#scuc

Thermal power plant generation from some of India’s cheapest coal stations was scheduled for reduction through the solar window on 9 July. Grid-India’s day-ahead security-constrained scheduling table listed more than a dozen pit-head units for backing down between morning and late afternoon.

The list included Darlipali, Talcher Stage-2, Talcher, Sipat, Korba, Singrauli, North Karanpura, Rihand and Vindhyachal Stage-4. Energy costs ranged from 115.9 paise per unit at Darlipali to above 212 paise per unit at North Karanpura and Vindhyachal Stage-4. Korba alone appeared in three listings with nearly 775 MW.

The market logic was clear. Day-ahead prices during the afternoon solar trough were around 25–30 paise per unit. EnergylineIndia.com records this as important for Power generation capacity planning because cheap coal can still be too costly when solar floods the system. Thermal power plant units in eastern and central coalfields were therefore part of a national trough response, not a local congestion event. Thermal power plant backdown now reflects economic optimisation. Thermal power plant cycling may become routine. Thermal power plant scheduling will increasingly depend on solar-hour price signals.

Renewable power generators are utilizing inaccurate day-ahead weather forecasts to externalize their balancing costs, forcing national grid operators to routinely purchase expensive reserve power. This structural imprecision forces distribution companies and retail consumers to absorb the financial burden of stabilizing an increasingly intermittent grid.

Grid stability requirements under the IEGC

Under the Indian Electricity Grid Code (IEGC), the grid must maintain a strict frequency band to prevent system instability.

When solar and wind generation deviates significantly from their day-ahead schedules, grid operators are legally required to activate Security Constrained Unit Commitment (SCUC) and Tertiary Reserve Ancillary Services to stabilize the system.

Because renewable operators are not penalized aggressively enough for forecasting deviations, they lack strong financial incentives to invest in localized battery storage or other balancing solutions. This shifts the real-time balancing burden onto the broader electricity market.

Grid reports reveal the operational impact

Official grid data from March 2, 2026 illustrates the scale of this imbalance.

The Renewable Energy Management Centre (REMC) Operation Report recorded forecasting inaccuracies across the grid, reaching a Normalized Root Mean Square Error (NRMSE) of 4.61.

To compensate for this deviation, the Grid Controller of India’s Daily Report on Ancillary Services and SCUC shows dispatchers activating 10,697 MWh of reserve energy, requiring 2,036 MW of immediate up-regulation from more expensive generating units.

Forecast uncertainty versus regulatory asymmetry

Wind and solar generation are inherently variable, and perfect day-ahead forecasting is meteorologically impossible.

However, the regulatory framework governing deviations is asymmetric. While renewable forecasting errors can be substantial, the penalties applied to developers often do not match the actual cost incurred by the grid to procure reserve power.

This creates a structural imbalance where grid operators must absorb the operational and financial consequences of forecast inaccuracies.

Regulatory implication

The Central Electricity Regulatory Commission (CERC) may need to recalibrate deviation settlement mechanisms to better reflect the real-time costs of activating ancillary reserves.

Aligning forecasting penalties with actual balancing costs could incentivize improved forecasting accuracy and investment in storage or flexible generation resources.