India has eliminated generation scarcity – capacity stands at 548 GW with an 874 GW target for 2031-32 – but the grid has shifted from a pipe that delivers power to a queue where states, traders, and renewable developers compete for the same constrained corridors at the same hours. The bottleneck is no longer whether electrons exist, but whether they can move when and where they are needed.
From Scarcity to Congestion: How the Grid Became a Queue
Three decades of capacity additions – coal, hydro, then solar and wind – have pushed India past the threshold where supply shortfalls drove policy. The Central Electricity Authority’s latest data show peak demand met consistently above 99 percent nationally, with load-shedding relegated to local distribution faults rather than systemic deficits. That achievement, however, has exposed the next layer of the problem: the transmission network was built for a unidirectional flow from large pithead plants to load centres, not for the multidirectional, time-varying exchanges that now dominate.
Inter-regional transfer capacity has grown, but not in step with the diversification of generation. Solar-heavy states like Rajasthan and Gujarat export midday surplus to the north and west, while wind-rich Tamil Nadu and Karnataka push power toward the southern corridor during evening peaks. At the same time, coal plants in the east and centre must ramp to cover the post-sunset ramp across multiple regions simultaneously. The result is a handful of high-voltage corridors – notably the Raipur-Pugalur HVDC link, the Champa-Kurukshetra bipole, and the 765 kV AC spines linking the western and northern grids – operating at or near thermal limits during critical hours.
Grid-India’s daily market coupling reports now routinely show congestion charges (transmission congestion charges in the day-ahead and real-time markets) spiking when renewable output peaks align with inter-state transfer limits. In Q1 2024, congestion revenue on the power exchange exceeded ₹1,200 crore in a single month, a figure that was negligible five years ago. That revenue is not a market efficiency signal; it is a scarcity rent on wire capacity that did not exist when the system was generation-constrained.
Why Storage and Market Design Must Evolve Together
The queue dynamic creates a structural mismatch between how renewable capacity is valued and how the grid can absorb it. A solar plant in Rajasthan earns the same energy price whether it generates at 11 a.m. or 2 p.m., but the transmission corridor to Delhi may be fully subscribed at 11 a.m. and have spare capacity at 2 p.m. – or vice versa, depending on northern demand. Without time-differentiated transmission pricing or locational marginal pricing that reflects congestion, developers have no incentive to co-locate storage or shift output.
That points to a broader sector trend: the levelised cost of solar-plus-storage in India has fallen to roughly ₹3.5-4.0 per kWh for four-hour duration, making firm renewable capacity competitive with new coal on a levelised basis. Yet the current market design – uniform pricing within a region, congestion managed through post-hoc surcharges – does not reward the flexibility that storage provides to the transmission system. If a battery charges when the corridor is uncongested and discharges when it is constrained, it relieves the queue, but the merchant revenue stack for that service is opaque.
By comparison, the ERCOT market in Texas uses nodal pricing that directly compensates storage for congestion relief; batteries there earn significant ancillary service and energy arbitrage revenue precisely because locational prices reflect wire scarcity. India’s move toward market-based economic dispatch (MBED) and the proposed day-ahead market coupling across all regions could introduce similar signals, but the timeline remains uncertain – the Central Electricity Regulatory Commission’s discussion paper on MBED dates to 2021, and pilot implementation has been limited to a few states.
If the queue dynamic persists without price signals that value flexibility, the 874 GW target for 2031-32 will include a growing share of “stranded” renewable capacity – generation that cannot be evacuated during its peak production hours. Roughly 30-40 GW of solar and wind capacity already faces curtailment risk during high-generation, low-demand periods in the southern and western grids, according to industry estimates. That figure could double by 2027 if transmission additions lag renewable additions by even 12-18 months, which is the typical gap given right-of-way acquisition timelines for 765 kV lines.
Who This Affects
- Transmission planner (CTU/STU): Must prioritise dynamic line rating, series compensation, and HVDC overlays on existing corridors over new greenfield lines – right-of-way delays make new 765 kV AC lines a 5-7 year proposition, while dynamic rating can unlock 10-15 percent more capacity in 12-18 months.
- Renewable developer: Power purchase agreement negotiations now need explicit curtailment risk clauses and transmission availability guarantees; projects in Rajasthan, Gujarat, and Tamil Nadu should budget for 3-5 percent annual energy loss to congestion unless paired with storage or firm transmission rights.
- State distribution utility: Short-term power purchase costs will become more volatile as congestion charges pass through exchange prices; utilities should hedge via medium-term contracts with firm transmission allocation rather than relying on day-ahead market spot purchases during peak congestion months (April-June, October).
- Storage investor: The revenue case for standalone batteries hinges on CERC finalising ancillary service markets and congestion revenue sharing – track the MBED pilot rollout in 2024-25 as the leading indicator of whether flexibility will be compensated at the nodal level.
What to Watch Next
- Commissioning of the ±800 kV Raigarh-Pugalur HVDC bipole (Pole-3 and Pole-4) – scheduled for late 2024 – which adds 6,000 MW of controlled transfer capacity between the western and southern grids and will test whether HVDC can relieve the AC corridor queue during solar peak hours.
- CERC’s order on the market-based economic dispatch (MBED) pilot expansion beyond the current five states – a nationwide rollout would introduce locational price signals that directly value congestion relief, fundamentally changing the storage business case.
- Central Transmission Utility’s rolling five-year plan (2025-29) for inter-regional corridors – specifically whether the planned 765 kV lines from the renewable-rich western corridor (Khavda, Fatehgarh, Bhadla) to the northern load centres are accelerated from 48-month to 36-month execution timelines via the new “Gati Shakti” right-of-way portal.
- Quarterly congestion revenue data on the Indian Energy Exchange and Power Exchange India – a sustained monthly figure above ₹1,500 crore would signal that wire scarcity is outpacing both transmission build and market-based mitigation.
Bottom line
India’s power sector has solved the generation problem; the queue at the transmission gate is now the binding constraint on decarbonisation, affordability, and reliability – and it will not clear until market signals, storage deployment, and corridor upgrades move in sync.
Read the full report at Energy Central
Note: facts and figures attributed above to reflect that outlet's original reporting. Broader context, cross-sector connections, and forward-looking scenarios reflect independent analysis by our editorial team.
About this article: Drafted by Energy Ai with AI-assisted research and writing based on public reporting, then reviewed under our editorial process before publication.
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