- Solar surplus crashes daytime power prices
- Coal shortages trigger nightly price spikes
Between 1-10 May 2026, the Indian electricity market experienced a daily rhythm that exposed a fundamental structural weakness. During daylight hours, power was abundant and cheap. After sunset, it became scarce and expensive – often hitting the maximum permissible price. This was not a one-off event. It repeated every single day.
The reason lies not in total generation capacity, but in the location of fuel, the timing of demand, and the absence of any mechanism to shift surplus daytime power into the evening hours.
Daily price arc: From INR 200 to INR 10,000
Every day followed a predictable price trajectory. Take 9 May as a representative example.
At noon, the price was INR 1,001 per MWh, with sell bids nearly six times purchase bids. By midnight, the price had hit the ceiling of INR 10,000 per MWh, and purchase bids exceeded sell bids by more than two to one. The market cleared less than half of what buyers wanted.
This pattern was not unique to May 9. Across the ten-day period, the price ceiling was triggered on at least eight separate nights.
Why daytime prices collapsed
Between 9 AM and 4 PM each day, solar generation flooded the grid. The result was a persistent oversupply.
- On 10 May at 11 AM, sell bids totalled 61,881 MWh against purchase bids of just 9,048 MWh. The price fell to INR 200 per MWh
- On 5 May at 1 PM, sell bids were 58,097 MWh while purchase bids stood at 7,345 MWh. The price was INR 200 per MWh.
At these price levels, coal-fired generators cannot recover their variable costs. Yet many continued to run, because shutting down and restarting later in the day would incur even higher costs. Effectively, the grid was being subsidized by generators willing to absorb daytime losses in order to be available for evening peak hours.
Why nighttime prices spiked
When solar generation dropped off after 5 PM, the burden shifted entirely to thermal power. But thermal plants across southern and western India were operating with critically low coal stocks.
These plants are located in high-demand states. Their inability to generate at full capacity forced the grid to rely on long-distance transmission from eastern coal belts. But transmission lines have limited capacity. When demand exceeded that capacity, the IEX market responded with price spikes.
On 5 May at midnight, the price hit INR 10,000 per MWh. Purchase bids were 15,483 MWh, sell bids were only 8,679 MWh. The cleared volume was 6,988 MWh – less than half of what buyers sought. On 9 May at midnight, the same scenario repeated: INR 10,000 per MWh, purchase bids at 15,109 MWh, sell bids at 7,045 MWh, cleared volume at 5,464 MWh.
The eastern coal belt: A surplus that could not travel
While the south and west struggled, eastern India remained comfortably supplied.
These plants had ample coal and operated at healthy PLFs. The power they generated was available to the national grid. But transmitting that power 1,500 km to southern load centres is not instantaneous. The transmission corridors between the eastern coal belt and southern demand centers are the physical bottleneck of the Indian electricity system. On any given evening, the grid operator could see generation in the East and unmet demand in the south, but could not move enough power quickly enough to prevent price caps.
Forced outages made the situation worse
Coal shortage was not the only constraint. On April 24, just before the reporting period, nearly 24 GW of thermal and nuclear capacity was under forced outage due to technical faults. This is roughly the entire installed capacity of a large state like Maharashtra. During 1-10 May, several plants continued to operate at very low PLF, not due to fuel but due to breakdowns or maintenance.
- North Chennai TPS Stage 2: 0-15% PLF throughout the period
- Tenughat TPS (Jharkhand): Erratic PLF between 0% and 75%
- Yadadri TPS: 6-10% PLF consistently
Every megawatt lost to forced outage shifted the burden to remaining plants. And those remaining plants, particularly in the South, were already fuel-constrained.
The unmet demand problem
The IEX data records every transaction, but it does not record demand that went unsatisfied. However, the gap between purchase bids and cleared volume tells the story.
Key observations from the 10-day period:
- On 9 May at 8 PM, purchase bids exceeded cleared volume by 8,281 MWh – 55% of what buyers wanted
- On 5 May at midnight, the gap was 8,495 MWh – more than half of total demand
- On 6 May at midnight, the price cap was triggered, and cleared volume was only 5,399 MWh against purchase bids of 14,739 MWh.
Some of this unmet demand was likely met through bilateral contracts outside the exchange. Some may have been shifted to captive generation or diesel backup. But some was almost certainly not met at all – load shedding, in plain terms. The market data cannot tell us which portion, but the price signals leave little doubt. When buyers are willing to pay the maximum legal price and still cannot secure power, the system has exhausted its options.
Regional divide: Who generated and who suffered
The ten-day data reveals a clear geographic pattern in operational readiness.
Eastern region (Chhattisgarh, Odisha, Jharkhand): Plants operated at 70-140% of normative stock. Coal was abundant. The constraint was transmission, not generation.
Northern region (Punjab, Haryana, Uttar Pradesh): Plants operated at 110-150% of normative stock. The region was comfortable but reliant on rail links from the East.
Western region (Maharashtra, Gujarat): Plants operated at 30-60% of normative stock. Maharashtra in particular showed consistent stress, with multiple plants below 50% stock.
Southern region (Telangana, Tamil Nadu): Plants operated at 15-35% of normative stock. This region carried the heaviest physical stress and saw the most frequent price spikes.
What was missing
The IEX snapshot for May 1-10 records every transaction, every bid, every price. But it also highlights what does not exist in the Indian electricity system at scale.
There was no significant demand response. Even at INR 10,000 per MWh, large buyers did not reduce consumption meaningfully. In a heatwave, price elasticity approaches zero.
There was no large-scale battery discharge. No storage exists to absorb the daytime solar surplus and release it in the evening. Every megawatt-hour consumed after sunset had to be generated at that moment, primarily from coal.
There was no quick relief from imports. Coastal plants designed for imported coal – such as Adani Mundra, Tata, and NTPL Tuticorin – were themselves at low stock levels of 10-18%. Either import prices were too high, or supply chains were delayed.
Closing view
Between 1 and 10 May, the Indian electricity market functioned exactly as designed. Prices rose when supply was tight. But the design assumed that supply would respond to high prices. In practice, it did not. Southern and western thermal plants had no coal. Eastern plants had coal but no transmission capacity to deliver it at scale. And no storage existed to bridge the gap between solar-rich afternoons and coal-scarce evenings.
The result was a market that cleared – but at the price ceiling, with thousands of megawatts of unmet demand, and with the same regions carrying the physical stress night after night. The grid did not collapse. But it also did not serve all the demand that was willing to pay for power. That is not a failure of market design. It is a failure of fuel logistics, transmission planning, and storage deployment.
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