government's separate bond programme, approved by the Federal Executive Council in August 2025 to settle verified legacy debts to GenCos and gas suppliers, has raised about ₦1.23 trillion across two series, according to statements by NBET and the finance ministry reported in September 2026. That programme addresses arrears from earlier periods; it does not tell us whether the 2025–26 monthly obligations were paid as they fell due.
The cross-border customers
NBET and the Market Operator also bill Nigeria's international bilateral customers, the utilities in Benin (SBEE), Togo (CEET) and Niger (NIGELEC) that buy power from Nigerian plants under bilateral arrangements. These customers paid $8.67 million of $18.84 million in Market Operator invoices in the second quarter of 2026, or 46.02%. The payment rate across the series has been erratic: 51.33% in the second quarter of 2025, 38.09% in the third, 53.28% in the fourth, and 27.57% in the first quarter of 2026. In the latest quarter the Transcorp-SBEE and Odukpani-CEET arrangements paid nothing, while Mainstream-NIGELEC paid in full.
The amounts are small relative to the domestic subsidy, about $10.17 million unpaid in one quarter. They matter for the West African Power Pool, where Nigerian supply to Benin, Togo and Niger is a long-standing part of cross-border trade. A regional market would have to price the counterparty risk that this payment record shows.
What would reverse the trend
The NERC footnote on subsidy risk describes the regime as "open-ended", leaving the government exposed to volume and supply-mix risk. Both risks cut both ways. A recovery in offtake, which the government wants, raises the subsidy unless it comes with more Band A allocation or a tariff change; at the Q2 2026 average rate of ₦46.01 per kilowatt-hour, every additional 100 GWh delivered to DisCos adds about ₦4.6 billion. A dry year at Kainji, Jebba, Shiroro and Zungeru would push the mix back toward gas and raise the unit cost.
The Band A lever has been used once in the series, in the fourth quarter of 2025, and NERC named it the key driver of that quarter's drop in the subsidy share. Further increases shift cost onto customers with at least 20 hours of supply a day, who already pay ₦209.50/kWh, more than double the current GenCo cost per unit received.
Regulatory oversight is also fragmenting. Under the Electricity Act 2023, states can take over regulation of their own electricity markets; NERC's first-quarter 2026 report lists the transfer of oversight in Gombe State to the state commission. State-regulated DisCos may set tariffs differently, and the national subsidy figure will cover a shrinking footprint.
Method notes
All energy and naira figures come from NERC's quarterly reports for the second quarter of 2025 through the second quarter of 2026. Per-kilowatt-hour figures divide the naira totals by DisCo offtake (energy received) for the same quarter. The decomposition uses the earlier quarter's subsidy rate for the volume effect and the later quarter's volume for the rate effects. The fourth-quarter 2025 report states the subsidy share as 52.30%; its own table gives ₦418.79 billion of ₦804.93 billion, which is 52.03%, the figure used in the next report and here. The first-quarter 2026 report restates fourth-quarter 2025 billed energy as 6,627.57 GWh against 6,614.57 GWh in the original report; the original is used here and the difference does not affect any subsidy figure. The data and calculation script are held by TEI.