From leased asset to market player

How batteries earn today: the lease

Almost every large battery tendered in India so far has been built under a long-term contract called a Battery Energy Storage Purchase Agreement (BESPA). The developer builds, owns and maintains the battery. The buyer, usually a state discom, sometimes through an intermediary such as SECI, NTPC or NHPC, pays a fixed capacity charge quoted in rupees per megawatt per month.

Three features define these contracts:

• The buyer controls the battery. In Punjab's PSPCL tender, for example, the charging and discharging schedule is in the discom's scope. In the Andhra Pradesh tender run by NHPC, the buying entity supplies the charging power.
• Payment is for availability, not performance in the market. The developer is paid to keep the capacity ready. SECI's standard BESPA charges liquidated damages for unavailable capacity, in one illustrated case at twice the capacity charge.
• The terms are long. Most are 12 years. Odisha's GRIDCO tender uses 15.

For a discom this is an attractive deal. It gets a flexible resource for evening peaks without taking construction or technology risk. One example is the 20 MW / 40 MWh Kilokari battery in south Delhi, built by IndiGrid for BSES Rajdhani and in commercial operation since 1 April 2025. It was built to manage peak demand, cut power purchase costs and defer an upgrade of the 33/11 kV Kilokari substation.

The government has backed this model heavily. In June 2025 the Ministry of Power announced a second Viability Gap Funding tranche of about ₹5,400 crore to support 30 GWh of battery storage, roughly ₹18 lakh per MWh, split between 15 states (25 GWh) and NTPC (5 GWh). Projects must be commissioned within 18 months of signing their contract. The Ministry also extended a 100% waiver of inter-state transmission charges to co-located batteries commissioned by 30 June 2028.

The lease model has a weakness, though. In 2025, competition drove tariffs down faster than costs. The IEEFA–JMK Research review of the 10.4 GW awarded that year found that average standalone tariffs fell about 79.6% between 2022 and 2025, while battery pack prices fell only about 36.5%. The lowest bid, ₹1.48 lakh/MW/month in APTRANSCO's 1,000 MW tender, sat well below the indicative benchmark of ₹2.3 lakh. The report considers nearly 75% of the allocated 2-hour capacity financially risky.

A lease pays the owner a thin, fixed fee. Everything the battery could earn from price swings goes to someone else.

The spread that changes the maths

India's power is traded on exchanges in 96 fifteen-minute blocks a day. As solar capacity has grown, the shape of a typical day has become sharp and predictable. Prices sag through the solar hours, when the grid is full of cheap generation, then climb steeply after sunset as solar output disappears and demand peaks.

How wide is the gap? The day-ahead and real-time markets have a price ceiling of ₹10/kWh, set by CERC from April 2023 (the high-price day-ahead segment is capped at ₹20/kWh). Ember finds that the day-ahead price has sat near that ₹10 ceiling in about one hour in six since 2022, while its worked example puts solar-hour clearing prices near ₹2.6/kWh. A snapshot of the IEX day-ahead market for 22 October 2026 shows solar hours averaging about ₹4.12/kWh against ₹10.00/kWh in the evening peak. JMK Research notes that in April 2026, surplus solar pushed real-time prices close to zero at midday while evening day-ahead prices approached the cap.

Meanwhile the cost of a battery has collapsed. Ember estimates the levelised cost of a 2-hour system at about ₹17 lakh per MWh in 2024, against ₹79 lakh in 2015. Its conclusion is that since early 2024 the average daily day-ahead spread has been larger than the cost of storing a unit of energy. On that basis, a battery trading on its own became profitable for the first time in 2024.

Ember projects returns of up to 17% for a battery commissioned in 2025 that trades only on the day-ahead market. Shorter 1–2 hour systems do better (15–22%) than 4-hour ones (13–18%), because the most valuable hours are concentrated in a short evening window.

Ancillary services: paid to keep the grid steady

Trading the daily spread is not the only revenue. Grid operators pay for reserves that can push power into the grid, or pull it out, within minutes to keep frequency stable. Batteries are among the fastest resources available for this.

CERC's Ancillary Services Regulations, 2022 opened these markets to energy storage, standalone or aggregated, connected to the inter-state or intra-state grid. Grid-India runs them as the nodal agency.

How much does this add? Ember's modelling puts ancillary services at about 15–20% of a merchant battery's earnings, with day-ahead trading supplying the other 80–85%. It also raises the projected return from up to 17% to up to 24%.

Experience abroad suggests treating that extra slice with care. In Texas (ERCOT), the volume batteries offered into ancillary markets nearly tripled in 2024 and clearing prices fell. Modo Energy reports that energy arbitrage rose from about 25% to 76% of ERCOT battery revenue in the year to June 2025. Enverus finds ancillary services falling from 84% to 48% of revenue over two years. In Australia's national market, Modo cites AEMO figures putting arbitrage at 97% of battery revenue in Q1 2026.

Ancillary markets are small. They pay well for the first batteries and quickly fill up. Over time, the energy spread is what pays for a battery.

Merchant batteries are already here

A merchant battery has no long-term buyer. It buys and sells on the exchanges, offers ancillary services, and keeps the margin.

• The first one. Juniper Green Energy's 100 MWh project in Bikaner, Rajasthan, which the company calls India's first merchant battery, commissioned 60 MWh in December 2025 and the remaining 40 MWh on 23 January 2026, after trial operation and approval from the Northern Regional Load Despatch Centre.
• The share. JMK Research reports that merchant projects make up about 80% of roughly 6.8 GWh of operational battery capacity. Its September 2026 monthly update puts total commissioned battery capacity at 9.6 GWh.
• Curtailed solar as fuel. In August 2026 the Ministry of Power allowed renewable projects to use power curtailed under temporary connectivity (T-GNA) to charge an additional co-located battery and sell the stored energy. Around 90% of T-GNA-scheduled power in the northern region was being curtailed.
• States are following. Maharashtra's regulator has proposed exempting electricity drawn for storage from intra-state transmission, wheeling and cross-subsidy charges when the energy is consumed within the state. These are draft proposals, not final charges.

The trading activity is moving closer to real time too. In IEX's first half of FY27, the real-time market overtook the day-ahead market, at 41% of volumes against 35%. Real-time trading rewards an asset that can respond within the hour, which a battery can.

What can go wrong

• Batteries flatten the spread they live on. Every new battery buys at midday and sells in the evening, lifting the trough and lowering the peak. Researchers have documented this cannibalisation in ERCOT. India plans for a lot of storage: the National Electricity Plan's base case is 47.24 GW / 236.22 GWh of batteries by 2031–32.
• Grid charging rules are unsettled. A May 2026 draft procedure from Rajasthan's transmission utility would stop co-located batteries charging from the grid at all, restricting them to their own solar output. A CTUIL agenda for the western region has proposed barring withdrawal from the inter-state grid. JMK Research suggests allowing charging in defined surplus-solar windows instead.
• The price ceiling caps the upside. At ₹10/kWh, the evening peak cannot rise further. A battery's best days are clipped, while the floor is close to zero.
• Market design is changing. CERC ordered day-ahead market coupling across exchanges in July 2025. In February 2026 the appellate tribunal dismissed IEX's challenge as premature, because coupling needs separate regulations first. Analysts do not expect it before late 2027. Coupling should improve price discovery, but it will change how and where batteries bid.
• Merchant revenue is harder to finance. A lease gives a lender a fixed payment for 12 years. Merchant revenue depends on forecasts of prices, battery wear and policy. That usually means a higher cost of capital, which eats into the extra return.

What comes next

The likely path is neither pure lease nor pure merchant, but a mix. Expect contracts that lease part of a battery's capacity for a bankable base income and leave the rest free to trade. Expect co-located batteries that store curtailed solar and sell it after sunset. And expect discoms that own batteries to start optimising them against exchange prices, not just their own peak.

In all of these, the value comes from the same three decisions, made 96 times a day: when to charge, when to discharge, and which market to use. A battery that charges at a fixed hour every day leaves much of its value unused. One that forecasts tomorrow's prices, weighs day-ahead against real-time and ancillary prices, and accounts for its own degradation earns more from the same hardware.

That is the work Zoltiq is built for. Our backtests on IEX data are on the Strategies page. Next in the series: whether a battery should sell day-ahead or wait for real-time, and a tender tariff against the exchange, lease or trade.