Green paper

Renewable is elbowing out coal: Can it continue the growth momentum?

The whole power universe seems to be favouring the growth momentum of renewable energy (RE) in India. Despite the policy changes, demand fluctuations and supply side disruptions, RE capacity addition has accelerated. In 2024, India added a record 25 GW of solar capacity in 2024, marking its strongest year of solar expansion to date. The momentum has continued into 2025, with deployments already exceeding 25 GW by October.

One of the key drivers has been the execution of long expected expiry of waiver on inter-state transmission system (ISTS) for RE projects. The gradual phase down of the ISTS waiver commenced from July 2025. The waiver was aimed at bringing down the cost of supplying RE. Now that RE is as competitive as other power sources, the government’s rationale is this support is no longer required. Add to it also the fact the ISTS network is facing congestion due to the concentration of RE projects in one region and delays in corresponding power transmission infrastructure.

To latch on to the waiver, several RE project developers have started compressing the project timelines to secure the benefits before its expiry. In parallel, a flurry of highly competitive auctions has built a substantial project pipeline and attracted enthusiastic offtakers, resulting in rapid on-ground deployment. These forces are expected to sustain the sector’s momentum in the near term. Unless significant headwinds emerge, India’s solar capacity growth is likely to maintain its current pace over the next few years.

Coal facing new realities

The plant load factors (PLFs) or the utilisation rate of India’s coal-based generation fleet is declining steadily, currently hovering around 66%. It is projected to fall further to about 55% by FY2031–32 if the country achieves the renewable and storage capacity targets outlined in the National Electricity Plan (NEP) 2023–32. While the rising share of RE might have played a role in declining PLFs, the new coal capacity in the pipeline will also further cannibalise utilisation levels across the fleet.

Coal plants have historically been designed and deployed for steady-state ‘baseload’ operations. But as RE’s share increases in the energy pie, coal would need to move more in rhythm with renewables. Thermal power plants would increasingly be required to operate flexibly – ramp down to technical minimum levels during solar hours and ramp up again to meet evening and night demand peaks.

This paradigm shift is expected to create both planning and operational challenges for the grid operators. The more complex this balancing act becomes, the more important it will be to demonstrate to state governments and distribution companies - the ultimate offtakers, how RE can contribute to reliable and affordable supply. This is where India risks entering a challenging phase in its power sector transition: where the end goal seems imaginable, but the steps in between are fraught with friction.

Balancing act

Against the backdrop of falling PLFs across the coal fleet, planning future additions of both coal and renewables is becoming increasingly complex. The two are now competing to serve the same demand pool. This is a sharp contrast from earlier years when renewable energy primarily catered to incremental demand. As renewables expand their share in total generation, they are now beginning to displace coal generation.

Compounding this challenge is India’s limited energy storage capacity, currently below 1 GWh. While several battery storage auctions are underway, delivery timelines remain uncertain, and experience with the technology is still limited from the buyer’s perspective. In the absence of sufficient storage, there has been a spate of coal procurement plans to meet non-solar-hour peaks.

This growing dependence on coal for flexibility also presents a planning challenge. For a DISCOM, portfolio optimisation approach may take a backseat and short-term reliability concerns take precedence. The prevailing reliance on long-term power purchase agreements (PPAs) further compounds the risk. DISCOMs remain bound by multi-decade contracts for coal assets, many of which may be required for less than half the year. This means paying substantial fixed charges for underutilised capacity. This also creates a growing risk of stranded coal assets for the DISCOM.

Ember’s modelling suggests that in an optimised dispatch (market operations closely resembling the market based economic dispatch- MBED), the more expensive coal units (those with marginal energy charges above ₹3 per kWh) face risk of idling for extended periods, as they fall behind cheaper renewables and pithead-based coal plants in the merit order.

However, India’s dispatch system in the current form is not centrally optimised. Power continues to be scheduled through bilateral power purchase agreements (PPAs) between states and power generators, rather than market-based mechanisms. As a result, these dynamics will unfold unevenly across states and generators, with higher marginal cost plants likely to face the brunt more.

There are also likely to be operational challenges associated with such sharp ramps and extended periods of minimum-load operations for coal units. These conditions can increase generation costs through poorer heat rates, leading to lower fuel efficiency, a need for additional capital investment to handle frequent cycling, and higher risks of outages or equipment stress.

However, pilots conducted by state owned power generator NTPC in recent years to test the limits of coal plant flexibilisation across both older and newer units, indicate that these challenges can be managed at a modest cost increase, typically in the range of ₹0.25–0.50 per kWh. The Central Electricity Regulatory Commission (CERC) also provides a part-load compensation framework for central generators (ISGS) that helps offset efficiency losses during flexible operations.

While these findings show that technical and economic flexibility is achievable, it remains to be seen how state generating companies will adapt their operating practices as renewable penetration rises. Their decisions may be shaped not only by cost economics, but also by institutional incentives and political considerations.

New coal is not good news

In the middle of these rapidly evolving new dynamics in the power market, the question arises on the economics of existing and new coal fleet. There are two key concerns that need to be addressed to understand how coal tariffs could evolve in the coming years.

The first relates to existing coal assets, many of which are expected to be utilised for less than half of the year as RE penetration rises. Ember’s analysis of the existing national coal fleet indicates that an average generation cost (inclusive of both capacity and energy charges) of ₹4.78 per kWh under normal utilisation can effectively appear to cost as high as ₹6 per kWh once future underutilisation is factored in. This occurs because fixed costs, which are paid for capacity availability, are spread over a thin volume of actual generation. This inflates the average cost of supply for DISCOMs.

This simplified estimate conceals significant variation across generator types, even though the underlying reality remains the same: lower utilisation inflates the overall cost of coal portfolios for states. ISGS plants and the newer, more agile fleet, which are mandated to operate flexibly to accommodate growing solar generation under central directives, may consequently appear more expensive in effective tariff terms. However, this outcome reflects a systemic adjustment rather than the fault of any generator or the planner.

The second concern relates to the increasing cost of new coal capacity, a trend evident in several recent auctions. The rise in tariffs, particularly the fixed-cost components stems from multiple factors. These include growing mandates for higher-efficiency technologies such as ultra-supercritical units, requirements for advanced emission control systems, and additional capital expenditure to enhance operational flexibility.

While generators are generally insulated from dispatch risks, since their capital costs and returns are recovered through fixed charges, they may be pricing in regulatory and broader macroeconomic risks through higher PPA bids. In some cases, this has led to a form of front-loading fixed costs, effectively shifting expenses from variable to fixed components. This allows generators to cover the inefficiencies of part-load operations as well as remain competitive in the merit order, where lower energy charges improve dispatch prospects. Even if generators face occasional operational losses per unit generated, the heavily loaded fixed costs ensure financial recovery.

However, this structure can increase overall PPA costs for buyers due to fixed cost issues, which amplifies further due to the bigger fixed cost base being built into the tariffs. This is also concerning and might involve regulatory scrutiny given the cost competitiveness of firm renewable energy (paired with storage) auction prices that have been discovered through 2024-25.

The converging solutions

There are important shifts happening which can ease the transition for the DISCOMs. States would need to redesign their resource planning and power purchase contracts. Some states are already doing so. In June this year, Gujarat signed a PPA with THDC Limited for flexible/variable supply from Tehri variable-speed pumped-storage project. This PPA would ensure flexible power dispatch with variable output and help meet peak/ancillary needs of the state.

During the same month, Rajasthan finalised the tariff for a 500 MW/1000 MWh battery energy storage project. The project aimed at grid stability with more RE integration saw a discovered price in the range of ₹2.21 to ₹2.24 lakh per MW per month – the lowest rates in India for standalone BESS projects.

Madhya Pradesh in September issued a unique tender for 600 MW solar-plus-battery-storage project (divided into two units of 300 MW each) at the Morena Solar Park. Each unit must be capable of supplying 220 MW in a ‘firm and dispatchable’ manner at any time block. The project is estimated to have 95% power supply availability. To ensure the same, it is paired with a Battery Energy Storage System (BESS) sized at roughly 880 MWh (for the full 600 MW plant) in a ‘dual-cycle’ format.

The supply obligation by the project developer would cover three periods. One, real-time solar generation during daytime (solar hours). Second, for the evening peak period, BESS which was charged through solar during the day would supply power. Third, during the morning peak period, the battery is charged overnight from cheaper grid power and discharges in the morning peak before solar output ramps up.

DISCOMs may benefit from exploring more flexible PPA structures as well. Adopting short to medium-term PPAs (for example, 5-7 years) instead of traditional 25-year contracts can offer greater flexibility to DISCOMs to rethink procurement portfolios as the generation mix evolves. Madhya Pradesh and Uttar Pradesh have recently partnered to develop 8,000 MW of solar power projects which would supply to both states during different seasons. MP’s peak demand period stretches from October to March, aligning with the rabi crop season, while UP’s demand surges between April and September, a duration that includes the kharif crop season. The solar power generated would be distributed based on these patterns.

Additionally, states can also move from a two-part to a three-part tariff structure, where the fixed charge for availability is partially replaced by a performance-linked component rewarding generation during stress or peak periods. This could better align incentives with needs of a state’s/DISCOMs system. These reforms hint at a push towards flexible utilization, allowing buyers and generators to adapt more dynamically to increasing RE penetration.

About the authors

Duttatreya Das is Energy Analyst and Neshwin Rodrigues is Senior Energy Analyst at Ember’s Asia program covering power and renewables.
Shreya Jai is Energy Lead at Climate Trends.