The Central Electricity Regulatory Commission (CERC) has released a draft second amendment to the Tariff Regulations, 2024, proposing a formal tariff framework for integrated energy storage systems (ESS) installed alongside coal, lignite, or gas-based generating stations and interstate transmission systems (ISTS).

Stakeholders can submit their comments and suggestions by December 30, 2025.

Supplementary Tariff for Storage

A key feature of the draft is a separate supplementary tariff for the installation of integrated energy storage systems in generating stations or transmission systems. This tariff will consist of supplementary fixed storage and energy charges to be determined separately by the Commission.

Supplementary storage capacity charges will be based on the annual fixed cost of the energy storage system. The annual fixed cost for the integrated system will include the same components that already apply to generating stations, such as depreciation, interest on loan, return on equity, interest on working capital, and operation and maintenance expenses. For integrated ESS installed as additional capitalization, the draft specifies a base return on equity of 14%.

The draft also requires generators and transmission licensees that install an integrated energy storage system to apply for a determination of a supplementary tariff, based on actual capital expenditure certified by an auditor, within 30 days of the system’s commercial operation.

Energy Used for Charging

The proposed amendments set out in detail how the cost of electricity used to charge integrated storage will be passed through.

Supplementary energy charges will consist of the cost of electricity used to charge the storage, adjusted for round-trip efficiency and auxiliary consumption. This may be based on energy charges from the same generating station, energy charges from another station for common beneficiaries, or the cost of electricity procured at the metering point based on the approved tariff or a competitive market rate.

A new regulation on the computation and payment of supplementary energy charges defines the storage energy charge as the cost of energy required to charge. Charging energy can be drawn from surplus generation at the associated station, from other generating stations, or from the open market, subject to priority use of storage to maintain technical minimum and continuous supply to beneficiaries.

The draft provides a monthly formula tfo calculate supplementary energy charges from storage.

• Monthly supplementary energy charge:
  SEC(n) = SECR_ess × E_sch,ess(n)

Where:

• SEC(n) = Supplementary Energy Charges for month n (₹)
• SECR_ess = Supplementary energy charge rate of the integrated ESS (₹/kWh)
• E_sch,ess(n) = Scheduled ex-bus discharge energy from the ESS in month n (kWh)

The supplementary energy charge rate, SECR_ess, depends on the charging source. The regulation specifies the following cases:

• Charging from the associated generating station (tariff determined by CERC):
  SECR_ess = ECR / ( max(RTE_ess_norm, RTE_ess_actual) × (1 − AEC_ess) )
• Charging from another generating station with the same beneficiaries and tariff determined by CERC:
  SECR_ess = ECR / ( max(RTE_ess_norm, RTE_ess_actual) × (1 − AEC_ess) )
• Charging from another generating station whose tariff is approved by CERC (including any capacity charge component for that supply):
  SECR_ess = (ECR + CC) / ( max(RTE_ess_norm, RTE_ess_actual) × (1 − AEC_ess) )
• Charging from the open market or any other source (using the discovered tariff at the metering point):
  SECR_ess = Discovered Tariff / ( max(RTE_ess_norm, RTE_ess_actual) × (1 − AEC_ess) )
• Charging from grid drawal during high-frequency operation (using the DSM rate):
  SECR_ess = DSM Rate / ( max(RTE_ess_norm, RTE_ess_actual) × (1 − AEC_ess) )

Definitions (common to all cases):

• ECR = energy charge rate of the relevant generating station (₹/kWh)
• CC = capacity-related component of the energy for charging, where applicable (₹/kWh)
• RTE_ess_norm = normative round-trip efficiency of the integrated ESS
• RTE_ess_actual = actual round-trip efficiency achieved over the period
• AEC_ess = auxiliary energy consumption of the ESS (as a fraction of input energy)
• Discovered tariff = tariff discovered through procurement from the market (₹/kWh)
• DSM Rate = deviation settlement mechanism rate applicable to the drawal (₹/kWh)

Supplementary energy charges for a month will be calculated as SECR_ess multiplied by the scheduled ex-bus discharge energy from storage for that month. If beneficiaries arrange for charging energy at their own cost, the draft provides that the storage energy charge rate will be zero.

In addition to supplementary capacity and energy charges, an incentive of ₹0.25 (~$0.00279)/kWh is proposed for discharge in excess of the energy corresponding to the normative round-trip efficiency, measured cumulatively.

For transmission-linked storage, the draft clarifies that the transmission licensee will retain the incentive revenue annually.

Operational norms for integrated storage

The draft inserts explicit operating norms for integrated storage in the main chapter on performance standards.

For storage installed at generating stations, the normative availability factor is set at 90%. Round-trip efficiency is specified at 85% for storage installed at either generating stations or transmission systems, and auxiliary energy consumption is set at 5% of input energy for both cases.

The plant availability factor for storage is defined as the average daily declared capacity during peak hours, expressed as a percentage of installed capacity, after deducting auxiliary consumption.

The draft also introduces a comprehensive new set of definitions for integrated ESS and key parameters, including auxiliary energy consumption, state of charge, c-rate, battery cycle, declared capacity, maximum continuous rating, and the commercial operation date of storage.

The proposed amendments also provide that the first right of discharge from integrated storage will lie with the beneficiary, except when required for safe and secure operation of the power system. Procedures for charging, scheduling, dispatch, and energy accounting for storage linked to transmission or generation assets will be prepared by Regional Power Committees in consultation with Regional Load Dispatch Centres and aligned with the Grid Code.

Useful life for battery energy storage systems is fixed at 12 years in the schedule of asset lives under the principal regulations.

CAPEX, Depreciation, and O&M

For additional capital expenditure on storage in existing projects, the draft requires generating companies to share proposals with beneficiaries and seek approval before implementation. These proposals must include technology details, scope of work, phasing of expenditure, schedule of completion, estimated completion cost, including interest during construction and foreign exchange component, along with indicative tariff impact and cost-benefit analysis.

A similar process is set out for transmission licensees that plan to add integrated storage. They must share proposals with the Regional Power Committee, the Central Transmission Utility, the Regional Load Despatch Centre, and long-term transmission customers or designated ISTS customers, and then file a petition for approval.

The draft extends initial spares norms to integrated ESS, aligned with the applicable norms for coal/lignite generating stations or substations, as relevant.

Depreciation for integrated storage installed with a generating station or transmission system will either follow the existing depreciation rules where storage is within the original scope or be computed separately using specified rates when added to an asset that has not yet completed its useful life.

Any unrecovered depreciation after 12 years of storage operation is to be spread over the higher of the remaining life of the storage, the generating station, or the transmission system.

Working capital norms are extended to storage. For integrated storage in coal or lignite-based stations or transmission systems, receivables equivalent to 45 days of supplementary tariff, maintenance spares at 20% of O&M expenses, and one month of O&M expenses are to be considered in working capital.

Tariff filing forms for both thermal generating stations and transmission systems have been revised to include detailed rows for storage-related capital costs, depreciation, loan interest, return on equity, O&M expenses, and supplementary charges.

For transmission, the forms state that O&M expenses for storage are to be calculated at 2% of the original project cost related to the storage asset, with actual expenses allowed on a prudence-checked basis at the time of true-up.

The draft further specifies that this 2% O&M is computed on admitted ESS capex excluding IDC/IEDC, escalated at 5.25% annually for the first two years, and thereafter allowed on a prudence-check/true-up basis.

Technical data requirements

The draft significantly expands the technical information required for projects with integrated storage.

New form entries require details such as type and technology of storage, number of battery racks or modules, number of battery cells, DC voltage of cells, operation mode at the grid interface, rated capacity in megawatts, maximum continuous rating, energy capacity in megawatt-hours, AC and DC output voltage, power factor, round trip efficiency, response time, state of charge, cycle life, charge and discharge C-rates, black start capability and utilisation factor.

Normative parameter forms are similarly expanded to include round-trip efficiency, number of cycles per day, total annual cycles, storage availability, auxiliary energy consumption, depth of discharge, and useful life in years.

Sharing of transmission storage costs and revenues

For storage that forms part of the transmission system, charges determined under the regulations will be shared by beneficiaries, long-term customers, or designated ISTS customers in line with the existing sharing regulations. Receipts that transmission licensees obtain from providing storage services to generating companies or other licensees must be used to reduce yearly transmission charges for the system.

A new provision also specifies that any net gains from the use of integrated storage (after adjusting supplementary charges) will be shared equally between generators and beneficiaries, while gains from transmission-linked storage will be used to reduce transmission charges.

India’s cumulative installed energy storage capacity reached 490 MWh by the end of June 2025, according to Mercom India Research’s India’s Energy Storage Landscape 1H 2025 Report.

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