India’s power crunch is becoming a fuel logistics problem: India’s power system is entering a period in which rising electricity demand is colliding with constraints in the supply chain that keeps thermal power plants running. Installed capacity may look adequate on paper, but that capacity is of limited use if coal does not reach a generating station when it is needed, hydropower output is weak and renewable generation is unavailable during the evening peak.
The warning is visible in the power market. The average day-ahead price on the Indian Energy Exchange rose to ₹7.3 per unit in September, up 105% from a year earlier. Electricity traded on the exchange increased 10.4% to 12.22 billion units, while national electricity consumption rose about 11% to 162 billion units. IEX traded 39.69 billion units in the July-September quarter, up 12.7%, while day-ahead and real-time market prices rose 46% and 49%, respectively.
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The market is signalling tighter supply relative to demand. It does not by itself establish a national shortage, but the sharp rise in prices alongside higher demand shows that spare capacity is becoming harder to access at the margin.
Demand is running ahead of the planning cycle
The more important warning comes from the demand numbers. Peak demand reached 269 GW on September 10, only marginally below the year’s record of about 270 GW set in May. September’s peak was unusual because electricity demand typically eases after the summer months. Instead, high temperatures, cooling requirements and irrigation demand kept pressure on the system.
Between April and August, actual electricity demand was 3.3% above the Central Electricity Authority’s projections. That gap is significant for a power system in which fuel procurement, coal stocking and plant maintenance have to be planned in advance. A forecast error of that size means generators can find themselves needing more fuel precisely when replenishing stocks is difficult.
Coal remains central to meeting that demand. Coal and lignite-based plants have about 230.8 GW of capacity and supplied 69.54% of India’s electricity between April and June. During non-solar peak hours, they generated as much as 188.8 GW, roughly three-fourths of total generation during those hours.
That dependence changes the significance of a coal-stock problem. A solar-heavy system can have substantial installed capacity and still need thermal generation when the sun goes down. Batteries and pumped storage can reduce that dependence, but they cannot yet substitute for the existing thermal fleet across the entire system.
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India’s power crunch: Coal is available, but getting it to plants is harder
The distinction between coal availability and coal delivery is important. India is not running out of coal. The problem this year has been that coal has not always reached power plants quickly enough to match the increase in consumption.
CRISIL estimated that coal inventories at thermal power plants fell about 42% year-on-year to 29 million tonnes in August, reducing average stock cover to nine days from 17 days a year earlier. It attributed the stress primarily to higher coal consumption and difficulties in replenishing stocks after prolonged rain disrupted mining and evacuation in the eastern coal belt. Rake loading increased by about 5% between April and August, while coal receipts rose only 3%, even as thermal coal consumption increased about 8%.
The pressure has continued. Recent reporting based on government data puts the number of thermal plants with critical coal stocks at more than 80 out of roughly 190. A critical-stock classification does not mean a plant will stop generating the next day. It means that the plant has less protection against another disruption or an unexpected rise in demand.
The contrast between mine stocks and plant stocks is revealing. Coal India increased supplies to the power sector by 10.6% year-on-year to 48.9 million tonnes in September. Its overall September supplies rose 12.5% to 61.2 million tonnes. The increase helped, but it also drew down accumulated stocks at the mines.
The problem is therefore one of moving the right quantity of coal to the right generating stations at the right time. Rail capacity, loading infrastructure, weather disruptions and plant-level inventories all matter. More production at the mine mouth does not automatically translate into more electricity when a generator needs it.
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NTPC is buying insurance against tighter supply
NTPC illustrates the pressure. Its coal stocks have fallen from about 18 million tonnes in April to roughly 5.2 million tonnes in early October, leaving some plants with only five to seven days of cover. At the same time, NTPC’s generation rose sharply as it responded to stronger electricity demand. The company is now looking to expand purchases from commercial and private mines and could procure as much as 15 million tonnes from these sources.
This diversification comes at a cost. Imported coal is exposed to international prices, freight rates and movements in the rupee. Even domestic coal bought through alternative channels can cost more than contracted supplies. If generators absorb the higher fuel cost, their margins fall. If the cost is passed through, electricity becomes more expensive.
The government has already responded by pushing captive coal-based plants to maximise generation and by increasing coal dispatches. These measures can ease the immediate problem. They do not remove the underlying exposure of a rapidly growing power system to fuel logistics.
The weakness in hydropower has made that exposure more visible. Since April, hydropower generation has fallen 10.85% from the corresponding period of 2025. Lower rainfall and depleted reservoir levels have reduced an important source of flexible generation, increasing reliance on coal, particularly during periods when solar output is falling.
The present squeeze should therefore not be mistaken for proof that India’s power system has run out of generation capacity. Nor is it evidence that renewable energy is failing. It shows that capacity and dependable supply are different things.
If coal supplies improve after the monsoon, hydropower recovers and demand moderates, the immediate pressure should ease. Coal India has already increased dispatches, and the government’s efforts to diversify procurement can provide additional support. But a system operating with thin fuel buffers has little protection against another weather disruption or an unexpectedly strong demand spell.
That is the more durable policy problem. India cannot plan its electricity system by adding generation capacity alone. The CEA’s own demand projections already envisage continued growth in electricity consumption and peak demand.
The next phase of the energy transition therefore has to be about the ability to deliver power when it is needed. That requires faster expansion of transmission, more grid-scale storage, better forecasting of demand and renewable output, and thermal plants capable of operating flexibly when renewable generation falls. Coal will remain part of that system for years, even as its relative share declines.
India’s renewable build-out will ultimately be judged by more than the number of gigawatts added. The relevant test is whether those gigawatts reduce the need for expensive and inflexible backup during the hours when demand is highest. Until storage, transmission and flexible generation catch up, the country will continue to need coal not because its long-term energy transition has failed, but because its power system still needs firm electricity after the sun goes down.