India’s Central Electricity Authority has proposed a structural change to renewable-power development that could make battery storage part of the standard construction cost of new ground-mounted solar and onshore wind projects rather than an optional feature added to selected tenders. Under draft amendments published for public comment, qualifying projects commissioned after July 1, 2027 would need co-located energy storage equal to at least 10% of installed plant capacity with a minimum two-hour duration, while projects entering service from July 1, 2029 through June 2031 would require at least four hours at the same 10% power-capacity threshold.
The draft also proposes that at least 15% of inverters at renewable plants commissioned from July 2027 have grid-forming control, while all power-conversion systems used in battery energy storage systems would require grid-forming capability. The Central Electricity Authority has invited comments until October 4, meaning these provisions remain proposals and should not yet be treated as final regulations.
Why is India moving storage from tender conditions into the technical rulebook?
India has already been pushing developers toward co-located storage. A February 2025 Central Electricity Authority advisory asked Renewable Energy Implementing Agencies and state utilities to include at least two hours of storage equal to 10% of installed solar capacity in future solar tenders. That was an advisory applied through procurement design rather than a general construction requirement.
The new draft potentially goes much further because the requirement is linked to plant commissioning. If finalised in substantially the current form, developers would increasingly need to treat batteries as part of the baseline engineering configuration of new ground-mounted solar and onshore wind assets.
The reason is system physics. A grid can absorb variable renewable power relatively easily when penetration is low because conventional generators provide most frequency control, inertia and dispatch flexibility. As solar and wind become larger portions of total generation, midday oversupply, evening ramps and short-term frequency disturbances become harder to manage.
Storage allows part of renewable output to move across time. Grid-forming inverters address a different but related problem by helping inverter-based resources actively support grid voltage and frequency rather than simply following an already stable grid signal.
What would the 10% two-hour rule mean for a typical 100 MW solar project?
A 100 MW qualifying project commissioned after July 1, 2027 would need storage power capacity of at least 10 MW. With a minimum two-hour duration, that implies at least 20 MWh of energy storage.
That sounds modest compared with a 100 MW generating plant, but the financial effect is not trivial. Developers would need additional battery cells, containers, power-conversion equipment, transformers, controls, fire-safety systems, land and integration work. Financing models would also have to account for degradation and possible battery augmentation over the project’s operating life.
The requirement becomes more significant from July 2029. Keeping power capacity at 10 MW but increasing minimum duration to four hours doubles the minimum energy component to 40 MWh for the same hypothetical 100 MW project.
That illustrates why the duration requirement can matter as much as the percentage. Battery power determines how quickly electricity can be delivered; battery energy determines how long that output can continue.
Why could four-hour storage from 2029 change renewable capex more sharply?
Moving from 20 MWh to 40 MWh requires materially more battery cells and associated equipment, although project costs will depend on battery prices by the time assets are ordered.
The policy timeline creates an unusual investment signal. Developers commissioning projects in 2027 or 2028 may design around a two-hour minimum, while projects crossing the July 2029 threshold could require twice the minimum stored-energy capacity. That creates incentives to rethink procurement schedules, PPA pricing and bid assumptions well before the rule becomes effective.
Battery prices may continue falling, which could absorb part of the extra capex. However, lower equipment costs do not eliminate financing, degradation and operating considerations. Longer-duration systems also hold more capital in an asset whose usable capacity declines over time.
Renewable tariffs consequently cannot be analysed solely through module and turbine prices anymore. The cheapest generation technology may not produce the cheapest dispatchable electricity once storage becomes structurally embedded in the plant.
What are grid-forming inverters and why does the CEA want at least 15%?
Conventional large synchronous generators naturally contribute physical inertia because heavy rotating machinery is electrically coupled to the grid. Solar and modern wind plants connect through power electronics, meaning they do not automatically behave in the same way.
Traditional grid-following inverters generally measure the grid’s existing voltage and frequency and synchronise their output to it. Grid-forming controls can establish and support voltage and frequency reference characteristics, allowing inverter-based resources to contribute more actively to stability as synchronous coal and gas generation becomes a smaller share of instantaneous supply.
The proposed 15% threshold appears to be an intermediate step rather than requiring every renewable inverter to operate in grid-forming mode immediately. All battery PCS would nevertheless require grid-forming capability under the draft.
That creates a new technology requirement across both generation and storage procurement. Equipment makers capable of supplying certified grid-forming systems could gain an advantage, while developers must understand whether their chosen inverters satisfy evolving technical standards rather than simply comparing price and conversion efficiency.
Who could gain and who could pay if India finalises the storage mandate?
Battery manufacturers, system integrators, inverter suppliers and EPC contractors would gain a much larger addressable market because storage would be attached systematically to new solar and wind capacity. Developers with established battery procurement and optimisation capabilities could also gain an execution advantage.
The immediate cost ultimately enters the project capital stack. Developers may attempt to recover it through higher auction tariffs, more favourable financing or improved revenue from stored electricity. Distribution companies and electricity consumers could therefore bear some cost, although the system may save money elsewhere if storage reduces curtailment, balancing requirements and peak-power procurement.
Banks and infrastructure lenders will also need to adjust underwriting models. A battery has a different degradation profile and replacement cycle from a photovoltaic module or wind turbine, meaning projects become more technologically layered even as contracted renewable power remains familiar.
The Central Electricity Authority’s 2025 advisory estimated that India would need 47.24 GW/236.22 GWh of battery energy storage by 2031-32 alongside 26.69 GW/175.18 GWh of pumped storage to integrate the expected renewable fleet.
Could the rule slow renewable bidding before eventually making the grid stronger?
Potentially. A mandatory storage component increases capital requirements and technical complexity, which could cause developers to bid more cautiously while supply chains, financing structures and tariffs adjust.
But that is precisely the trade-off the proposal is attempting to address. A renewable project that is exceptionally cheap but contributes to curtailment or system instability can impose costs elsewhere on the grid. Requiring a modest amount of co-located flexibility internalises part of that system requirement at the project level.
The draft therefore signals a maturation of India’s renewable market. The first phase was dominated by building the cheapest possible solar and wind capacity. The next phase increasingly asks whether those megawatts can coexist reliably when renewable generation becomes one of the dominant physical components of the power system.
If the regulations are finalised, the winning project after July 2027 may no longer be the developer with the cheapest panel or turbine. It may be the one that can integrate generation, batteries, grid-forming controls and finance into the lowest-cost reliable power package.
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