The Seasonal Demand-Supply Scissor: Why Electricity is Poor in February
Every year, without fail, Nigeria's electricity system enters its worst performance phase between February and April. This paper argues that the yearly crisis is not a random expression of general dysfunction. It is the predictable convergence of two independent forces – a demand spike driven by heat and a supply contraction driven by hydrology – in a system with no reserve capacity to absorb their combined impact. Understanding why these forces coincide, and why nothing in the system can cushion the collision, is the starting point for any serious reform.
A Crisis That Arrives on Schedule
Nigeria's electricity grid is in a state of chronic underperformance. That much is well understood, endlessly discussed, and insufficiently acted upon. Installed generation capacity stands at roughly 13,000 megawatts; actual dispatched power on any given day rarely exceeds 4,000 to 5,000 megawatts. The gap between those two figures – caused by gas supply failures, ageing plant, transmission constraints, and the commercial dysfunction of a sector that cannot pay its bills – is the subject of constant and legitimate complaint.
But within this chronic underperformance, there is a seasonal structure that is analytically distinct and operationally significant. The February–April window is not merely a particularly bad expression of an always-bad system. It is the predictable convergence of two independent dynamics: a demand spike driven by meteorology, and a supply contraction driven by hydrology. Understanding why they coincide – and why the system has no capacity to absorb the resulting shock – is the first requirement of serious analysis.
The system has, in effect, a built-in annual stress test. It fails that test every year. And yet the people responsible for managing it continue to respond to each failure as though it were an unforeseen event rather than a scheduled one. That, as much as the engineering failures themselves, is what this paper is about.
The Demand Side: What Heat Does to a Grid
Nigeria sits within the tropics, and its annual temperature profile is sharply seasonal. The harmattan – the dry north-easterly wind that defines the meteorological character of the dry season – retreats from the south roughly in February. What follows is the most punishing heat of the year: a period of intense dry heat from the north and rising humidity from the south, running through March and into April before the rains bring relief.
Daytime temperatures across much of the country regularly reach 35 to 40 degrees Celsius. Across the North and Middle Belt, peaks of 38 to 42 degrees are common through the afternoon, and night temperatures remain high enough that cooling loads persist well into the evening. The electricity consequence of this meteorology is direct and large. Cooling demand – from air conditioners, ceiling fans, standing fans, and refrigeration – is strongly temperature-sensitive.
Unlike temperate climates, where peak electricity demand is driven by winter heating, Nigeria's annual demand peak is a dry-season phenomenon. Global evidence confirms the magnitude: cooling demand in hot climates can drive seasonal load increases of 20 to 30 per cent above annual averages. The World Bank has flagged rising air-conditioning uptake as a growing grid stressor across sub-Saharan Africa, and Nigeria, where the penetration of room air conditioners has expanded significantly with urbanisation and rising, if still modest, middle-class incomes, is no exception.
The demand spike is not confined to commercial or wealthy consumers. Households that own any cooling appliance – and increasingly many do, even in lower-income urban areas – run them harder and longer during February through April. Water pumping, driven by heat and increased consumption, also rises. The aggregate load on the grid during this period is, therefore, systematically higher than at any other time of year, before any question of supply is even raised.
What the Nigerian system lacks – and what distinguishes it from better-managed grids – is any institutionalised recognition of this demand seasonality. Planning frameworks are structured around annual averages. They do not ask how much capacity will be available in February versus October. If your planning framework does not ask seasonal questions, it will not generate seasonal answers.
The Multi-Year Tariff Order, NERC's medium-term expansion plans, and the sector's investment frameworks are all structured around annual averages and aggregate capacity targets. They do not model seasonal load curves with any granularity. They do not establish seasonal adequacy standards. The consequence is that Nigeria's planning system is constitutionally incapable of anticipating the stress that its own meteorology reliably produces.
The Supply Side: What Hydrology Does to a Grid
If the demand dynamics are meteorological, the supply dynamics are hydrological – and they move in exactly the wrong direction. Nigeria's major hydroelectric stations sit on the Niger River system and its tributaries. Kainji Dam, with 760 megawatts of installed capacity, and Jebba Hydroelectric Power Station, with 578 megawatts, are located on the main Niger River. Shiroro – 600 megawatts – sits on the Kaduna River, a major Niger tributary. Zungeru, commissioned in 2022 with 700 megawatts of capacity, is also on the Kaduna River.
Together, these plants represent approximately 23 per cent of Nigeria's installed generation capacity, and a fluctuating share – roughly 25 to 32 percent – of actual dispatched power, depending on the season. That variability is determined by the hydrology of the Niger basin, which follows a clear and well-documented seasonal pattern. Rainfall in the catchment areas peaks between July and September. The flood pulse – driven by local West African rains – fills reservoirs to their annual maximum between August and October.
By the time the dry season sets in through December and January, inflows are declining sharply. February and March represent the trough of the hydrological cycle: the point of minimum reservoir storage, minimum turbine head, and minimum generating capacity. The consequence is material and quantifiable. NERC's quarterly performance data provide consistent evidence. In the first quarter of each year – which captures the heart of the February–April stress window – hydro generation as a share of total dispatched power falls measurably relative to the preceding wet-season quarter.
Historical analysis of Nigeria's generation portfolio records output reductions from hydro plants of up to approximately 40 per cent outside the wet-season peak, as reservoir levels and turbine head fall. In early 2026, operators explicitly cited lower water inflows at Kainji, Jebba, and Shiroro as a direct drag on system performance – a period in which available capacity fell to approximately 4,900 megawatts from an installed base of roughly 13,600 megawatts, with average dispatched power of around 4,400 megawatts.
This is not a marginal seasonal adjustment. It is a structural supply withdrawal at the worst possible time. And critically, the thermal fleet – which at roughly 77 per cent of installed capacity should be the system's primary insulation against hydro shortfalls – is in no position to compensate.
Why Thermal Plants Cannot Save the Day
Gas-fired thermal plants dominate Nigeria's installed generation base. In a well-functioning system, this capacity would serve as the baseload anchor that insulates the grid against seasonal hydro variability: running continuously, carrying the load through the dry season, and freeing the hydro plants to manage their reservoirs strategically. In Nigeria's system, it does not do this.
The reasons are structural and well-rehearsed, but their seasonal significance is too rarely emphasised. Gas supply to generating stations is chronically unreliable – disrupted by pipeline vandalism, compression failures, payment arrears to gas producers, and the commercial dysfunction of a sector in which distribution companies cannot reliably pay generators, generators cannot reliably pay gas suppliers, and the entire value chain runs on perpetual debt.
Plant maintenance is inadequate, turbine availability is constrained by ageing equipment, and the grid's transmission infrastructure cannot always wheel available power to where demand is concentrated. The combined effect is that only a fraction of installed thermal capacity is actually available on any given day. Available thermal capacity routinely falls well below 50 per cent of the nameplate.
A system nominally endowed with 13,000 megawatts of capacity frequently delivers less than 5,000 megawatts – and during the February–April stress period, when hydro is also constrained, that delivered figure can fall toward 4,000 megawatts or below. Such is not a 13,000 megawatt system in any meaningful operational sense. The headline capacity is a fiction of engineering specification, not a measure of actual reliability.
This points to the crux of the seasonal problem. A healthy electricity system maintains a reserve margin – typically 15 to 20 per cent of peak demand – specifically to absorb the kind of correlated shock that Nigeria's February–April convergence represents. Reserve capacity exists precisely to cover the unexpected or the seasonal: plant outages, demand spikes, supply shortfalls. Nigeria's system operates with an effective reserve margin close to zero. There is no buffer.
When the two jaws of the seasonal scissor close – demand rising, hydro falling – there is nothing between the grid and involuntary load shedding. Unplanned outages are not a failure of the system in those moments. They are how the system equilibrates supply and demand in the absence of any other mechanism.
The Governance Failure: Data Without Analysis
The seasonal nature of Nigeria's worst electricity performance is not a secret. Hydrological records for the Niger basin extend back decades. The Nigerian Meteorological Agency maintains long-run climatological data establishing the February–April temperature regime with precision. NERC publishes quarterly performance reports that, read carefully, reveal the seasonal patterns in generation mix and availability.
System operators have dispatch data that could, with modest analytical effort, be correlated with monthly load and weather records to confirm what casual observation already suggests. The failure is therefore not informational. The data exist. The failure is analytical, institutional, and cultural – a failure to ask the right questions of the available information, and/or a failure to translate whatever answers emerge into planning and operational practice.
Several pathologies sustain this failure. The first is what might be called the chronic-acute confusion: because the Nigerian electricity system is always performing badly, there is limited analytical incentive to distinguish why it performs particularly badly at particular moments. The seasonal signal is drowned in the noise of perpetual underperformance. Everything is always a crisis; the specifically seasonal crisis disappears into the general emergency.
This undifferentiated framing makes targeted seasonal remedies impossible because the problem has not been isolated with enough specificity to generate targeted solutions. The second pathology is the dominance of the tariff narrative. Public and policy discourse about Nigeria's electricity sector is overwhelmingly structured around one diagnostic claim: that tariffs are not cost-reflective, and that the remedy for most of the sector's ills is tariff increases that allow full cost recovery.
Whatever the partial validity of this argument in other contexts, it is wholly inadequate as a diagnosis of seasonal stress. A tariff increase does not raise reservoir levels. It does not fix pipeline vandalism. It does not add spinning reserve to a grid that has none. When the February–April stress period arrives, tariff policy is irrelevant to the cause and irrelevant to the cure. Applying it as though it were a universal remedy is a form of analytical malpractice – not because tariffs are unimportant, but because the seasonal crisis requires a categorically different set of interventions.
The third pathology is structural in the planning frameworks themselves. MYTO, NERC's expansion plans, and the sector's investment analyses are built around annual averages and aggregate capacity targets. They do not model seasonally available capacity, seasonally varying demand curves, or the mismatch between the two. Planning that asks how many gigawatts Nigeria needs without asking how many gigawatts will be available in March will consistently underestimate the operational challenge and overpromise on the relief that new capacity will provide.
A Risk Concentration Problem
At its analytical core, what Nigeria's electricity system exhibits is a risk concentration problem of a particular and damaging kind. A substantial share of generation capacity – hydro – is negatively correlated with the period of peak electricity demand. When demand is highest, hydro output is lowest. When hydro output is highest, demand is lower. This is the worst possible design characteristic for a reliable system: the resource that should serve as a balancing tool moves against demand rather than with it.
Thermal generation, which dominates the installed base, should, in principle, be the seasonal balancing resource. It can, in theory, run regardless of reservoir levels. But because it is chronically unavailable due to gas supply failures and maintenance dysfunction, it cannot fulfil this role. The system, therefore, lacks a dependable backstop at precisely the moment it most needs one.
The result is that Nigeria's electricity crisis has two analytically separable but operationally fused layers. The first is the chronic layer: persistent system-wide underperformance due to gas constraints, ageing plant, transmission bottlenecks, and commercial dysfunction. This operates year-round. The second is the seasonal layer: the additional stress imposed by the February–April convergence of peak cooling demand and minimum hydro output.
This operates predictably and cyclically on top of the chronic dysfunction, amplifying its effects and generating the concentrated annual crisis that any attentive observer has long identified. Addressing only the chronic layer – even successfully – will not eliminate the seasonal crisis unless the seasonal structure of the supply mix is also addressed. And addressing only the seasonal layer without resolving the chronic dysfunction will produce, at best, marginal relief.
Both require diagnosis and remedy, and the remedies are different. The current policy conversation, focused almost exclusively on the chronic-structural dimension and, within that, almost exclusively on tariff reform, addresses neither layer with the precision required.
What Comes Next?
The diagnosis presented in this paper establishes the structural foundation of the seasonal crisis: the scissor that opens every February, the system's inability to absorb it, and the governance failures that allow a predictable annual event to be treated as an annual surprise. But it does not yet fully explain why the crisis is as bad as it is – why, in particular, the hydro shortfall is consistently worse than simple seasonal hydrology would imply.
The answer to that question lies in the operational history of a single plant. Shiroro Hydroelectric Power Station was designed explicitly as Nigeria's insurance against the seasonal stress this paper has described. Understanding how that insurance policy was quietly spent – and what its loss means for any realistic path to recovery – is the subject of the second paper in this series.
Dr Babalola is a former Minister of Power and was one of the principal architects of Nigeria's electricity sector reform. Through Exenergia Limited, he works on infrastructure development, electricity industry policy, regulatory economics, and the macroeconomic dimensions of energy infrastructure failure. This paper is the first in a three-part series.
