India’s Central Electricity Regulatory Commission (CERC) sets the principal framework for projects connected to India’s interstate transmission system (ISTS), alongside procedures issued by the National Load Despatch Centre (NLDC), Regional Load Despatch Centres (RLDCs) and other system operators. Projects connected within a state are generally subject to the relevant State Electricity Regulatory Commission (SERC), State Load Despatch Centre (SLDC) and state grid code.

These frameworks may define different capacity thresholds, submission deadlines, revision windows and settlement mechanisms. Requirements in Karnataka, Tamil Nadu, Rajasthan, Gujarat and Andhra Pradesh should therefore not be treated as interchangeable. A forecasting system designed around an ISTS project may not meet the data format, timing or aggregation requirements of an SLDC-connected plant. The applicable power purchase agreement (PPA), open-access arrangement or market-participation agreement may add further obligations. The result is a regulatory market in which the question is not simply whether a solar plant must forecast – It is who requires what, at which connection point and under which settlement regime.

Core requirements

For utility-scale projects, the central operational requirement is a schedule for the following day in 15-minute time blocks. A full 24-hour schedule contains 96 intervals. The forecast is submitted by the seller, generator or an appointed Qualified Coordinating Agency (QCA), depending on the applicable arrangement. This day-ahead schedule is not necessarily the complete service requirement. The relevant CERC or state procedure may specify a submission cut-off, a minimum lead time and a defined number of intraday revisions. Revisions reflect changes in cloud cover, plant availability, curtailment or grid conditions. Providers must therefore manage submission status, timestamps, accepted versions and effective times.

Some state procedures, PPAs and utility processes also call for week-ahead forecasts for outage planning, transmission coordination or portfolio management. These should be distinguished from the day-ahead schedule used for settlement. A 24-hour forecast in 15-minute resolution is a useful baseline, but not a complete nationwide specification. Forecasts are distinct from telemetry. Load-dispatch centers require current measurements of active power, voltage, frequency and plant status. The forecast describes future injection, while supervisory control and data acquisition (SCADA), meters and weather stations describe the current plant condition.

Beyond compliance

Forecasting also supports maintenance, cleaning, inverter availability, procurement, portfolio management, ramp assessment and balancing. This creates demand for several forecast horizons. Numerical weather prediction models integrating AI support day-ahead and multi-day forecasts, while local irradiance, plant data and satellite models help correct them.

For the shortest horizons, all-sky imagers can track cloud movement across the plant and estimate changes in irradiance and power output. Such systems support “nowcasting” from a few minutes to around 30 minutes ahead, depending on site conditions and model performance. This short-term layer is particularly relevant in regions where rapidly developing clouds create steep ramps. It does not replace the day-ahead schedule, but can improve intraday revisions, balancing decisions and operator awareness. For floating solar, the model may need to account for reservoir-specific humidity, wind exposure, haze, water-surface temperature and changing access to meteorological equipment.

Forecast performance depends on data quality and representativeness. Providers may need plant-level SCADA, irradiance sensors, automatic weather stations, outage records and curtailment instructions. Time synchronization is critical because a mismatch between forecast intervals and settlement meters can create apparent errors even when the meteorological prediction is sound.

The Central Electricity Authority published guidelines for automatic weather stations for solar and wind power plants in July 2025. The guidance is relevant to the measurement layer supporting forecasting, although each project must still verify the requirements imposed by its SLDC, RLDC, connectivity agreement or tender documents. Data exchange must also meet cybersecurity and interface requirements, often involving the EPC contractor, SCADA supplier, QCA, plant operator, utility and grid control center.

Deviation settlement

The main commercial consequence of an inaccurate schedule is deviation settlement. The relevant calculation compares scheduled and actual injection in each settlement block. Charges or credits can depend on the direction and magnitude of the deviation, the applicable contract or prescribed rate, the project category and the current regulatory formula. The details should not be taken from older summaries. CERC lists an order dated March 31, 2026, determining the value of “X” for wind and solar sellers from April 1, 2026. Providers should verify the operative order, subsequent clarifications and the applicable state regulation before estimating financial exposure.

Failure to submit a required forecast can lead to rejection, substitution or settlement against the last accepted submission. Repeated non-compliance may trigger notices, contractual remedies or regulatory action.

Solar forecasting in India is therefore shaped by two parallel requirements: the technical need to predict variable generation and the regulatory need to submit an accepted, auditable schedule. Providers that offer only a generic weather forecast may not address the full operational problem. The stronger proposition combines day-ahead scheduling, intraday revisions, plant-to-meter reconciliation, advanced short-term nowcasting, data-quality controls and deviation-risk reporting.

Whether India’s different state frameworks eventually converge remains open. Until then, the practical market opportunity will belong to providers able to answer, for each project, who requires what.

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