Recommendations

While there are multiple pathways to drive this transition, this report focuses on two that are most relevant to India’s current context: managing existing coal capacity better without overbuilding, and expanding storage capacity — not just in quantity, but in ways that deliver the greatest value to the power system.

India needs to improve coal plant flexibility to operate at reduced minimum loads, prioritise short- or medium-term power contracts connected to demand peaks, and reform market design to enable more flexible, centralised dispatch of both central and state-level thermal plants. For storage, the current capacity is insufficient to support planned solar growth and reliability. Therefore, the country needs to prioritise tracking storage deployment, with part reserved for ancillary services. Further, storage needs to be compensated for its superior response capabilities in grid reserves, requiring policy reforms and careful monitoring.

There are a few strategies to better manage the existing coal fleet, while allowing a greater share of renewables into the system:

• Technical: Regulators and technical authorities should fast-track evaluations to identify thermal plants capable of flexing down to 40% of their rated capacity (from the current 55% the benchmark) and establish appropriate compensation mechanisms that balance the interests of both generators and power purchasers. Going forward, coal plants should be mandated to operate flexibly — at least down to 40% MTL as a statutory requirement, with provisions to enable two-shift operations wherever technically and economically feasible.
• Contractual and Regulatory Reforms: DISCOMs should avoid long-term, 25-year power purchase agreements (PPAs) amid the rapidly evolving power sector. Instead, coal-based power should be secured through short- or medium-term contracts (~3-5 years), which are typically traded on an energy-charge basis without rigid fixed-charge commitments.

Even where DISCOMs agree to pay a fixed charge over the plant’s life, this component should be linked to performance during peak demand periods. In practice, this would mean that supplying power during peak seasons earns generators higher fixed cost recovery, while lean periods would attract lower or no fixed payment. Such a structure would ensure that coal plants operate when they are genuinely needed and have a financial incentive to do so efficiently. Maintaining a uniform fixed charge throughout the year, irrespective of system need, risks turning coal contracts into an “expensive lunch” for the DISCOMs.

• Improved market design: To effectively absorb the midday solar surge, India currently relies heavily on central ISGS generators and a limited number of state-level plants. However, many intra-state generators (operating within the state) remain unresponsive to system flexibility needs, leaving a narrow pool of thermal capacity available for balancing solar.

To enable deeper renewable integration, state-level thermal generators must be integrated into the central optimisation pool, allowing their operations to be dispatched more flexibly alongside central plants. This would achieve three key outcomes: (i) a larger pool of thermal capacity available to balance the midday solar surge, (ii) adequate downward reserves for grid operators during high solar output hours, and (iii) optimised economic dispatch (SCED), wherein higher-cost plants are backed down and lower-cost ones prioritised.

This can be done with better adequate incentive mechanisms for the intra-state plants, developing a part-load compensation framework for these plants (as done for ISGS plants at the central level) and a push towards more stable grid operations (for example, making penalties for deviation from schedule stricter).

Adequacy of planned storage and monitoring growth in storage addition

Ember’s estimates suggest that the storage volume assumed in the NEP is below what is required to integrate the planned solar capacity while maintaining reliability. Additional storage is needed to cover operational reserves during solar hours and ensure a material share is explicitly available for ancillary services. If India is to meet the planned solar additions, storage should be procured at no less than the NEP-indicated level—and preferably higher—with a portion ring-fenced for ancillary services. Without this, the system risks higher curtailment. 

We estimate system-wide renewable curtailment of 2.5–3.8% under modelled operations. Most of this stems from the need to maintain reserves while keeping enough thermal units online for the evening ramp—about 1.3–2.0 percentage points of curtailment is due to reserves alone. Storage is not required to drive curtailment to zero, but this range makes clear that the cost-effective scale-up of variable renewable energy depends heavily on storage growth. In short, track storage builds closely—both total volume and the share explicitly available for reserves. 

Market enablers for ancillary participation

While coal units can and should contribute to reserves, they face MTLconstraints and associated flexibility costs. By contrast, storage can provide faster, deeper, and more accurate frequency response. However, its cost-effectiveness—though strong from a system perspective—can be hard to justify under current Secondary Reserve Ancillary Service/Tertiary Reserve Ancillary Service compensation levels.

Two near-term entry points for storage are:

• Secondary SRAS, where response quality is explicitly compensated.
• Reduction of emergency TRAS, including instances of negative prices where generators are paid not to generate.

Policy should explicitly enable and compensate storage for reserve provision, designed from a system-wide lens with clear products. Storage build-out should be closely monitored to ensure sufficient volumes are ring-fenced for reserves.