BESS tariffs explained: capacity charge is not the cost of stored electricity

Start by fixing the units

India’s historical SECI ESS-I order records an auction charge in rupees per MW per month.[S1] That is a payment for capacity, not a complete energy price. The same notation can hide different service specifications:two hours versus four hours, one cycle versus multiple cycles, net versus gross delivery, or different charging responsibilities. Before ranking bids, write the product definition alongside the price. The cheapest number is not necessarily the cheapest equivalent service.

For every offer, establish whether the quoted charge includes augmentation, auxiliary consumption, insurance, land, connection and maintenance. Also record whether the buyer pays for charging energy and whether the contract obliges the seller to make up efficiency losses. Converting an invoice into a common denominator is an analytical exercise; it does not amend the underlying contract. Use the actual contractual definitions when making a purchase decision.

Work through a transparent example

Assume a 1 MW system with two hours of net discharge,330 cycles annually and 95% usable availability. Delivered output is 1,000 kW×2 hours×330×0.95=627,000 kWh. AtRs 200,000/MW/month, the annual capacity payment isRs 2.4 million, or Rs 3.83/kWh discharged. This capacity charge is an illustrative input, not a claim about the latest Indian auction.

With charging electricity atRs 3/kWh and 85% round-trip efficiency, charging addsRs 3.53/kWh. Total fixed-plus-charging cost isRs 7.36/kWh. It excludes network charges, taxes, deviations, trading margins and any cost absent from the assumed capacity payment. If the comparison is against a dispatchable supply contract, normalise these exclusions rather than presenting the simplified result as a final landed tariff.

Under-utilisation can dominate a cheaper bid

A two-hour battery does not necessarily find 330 valuable events merely because the contract permits them. A buyer with a seasonal peak may use the asset heavily for a few months and sparingly thereafter. Conversely, a second daily cycle may be technically permitted but commercially unattractive after charging costs and degradation. Value the residual dispatch opportunities using an hourly simulation and a feasible state-of-charge trajectory.

This is why a battery model should contain a dispatch ledger rather than only an annual revenue multiplier. Track starting state of charge, charging window, delivery obligation, cycling budget and reserve commitments. A model that assigns full availability independently to energy arbitrage, peak capacity and ancillary services can sell the same megawatt several times. CERC’s ancillary-services regulations create a procurement framework; they do not guarantee merchant revenue.[S2]

Charging price is a basis risk

A project connected where renewable output is abundant may still lack the legal right to buy curtailed energy. Another project may have cheap contracted energy but insufficient connection capacity during the charging window. Analyse both access and price. A forecast of low average daytime prices does not establish the achievable charging cost of a particular battery.

Ask which party bears congestion, charging restrictions and deviation costs. Also test what happens if the system operator calls the battery shortly after a scheduled discharge. These provisions can create a meaningful option value or a substantial cost exposure. A single annual average price cannot reveal them.

Compare ownership without creating a false LCOS

For an owned asset, the numerator must include discounted capital expenditure, operating costs, augmentation, charging costs and relevant terminal cash flows. The denominator must use discounted net discharged energy. A capacity-service quotation already embeds the provider’s financing and risk allocation; adding an assumed capital recovery charge to it would double count investment cost.

The November 2026 VGF announcement is relevant to project economics, but a model should recognise only support for which the specific project is eligible and whose timing can be evidenced.[S3] Treating a prospective grant as immediately available cash understates construction funding. Likewise, residual value should not be used as a balancing item to make a weak project appear viable.

The decision rule is straightforward:compare equivalent delivery obligations under common demand, charging, network and reliability assumptions. Then show which risks remain with the buyer in each structure. The resulting commercial range is more useful than an apparently precise LCOS built on incompatible quotations.

A final comparison should show at least three views:the capacity invoice, the expected annual cash cost and the cost of meeting the contracted critical-hour obligation. These views answer different questions. A system reserved for rare emergencies may look expensive per discharged kWh yet still be justified by avoided disruption. An arbitrage project, however, needs enough profitable dispatch to recover fixed cost. Avoid transferring the investment rationale from one use case to another without rebuilding the model. If an offer is sold as both insurance and a trading asset, allocate its capacity and state of charge between those roles explicitly.