If you had to guess where India’s biggest battery orders were going, a coal station would probably not be the answer. Solar farms, yes. Substations, maybe. But coal?
That is nevertheless where a great deal of it is going. NTPC — India’s largest generator — has been allocated 5 GWh of battery storage to install across 14 of its thermal power stations, and the first tranche has already been auctioned. Understanding why makes the rest of the Indian storage market easier to read, because the reason has almost nothing to do with coal and everything to do with solar.
The problem solar created for coal
For most of their history, Indian coal units did one job: run flat out, more or less continuously, and let hydro and gas handle the variation. Baseload is not a marketing term. It is a description of a machine designed to sit at one operating point.
Large-scale solar broke that arrangement, and it did so in a specific way. Solar generates in the middle of the day. India’s demand peaks in the evening, after sunset. So the daily shape a thermal fleet now has to absorb looks like this:
- Morning: solar comes up. Thermal units are backed down to make room for it.
- Midday: solar is at full output. Thermal units sit at technical minimum, or close to it.
- Sunset: solar falls away in two hours while demand is still climbing toward its peak. Thermal units must ramp hard.
- Night: demand falls. Thermal backs down again.
Every one of those transitions costs something real:
- Heat rate worsens at part load. A unit at 55% of rating burns more coal per unit of electricity than the same unit at 90%. You pay for the flexibility in fuel.
- Thermal fatigue. Boiler drums, headers, superheater tubes and turbine rotors expand and contract with each cycle. Repeated cycling consumes design life, and the damage is cumulative and largely invisible until something fails.
- Maintenance and forced outages rise. More cycles means more tube leaks, more valve wear, more unplanned outages.
- Ramp limits bind. A coal unit’s ability to change output is measured in a few percent per minute. When solar falls faster than that, something else has to fill the gap.
This is the context for the whole conversation, and it is the same gap we describe from the grid side in India’s evening peak storage gap.
What the battery actually does
Place a battery at the plant boundary, on a common bus with the units, and the coal plant’s problem changes shape. The unit no longer has to follow the grid; the battery does that, and the unit follows the battery.
In practice:
- Midday. Rather than pushing the coal unit down to technical minimum, keep it at a more efficient output and route the difference into the battery. Or charge from the grid when system frequency is high — that is, when the grid has surplus and wants someone to absorb it.
- Evening peak. The battery discharges. The coal unit does not have to make a violent ramp, because part of the ramp has already been stored.
- Fast response. Between those hours, a battery on a plant bus can hold frequency and provide ancillary services far faster than any turbine — milliseconds rather than minutes.
The result is a station that runs closer to a steady, efficient operating point while still presenting a flexible profile to the grid. Fewer cycles, better heat rate, less fatigue, and an evening peak contribution that the plant could not otherwise make.
Why unrequisitioned surplus is the key term
Site selection for NTPC’s 5 GWh follows the availability of unrequisitioned surplus (URS) at each station, and that phrase deserves unpacking because it explains the economics.
A central generating station signs power purchase agreements with beneficiary distribution companies. Each day those discoms requisition — schedule — how much they want. Often they want less than the station has declared available, because demand was lower than forecast or because cheaper power was available on the exchange. The gap between declared availability and what was actually scheduled is the unrequisitioned surplus.
For the generator, URS is frustrating: the plant is available, the fixed charge is being paid for that availability, and the energy is simply not taken. For a battery, URS is close to ideal charging energy — it is already at the right voltage, on the right bus, inside the plant boundary, and nobody else wanted it.
So the stations with the most persistent URS are the stations where a battery has the most to work with. That is why the allocation is spread across many sites rather than concentrated in a few large ones.
Where the first tranche went
NTPC completed an auction covering 2,334 MWh — Lot-I of a larger 500 MW / 2,000 MWh programme — across seven thermal stations in six states.
The winners were a mix of infrastructure contractors, engineering firms and specialist storage players — G R Infraprojects at Mouda, Enviro Infra Engineers at Kudgi and Ramagundam, Solarworld Energy Solutions at Solapur, NTPC GE Power Services at Barh, Pace Digitek at Nabinagar and Enrich Energy at Simhadri. Each also carries 11 years of operation and maintenance alongside integration with the host plant.
That O&M tail is worth pausing on. It tells you the buyer’s concern is not the delivered box but the availability of the asset a decade out — the same shift toward availability guarantees and long-term spares commitments that now characterises every serious Indian storage procurement.
NTPC’s wider capital commitment is on the same trajectory: the board has approved around ₹8,996 crore covering BESS investment alongside the Meja Stage-II thermal expansion.
How it gets paid: the tariff side
Two CERC actions matter here.
The Terms and Conditions of Tariff (Second Amendment) Regulations, notified 1 December 2025, created the Integrated Energy Storage System (IESS) — storage co-located with a generating station or transmission system on a common bus, used for grid reliability, transmission deferral or flexible operation. For plant-co-located storage the key provisions are:
- Gains split 50:50 between the generator and the beneficiaries, after fixed and variable storage costs are met. The discoms that hold the PPA share in the upside rather than the generator keeping it all.
- Charging sources are broad: the host plant, another generator, the grid during high-frequency periods, or the open market.
- Performance norms: minimum 85% round-trip efficiency, minimum 90% availability, 5% auxiliary consumption.
- A 12-year depreciation life for battery assets.
- Supplementary tariff filings within 30 days of commercial operation.
Then, on 20 March 2026, CERC issued regulations specifically for determining the tariff of battery energy storage systems installed at thermal generating stations — turning the framework into a method a station can actually file under.
The round-trip efficiency norm is the one to watch in operation. At 85%, roughly one unit in seven that goes into the battery does not come out, which is why the cost of charging energy dominates the economics and why URS — energy nobody else bought — is the resource that makes the arithmetic work. We go through that arithmetic in round-trip efficiency and degradation.
Not only lithium
One detail that tends to get lost. At Kudgi, alongside the lithium system, NTPC is evaluating a 3 MWh vanadium redox flow battery and a 144 MWh CO₂ battery, targeted for commissioning around October–November 2026.
A thermal station is an unusually good host for these alternatives. Land is available, footprint is less precious than at an urban substation, there is existing water and steam infrastructure, and there are operating staff on site who are already comfortable with rotating machinery and pressure systems. Long-duration technologies that struggle to compete with lithium on a tight site have a better hearing here. We compare the chemistry trade-offs in vanadium flow batteries in India.
The honest counter-argument
It would be incomplete to write this without stating the objection. Attaching storage to a coal plant improves the coal plant’s economics. If the battery charges from genuine surplus that would otherwise have been wasted, and reduces cycling damage on plant that is running regardless, the effect is clearly good — less fuel per unit, longer asset life, and an evening peak served without a new peaking plant.
If, instead, it becomes a reason to schedule coal in hours that would otherwise have been served by renewables, the emissions arithmetic reverses. Nothing in the tariff regulations settles that question. It will be settled by dispatch practice, by how URS is actually priced, and by how much competing storage sits elsewhere on the system. Anyone assessing these projects should ask what the battery’s assumed charging source is, and check whether it is surplus or displacement.
Tariff regulations, tender terms and VGF conditions in this area change by notification — the thermal-station tariff regulations are themselves only months old — so verify current terms against the latest CERC and Ministry of Power notifications before committing to a bid or a financial model.
What this means for you
If you are a thermal plant operator, the case for co-located storage is mostly a plant-integrity case rather than an energy-trading one. Before sizing anything, quantify what cycling is costing you: heat rate penalty at part load in rupees per year, incremental maintenance attributable to cycles, and consumed design life on the pressure parts. Those numbers, plus your URS history, determine whether two hours or four hours is the right duration — a choice we set out in two-hour versus four-hour storage.
If you are a developer or EPC, this is a different bid from a standalone tender. You are integrating with a live generating station: a common bus, the host’s protection scheme and control philosophy, plant safety rules, and an operating crew whose priorities are the boiler and turbine rather than your battery. The eleven-year O&M tail means the winning bid is the one that can staff and stock a site inside a working power station for a decade, which is a different competence from building fast.
If you are a discom or beneficiary, watch the 50:50 gain-sharing provision, because it is the clause that decides whether this buildout lowers your cost of evening supply or simply improves a generator’s margin. Ask what the assumed charging source is, and at what price it is booked.
If you are a C&I buyer, the relevance is indirect but real. A fleet-wide shift of storage into thermal stations is aimed at the evening peak, which is precisely the window driving your own time-of-day exposure. It may soften the peak over time; it will not remove your own demand charges. For that, storage on your side of the meter — sized to your load and paired with renewable firming where you have solar — remains the direct lever, and container-class systems such as the ADESS 6500 are the utility-scale end of the same hardware family being installed at these plants.
If you want to know what co-located or standalone storage would do to your own generation profile or your evening cost of power, start with the operating data rather than a product. Talk to our team and we will work through it with you.
Technology and tariff snapshot as of September 2026. Indian storage regulation is moving quickly through CERC and Ministry of Power processes; verify current notifications before design, bidding or investment decisions.