Why DisCos Must Fix ATC&C Losses Before the Next Tariff Review

A quarter-by-quarter read of NERC’s 2025 and 2026 reports tells a plain story: the sector stopped improving just as the loss target got stricter, and without a step-change, the next tariff adjustment will be calculated against a gap that is widening, not closing.

A field technician completes maintenance on a distribution transformer. Metering and feeder-level maintenance quality are the strongest predictors of ATC&C performance across Nigeria’s DisCos. Illustrative.

Nigeria’s electricity distribution companies lost 37.44% of the energy delivered to them in the first quarter of 2026, to faulty meters, unbilled consumption, and uncollected bills. Read against the sector’s own recent numbers, that reading is a step backwards: 2.5 points worse than the 34.90% of Q4 2025, and 4.2 points worse than the 33.27% of Q3 2025, the best quarter of the current MYTO era. Only against the very start of 2025, Q1’s 39.61%, does Q1 2026 look like an improvement, and a slender one at that. The gap between what regulation demands and what the network actually delivers has not been closing across 2025 into 2026. It has been widening, even as the target itself got stricter.

This is GridIQ’s read of NERC’s quarterly reports across 2025 and into 2026, five consecutive quarters of Aggregate Technical, Commercial & Collection (ATC&C) loss data, cross-checked against billing and collection efficiency, DisCo-level performance, and the Naira value of what regulation says should have been collected and wasn’t. Placed side by side, the reports show the same thing from every angle: the improvement that carried the sector from 2022 to mid-2024 did not extend into 2025, and 2026 has opened by giving back most of 2025’s best quarter.

2025 Into 2026: The Year the Curve Went Flat

The five quarters that matter for the next tariff review run from Q1 2025 to Q1 2026, and they do not trend. The sector opened 2025 at 39.61%, improved for two quarters to a genuine low of 33.27% in Q3, the best reading of the current MYTO era, then reversed: 34.90% in Q4 2025 and 37.44% in Q1 2026. That is two consecutive quarters of deterioration, erasing more than three-quarters of the gain made in the first three quarters of 2025. A line that ends higher than it began, having briefly gone lower, is not progress interrupted. It is a plateau with noise on it.

The annual averages remove the noise and make the point bluntly: 36.34% in 2024, 36.43% in 2025, statistically identical, despite a full year passing and despite MYTO tightening the sector target from 20.54% for 2025 to 16.92% for 2026, a 3.6-point cut. The result is a gap to target that widened by 6.16 points in a single quarter, from 14.36pp at the end of 2025 to 20.52pp at the start of 2026: the loss rate rose 2.54 points and the bar dropped 3.62 points at the same moment. At the pace the sector actually moved across 2025, closing the remaining gap to the 2026 target is a matter of years, not the one or two the tariff calendar assumes.

A Collection Problem, Not Just a Technical One

ATC&C loss is a compound figure: 1 − (Billing Efficiency × Collection Efficiency). Billing efficiency asks whether DisCos are correctly metering and invoicing the energy they receive; collection efficiency asks whether they can actually get paid for what they invoice. Splitting the last four quarters apart shows where the erosion is really coming from.

Neither line moves in a straight direction, and that is itself the signal. Collection efficiency climbed from 76.07% in Q2 2025 to a 2025 high of 80.70% in Q3, then slipped back for two straight quarters to 78.95% in Q1 2026, net up 2.9 points over the year, but giving back more than half its gain in the final six months. Billing efficiency moved the other way: it peaked at 82.69% in Q3 2025 and has fallen in every quarter since, down to 79.24% by Q1 2026, a net decline of 2.4 points. Neither metric has found a stable footing, billing efficiency is currently the faster-eroding of the two, which points to metering and invoicing accuracy, not just payment collection, as the more urgent near-term fix.

Tariff design corrects for the price DisCos charge; it does nothing for energy they never bill or never collect on in the first place.

What It Costs, In Naira

NERC’s reports have, since late 2024, begun stating the naira gap explicitly: target revenue at approved tariffs, versus what DisCos actually billed and collected. In 2026 Q1, that gap was ₦357.63 billion against a target revenue base of ₦955.19 billion, effectively the same 37.4% shortfall the ATC&C percentage implies, confirmed independently in Naira terms. The quarter before, Q4 2025, the shortfall was ₦338.26 billion against ₦969.19 billion targeted. Across all four quarters of 2025 that NERC has reported a Naira loss figure for, the cumulative shortfall against target revenue comes to roughly ₦606.5 billion, money the sector’s own tariff order says should exist, and doesn’t.

This is the number that should anchor the “next tariff review” debate, because it reframes the question. A tariff increase raises the price charged for energy that is billed and collected. It does nothing about ₦357.6 billion a quarter that was never billed, never metered correctly, or billed and never collected. Under the FGN subsidy arrangement that has held retail tariffs frozen since July 2024, the fiscal cost of that shortfall does not disappear, it shifts, either to the federal subsidy line or to DisCo balance sheets already under remittance pressure from NBET and the Market Operator.

There is a near-perfect symmetry worth pausing on. The energy the DisCos failed to recover in Q1 2026, ₦357.6 billion, is almost exactly the ₦358.3 billion the Federal Government paid in electricity subsidy over the very same quarter. Two different holes in the sector’s balance sheet, each about a third of a trillion naira a quarter, and only one of them is even nominally the tariff’s job to close. We take up the subsidy side of that ledger in a companion feature, The Frozen Tariff.

The National Average Hides an 11-DisCo Range From 20% to 70%

Averaging across eleven DisCos flattens a genuinely bimodal sector. Eko (20.2%) and Ikeja (24.6%) already run inside striking distance of MYTO-grade performance. Kaduna (69.7%), Yola (56.4%) and Jos (58.0%) are losing more than half of everything they receive. Six of eleven DisCos, Enugu, Ibadan, Jos, Kaduna, Kano, and Yola, are currently posting ATC&C loss above 40%, more than double their MYTO targets.

The relationship between metering and loss is about as strong as social-science data gets: DisCos with more metered customers lose less energy, almost linearly (correlation coefficient −0.91). Unmetered customers are estimate-billed, and estimate billing is where both technical loss (no feedback on actual consumption) and commercial loss (disputed, unpaid, or simply wrong bills) originate. National metering coverage moved from 54.33% to 59.13% between June 2025 and March 2026, a 4.8-point gain in nine months. At that rate, closing the metering gap for the worst-performing DisCos is a multi-year capital programme, not a policy announcement.

Kaduna: What Happens When the Gap Goes Unaddressed

On 11 August 2026, NERC took the unusual step of placing Kaduna Electric under regulatory takeover, citing accumulated market debt of ₦456.5 billion and a persistent inability to meet remittance obligations. Kaduna’s ATC&C loss, 69.66% in the most recent DisCo-level data GridIQ reviewed, is the highest of any DisCo in the country and more than 3.8× its MYTO target. Its metering rate, at 36.43%, is among the lowest.

Kaduna is not an outlier event. It is the endpoint of a trend line every other laggard DisCo is also on, low metering, high loss, chronic under-remittance, compounding quarter over quarter until the regulator runs out of tariff tools and reaches for administrative ones.

Kaduna is what happens when loss reduction is treated as a target to report against rather than a capital and operating priority to fund. Five more DisCos are on a trajectory that could put them in the same position within two to three MYTO cycles if the current stall persists.

NERC’s Own Move Signals It Agrees

On 4 September 2026, NERC issued a Revised Order on Successor Distribution Companies’ Utilisation of Earned Non-Admin Operating Expenditure (NERC/2026/062A), redirecting DisCo “surplus” revenue, margin earned above the MYTO-allowed return, into ring-fenced CapEx accounts rather than leaving it as freely distributable income. Read alongside seventeen quarters of stalled ATC&C performance, the intent is legible: the regulator is trying to force loss-reduction investment out of DisCos that have not been making it voluntarily, because the commercial case for reducing losses is stronger for DisCos than for the sector when remittance obligations, not loss reduction, determine near-term cash flow.

That is the structural tension the next tariff review inherits. Under the DRO regime introduced in January 2024, DisCos remit against an obligation set independently of how much they actually collect; a DisCo that under-collects still owes the same obligation, funded either by squeezing CapEx, delaying supplier payments, or accumulating the kind of arrears that put Kaduna into administration. Tariff increases raise the obligation’s revenue base but do nothing to change the incentive that lets loss reduction stay a second priority.

The risk to the next tariff cycle: If ATC&C loss is still running near 37% when the next tariff order is calculated, either (a) the cost-reflective tariff embeds today’s loss rate and customers pay for inefficiency they didn’t cause, or (b) the tariff assumes MYTO-target loss rates DisCos are nowhere close to hitting, and the revenue gap reopens the subsidy and remittance pressure that produced Kaduna. Neither outcome is what “the next phase of tariff adjustments” is supposed to deliver.

What Still Needs to Be True

None of this is self-correcting on the current trajectory. Four conditions determine whether the next tariff review lands on a sector that has actually closed the gap, or one still carrying the same loss rate it had two years ago, dressed in a new tariff order:

1. A second consecutive quarter of improvement. Seven quarters of range-bound performance (33.3%–39.6%) is long enough that one good reading should not be read as a reversal. Q2 2026 either confirms Q1’s direction or confirms the plateau is the new normal.
2. The ring-fenced CapEx order reaching the feeder, not just the balance sheet. NERC/2026/062A only closes the loss gap if redirected surplus revenue actually funds metering and feeder investment, rather than being absorbed elsewhere in DisCo cost structures the way earlier operating-expenditure flexibility often was.
3. A credible template out of Kaduna, not just an emergency measure. How NERC restructures Kaduna’s operations and ₦456.5 billion in debt will signal what happens to the next DisCo that crosses a similar threshold, and on current numbers, several are on that path.
4. Metering investment sustained past the current pace. National coverage gained 4.8 points in nine months. At that rate, closing the metering gap for the six worst-performing DisCos is a multi-year programme, not a policy announcement, and any change in pace shows up in ATC&C figures roughly two quarters later.

The Bottom Line for GridIQ Readers

Strip away the quarterly noise, and the data makes one point cleanly: Nigeria’s DisCos found real loss-reduction gains between 2022 and mid-2024, and have not found a second round of them since. A tariff review calculated against today’s 37% loss rate asks customers to pay for inefficiency they did not cause; one calculated against MYTO’s 16.92% target assumes a performance level the sector is nowhere near, reopening exactly the subsidy and remittance pressure that put Kaduna into administration. For GridIQ’s readers tracking the next tariff cycle, the metric to watch is not the headline percentage on review day, it is whether ATC&C loss has actually moved between now and then, or whether the sector is once again asking a price change to do a collections problem’s job.

Methodology & sourcing. ATC&C loss, billing-efficiency, collection-efficiency, DisCo-level and Naira-shortfall figures for Q1 2025 through Q1 2026 are drawn directly from NERC’s published Quarterly Reports on the Performance of the Nigerian Electricity Supply Industry (nerc.gov.ng). The 2024 comparison figures used for the annual-average context are from the same NERC series. All billing-efficiency × collection-efficiency identities were independently recomputed by GridIQ and reconciled against NERC’s headline ATC&C figure for each quarter. MYTO target figures reflect NERC’s published sector-average and DisCo-level targets in force for each year (20.54% for 2025, 16.92% for 2026); targets are revised periodically and comparisons should be read against the vintage in force at the time.

© 2026 GridIQ Analytics and Insight Ltd. Figures are drawn from NERC’s public quarterly disclosures and named secondary sources; loss rates, targets, and revenue figures have varied across reporting cycles. This piece is an editorial analysis, not investment, legal, or regulatory advice.

The Frozen Tariff: What Two Years of Held Prices Are Really Costing Nigeria

Retail electricity prices have not moved since July 2024. The bill did not disappear. It moved onto the federal balance sheet, to the tune of ₦1.93 trillion in 2025 alone. Who is actually paying for the freeze, and what it is quietly buying and starving.

Transmission infrastructure outside a load centre. A price freeze holds the customer tariff still; it does nothing to hold still the cost of gas, debt service or the naira. Illustrative.

For more than two years, the number on a Nigerian electricity bill has been, for most customers, a political decision rather than an economic one. Since July 2024 the Federal Government has held allowed retail tariffs frozen for every customer band except Band A, even as the cost-reflective tariff, what it actually costs to generate, wheel and distribute a unit of power, kept climbing with gas prices, inflation and the naira. The difference between those two numbers does not vanish. It is paid, in full, by the government, and it has become one of the largest single subsidy lines in the federal budget.

Two Tariffs, One Grid

Nigeria does not really run one electricity tariff; since April 2024 it has run two systems side by side. Band A customers, those promised 20 or more hours of supply a day, now roughly 45% of billed consumption after their share was raised from 40% in the fourth quarter of 2025, were moved to a cost-reflective rate, currently about ₦209.50 per kWh for most DisCos. Everyone else, on Bands B through E, pays a rate that has not been allowed to rise: held below cost, with the shortfall covered by subsidy. The result is a grid where the customers with the best supply pay something close to the true cost of power, and the customers with the worst supply are shielded from it, the opposite of what most people assume a subsidy does.

The Bill the Government Is Paying Instead

Freezing the tariff did not make power cheaper to produce; it moved the difference onto the federal subsidy line. In 2025 that line came to ₦1.928 trillion, an average of ₦160.7 billion every month, and 57.44% of the entire Nigerian Bulk Electricity Trading (NBET) invoice for the year. Put plainly: across 2025, the government paid more than half of the actual cost of the power the market bought. And 2025 was not an aberration, it was marginally lower than 2024’s ₦1.949 trillion, meaning two consecutive years of roughly two-trillion-naira subsidies with no structural exit in sight.

Why a “Falling” Subsidy Isn’t Good News

On the surface, Q1 2026 looks like relief: the subsidy fell ₦60 billion, or 14.4%, from the previous quarter. But NERC itself attributes the drop to lower electricity offtake by the DisCos, not to any improvement in tariff recovery. In other words, the bill went down because the DisCos took and sold less power, not because the sector got better at charging cost-reflective rates or collecting what it billed. A subsidy that shrinks because supply shrank is not progress; it is the fiscal shadow of a grid that delivered less. Collection efficiency actually slipped over the same window, to 78.95% from 79.36% a quarter earlier.

Who Really Bears the Freeze

The comfortable story is that the freeze protects ordinary consumers. The fuller picture is that it redistributes the cost across four balance sheets, none of them free.

Consumers get a held price but a rationed product: Bands B through E are shielded from cost-reflective tariffs precisely because they receive fewer guaranteed hours, so the “saving” is partly a discount for unreliability. Band A customers, meanwhile, now pay the full economic rate. Households and businesses on the wrong side of the reliability line still fill the gap the old-fashioned way, with petrol and diesel generators whose per-unit cost dwarfs even the cost-reflective grid tariff.

The DisCos carry a revenue hole the subsidy does not fully plug. In 2025 they received power worth ₦3.68 trillion, billed ₦2.99 trillion of it, and collected just ₦2.32 trillion, a ₦1.36 trillion gap made up of ₦694.8 billion supplied but never billed and ₦669.49 billion billed but never collected. That is the loss story from our ATC&C feature, wearing its naira coat.

The generators and the fisc absorb the rest. Legacy debt owed to generation companies has been put at around ₦3.3 trillion; the government has moved to clear part of it, raising roughly ₦1.23 trillion against that backlog rather than adjusting prices. Every quarter the freeze persists, the subsidy line and the arrears stack compete for the same scarce fiscal space.

The Hidden Cost: Investment Deferred

A subsidy that consumes ₦1.9 trillion a year is ₦1.9 trillion not spent on the things that would actually lower the cost of power, metering, feeder upgrades, gas infrastructure, transmission. This is the quiet link between the freeze and the loss numbers: as long as the sector’s cash is going to cover a price gap, it is not going into the capital programme that would close the loss gap. The two problems feed each other. High ATC&C losses raise the true cost of served power, which widens the subsidy needed to hold the retail price down, which drains the capital that would reduce the losses. Freezing the tariff without funding loss reduction locks that loop in place.

What Has to Be True to Exit

There is no painless way out of a two-trillion-naira subsidy, only a managed one. Three things determine whether Nigeria exits the freeze on its own terms or has it broken for it by the fisc:

1. Loss reduction has to lead price. Every point of ATC&C loss recovered lowers the true cost of served power and therefore the subsidy required to freeze the retail price. Metering and feeder investment are the cheapest tariff policy available, they shrink the gap without touching the customer’s bill.
2. Any thaw has to be sequenced by band and by reliability. Raising frozen tariffs only lands fairly if the promised hours arrive first; a price rise into unchanged darkness is what turns a tariff review into a political crisis. Band A’s cost-reflective move worked because it was tied to a supply guarantee.
3. The subsidy has to be made visible and time-bound. An open-ended, quietly-growing subsidy is the one most likely to be cut abruptly under fiscal stress. A declared glide-path, with the savings ring-fenced for the network, as NERC’s recent surplus-revenue order signals, is the difference between a transition and a shock.

The Bottom Line for GridIQ Readers

The tariff freeze is often discussed as consumer protection; read against the numbers, it is better understood as a ₦1.9-trillion-a-year deferral. It holds the retail price still while the cost of power, the DisCos’ unrecovered revenue and the generators’ unpaid invoices all keep moving. For GridIQ’s readers, the figure to track is not whether tariffs rise at the next review, officials have said an increase is “not on the table”, but whether the gap the freeze is papering over is getting smaller underneath it. If ATC&C losses fall, the subsidy can shrink for the right reason. If they don’t, the subsidy will shrink anyway, the wrong way: through less power, more darkness, and a bill that has simply been moved, not paid.

Methodology & sourcing. Subsidy figures (2025 full-year ₦1.928trn, quarterly split, monthly average, share of the NBET invoice; Q1 2026 ₦358.32bn) and the DisCo revenue, billing and collection figures are from NERC’s 2025 and Q1 2026 performance disclosures. Band A’s cost-reflective rate (~₦209.50/kWh, EEDC lower) and band supply guarantees reflect NERC MYTO as published in 2026; frozen Band B–E rates vary by DisCo and are held at their July 2024 allowed levels. The 2024 subsidy comparison (₦1.949trn) is NERC’s. Figures are indicative and have varied across reporting cycles.

© 2026 GridIQ Analytics and Insight Ltd. Drawn from NERC disclosures and named secondary sources. This piece is an editorial analysis, not investment, legal, or regulatory advice.

Abu Dhabi Buys Into Nigerian Power: What 2PointZero’s 90% Azura Deal Means

Abu Dhabi is making a major entry into African power generation, and Nigeria sits at the centre of it. The bigger story is not who now owns Azura, but that sophisticated international capital is positioning for the next generation of African power infrastructure.

The 461 MW Azura-Edo open-cycle gas turbine plant near Benin City, Edo State, online since 2018 and the jewel of the platform now passing to Abu Dhabi’s 2PointZero.

Abu Dhabi-based 2PointZero Group, through its specialised energy infrastructure platform ePointZero, has agreed to acquire a 90% stake in Azura Power Holdings, the pan-African independent power producer behind one of Nigeria’s most important private power projects. The transaction is subject to regulatory approvals and closing conditions. Azura’s founding partner, Amaya Capital, retains the remaining 10%.

What 2PointZero Is Actually Buying

Azura Power operates 752 MW across three African markets, and by the company’s own account those assets supply roughly 10% of grid baseload in each of the three countries. For Nigeria, the jewel is Azura-Edo: a 461 MW open-cycle gas turbine plant near Benin City, Edo State, which came online in 2018. It was built as the first phase of a planned 1,500 MW development, financed with about $890 million in debt and equity, and backed by major international development finance institutions.

What made Azura-Edo bankable in a difficult market was its contract. The plant sells its electricity under a long-term Power Purchase Agreement with NBET, which buys the power for onward supply to Nigeria’s distribution companies. That structure, alongside an original shareholder base of Actis, Africa50 and Amaya Capital and land-and-infrastructure support from the Edo State Government, is what turned a Nigerian IPP into an asset international capital could underwrite. The new transaction brings the platform under ePointZero’s control, with Amaya holding on to 10%.

So, Who Is 2PointZero?

2PointZero is not simply another foreign investor testing the Nigerian market. It is a large Abu Dhabi-based investment holding company focused on energy and consumer sectors, with more than AED 147 billion in assets, over 50 subsidiaries and operations in more than 85 countries, established as an Abu Dhabi platform within the wider International Holding Company (IHC) ecosystem.

Its energy strategy is the part Nigeria should read closely. Through ePointZero, the group is building exposure across the energy value chain: power generation, energy infrastructure, pipelines and storage. In July 2026 ePointZero completed a $2.25 billion acquisition of Traverse Midstream Partners in the United States, taking a position in major natural-gas pipeline infrastructure, and it holds a stake in Elsewedy Electric, the Egyptian electrical-equipment, engineering and infrastructure group. Azura is the African generation piece of a value-chain strategy, not a one-off bet on a single plant.

A Platform, Not a Plant

The reason the deal matters more than its megawatts is the pipeline that comes with it. Azura carries more than 1.5 GW of additional projects in development, spanning gas-fired generation, renewables and battery energy storage. In Nigeria alone the company points to a planned 270 MW expansion of Azura-Edo and a 100 MW solar project in Katsina. A buyer positioning the acquisition as a growth platform inherits not just an income stream but a route to build.

What It Means for Nigeria

Read against the wider market, the acquisition could mark a real shift in the Nigerian power investment landscape, on three fronts.

1. It validates Nigerian power as an investable class. Azura was one of the projects that proved a Nigerian IPP could attract international capital. A new Abu Dhabi-backed owner taking 90% control sends the same signal again: properly structured Nigerian power assets can pull serious, long-term money.
2. It could bring fresh capital for expansion. 2PointZero has framed the deal as a platform for growth. With 752 MW already operating and a substantial pipeline behind it, the transaction could accelerate new generation rather than simply rewrite the shareholder register.
3. It could change the competitive landscape. Nigeria needs far more generation, but the industry needs more than megawatts: gas supply, transmission capacity, bankable PPAs, credible offtakers, payment security and patient capital. The Azura model already has experience navigating most of those, and a deep-pocketed owner sharpens it.

The GridIQ View

The transaction is best read as Abu Dhabi taking a longer-term position in Africa’s energy infrastructure market, and for Nigeria that is both an opportunity and a test. The opportunity is capital, technology, expertise and potentially more generation capacity. The test is whether the country’s regulatory, gas, transmission and electricity-market reforms are strong enough to convert that investment appetite into actual megawatts delivered to homes and factories, rather than another well-financed asset waiting on the rest of the value chain.

The headline may be that Abu Dhabi is buying 90% of Azura. The bigger story for Nigeria is that sophisticated international capital is positioning itself for the next generation of African power infrastructure, and the reforms now on the table will decide how much of that capital turns into power on the grid.

Sourcing. Transaction terms, portfolio figures (752 MW across Azura-Edo 461 MW, Tobene 116 MW and CTRG 175 MW), financing (~$890 million), the NBET PPA, 2PointZero’s corporate scale (AED 147 billion in assets, 50+ subsidiaries, 85+ countries), the July 2026 Traverse Midstream acquisition ($2.25 billion) and the development pipeline (270 MW Azura-Edo expansion, 100 MW Katsina solar) are as stated in the source briefing. The transaction remains subject to regulatory approvals and closing conditions.

© 2026 GridIQ Analytics and Insight Ltd. This piece is an editorial analysis, not investment, legal, or regulatory advice.