CEA proposes new ramping rules for coal power plants

The Central Electricity Authority (CEA) has proposed a series of changes to the scheduling of coal-based thermal power plants following consultations with generating companies, equipment manufacturers and grid operators on the impact of flexible operations.

The recommendations emerged from three meetings held on March 11, May 8 and June 18, 2026, chaired by Principal Chief Engineer-II B.C. Mallick. Participants included NTPC Limited, Damodar Valley Corporation (DVC), Bharat Heavy Electricals Limited (BHEL), Rajasthan Rajya Vidyut Utpadan Nigam Limited (RVUNL), Grid Controller of India Limited (Grid-India), and Adani Power Limited.

The discussions focused on balancing two competing objectives: maintaining grid flexibility to support increasing renewable energy generation while reducing wear and tear on coal-fired units.

Ramping concerns

Generating companies informed the CEA that the existing methodology for assessing ramp rates does not adequately reflect the operational characteristics of thermal power plants.

At present, ramp rates are measured using the change in average generation between two consecutive 15-minute time blocks. However, thermal units typically pass through three stages during load changes—boiler response, active ramping and stabilisation.

According to generators, this means units often need to achieve instantaneous ramp rates of up to 2.5% per minute during the active ramping phase, which generally lasts five to seven minutes, in order to meet the prescribed average ramp rate of 1% per minute over a 15-minute block.

BHEL informed the authority that its Advanced Process Control (APC) system supplied to NTPC has demonstrated ramp rates of up to 3% per minute during individual tests, although these measurements exclude boiler response and stabilisation periods.

DSM issues

Generating companies also raised concerns regarding the treatment of deviations during ramping under the Central Electricity Regulatory Commission (CERC) Deviation Settlement Mechanism (DSM) Regulations, 2024.

They stated that differences between scheduled and actual generation during the initial stages of ramping frequently attract DSM charges, despite the units operating within their technical limitations.

National Load Despatch Centre (NLDC) clarified that deviations are calculated on the basis of energy delivered rather than scheduled MW. While generators could theoretically begin ramping one block in advance, doing so may result in DSM charges during the preceding block.

Grid-India noted that a concession already exists under tariff regulations, where a block-wise ramp rate of 0.5% MW per minute is treated as equivalent to 1% MW per minute for return on equity purposes. NTPC requested that a similar approach be adopted under DSM provisions.

Scheduling practices

Another issue highlighted during the meetings was the limited notice provided for schedule revisions.

Generators stated that ramp-up and ramp-down instructions are often received only 8 to 15 minutes before the start of a scheduling block, leaving limited time for units to respond smoothly.

NLDC explained that schedules for inter-state generating stations are prepared by Regional Load Despatch Centres (RLDCs), while schedules for independent power producers are based on power purchase agreements and mutually agreed dispatch schedules.

According to NLDC, generating stations participating in Security Constrained Economic Despatch (SCED) receive schedules around 30 minutes in advance, while participants in Ancillary Services receive schedules 15 minutes ahead of time.

The load despatch body also stated that implementation of SCED in April 2019 resulted in a 29% reduction in the number of schedule changes and a 42% reduction in the aggregate MW quantum of schedule revisions during the pilot phase.

Key recommendations

Following the consultations, the CEA concluded that frequent and consecutive ramping, rather than operation at low loads, is the principal cause of mechanical stress in coal-based units.

The authority recommended that consecutive ramp-up and ramp-down instructions for the same generating unit should be avoided. Instead, a group of units should be designated for ramping up and another for ramping down, with schedules rotated across a larger pool of plants rather than being assigned solely on the basis of Merit Order Dispatch.

The CEA also proposed a revised operating philosophy under which units ramped down to Minimum Technical Load (MTL) of 55%—and eventually 40% in line with existing regulations—should remain at that level until renewable generation begins to decline. Similarly, units that begin ramping up should continue until reaching 70% load before receiving any further ramp-down instructions.

For grid balancing requirements, the authority recommended greater use of hydropower plants, gas-based stations, pumped storage projects and Battery Energy Storage Systems (BESS), reducing dependence on thermal stations for short-term balancing needs.

Revised ramp rates

The authority proposed differentiated ramp rates based on plant loading levels.

For generating units operating between 55% and 70% load, it recommended an average scheduled ramp rate of 0.8% per minute over a 15-minute block. According to the CEA, this would translate into a maximum machine ramp rate of approximately 2% per minute, consistent with existing technical standards.

For loads between 70% and 100%, the existing average scheduled ramp rate of 1% per minute could continue.

The CEA also observed that thermal units inherently follow a diagonal generation profile during ramping and cannot match the vertical step changes reflected in scheduling blocks. Consequently, some difference between scheduled and actual generation is unavoidable.

To address this, the authority recommended applying a factor of 0.5 to scheduled generation during ramping periods for the purposes of DSM calculations, thereby reducing penalties arising from lower generation during ramp-up and excess generation during ramp-down.

In addition, the CEA proposed introducing stabilisation periods between successive ramping instructions, allowing generating units sufficient time to achieve steady-state operation before receiving further schedule changes.

Next steps

The CEA noted that implementation of several recommendations, including revised DSM treatment and mandatory stabilisation periods, would require amendments to existing regulations governing flexible operation and deviation settlement.

It has sought additional inputs from original equipment manufacturers and generating companies regarding the maximum duration for continuous ramping before a stabilisation block becomes necessary.

The authority concluded that the current scheduling framework requires revision to better align with the physical operating characteristics of coal-based generating units while preserving the flexibility needed to integrate increasing levels of renewable energy into the grid.

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