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					</table>The Central Electricity Authority’s (<a href="https://cea.nic.in/?lang=en" target="_blank" rel="noopener">CEA</a>) proposal to <a href="https://www.mercomindia.com/cea-proposes-mandatory-co-located-energy-storage-for-solar-wind-projects" target="_blank" rel="noopener">mandate</a> co-located energy storage systems (ESS) for new ground-mounted solar and onshore wind projects could fundamentally change how renewable energy projects are designed, financed, and operated in India.
Under the draft Central Electricity Authority (Technical Standards for Construction of Electric Plants and Electric Lines) Second Amendment Regulations, 2026, ground-mounted solar and onshore wind projects commissioned after July 1, 2027, would need a co-located ESS equivalent to at least 10% of their installed capacity with a minimum storage duration of two hours.
The requirement becomes more rigorous for projects commissioned after July 1, 2029, and up to June 30, 2031, with the minimum storage duration increasing to four hours at an ESS capacity of 10%.
Policy Impact
The proposed standards will increase the technical requirements for future solar and wind projects by making storage and grid-forming capabilities part of project design. Developers planning projects after the specified commissioning dates will need to incorporate ESS capacity, advanced inverters, and associated control systems into project configurations and financial models.
The most immediate impact would be on project configuration.
A 100 MW solar or onshore wind project commissioned after July 1, 2027, would need at least 10 MW of co-located storage. With the proposed two-hour duration, this translates to at least 20 MWh of storage.
Under the requirement applicable from July 1, 2029, the same project would require at least 10 MW/40 MWh of storage.
This means developers would have to account for batteries, power conversion systems, battery management systems, additional land, electrical infrastructure, and replacement requirements during project development.
Storage procurement could therefore become part of the core engineering, procurement, and construction strategy for solar and wind projects, rather than an optional component.
Higher Capital Costs
Solar and wind developers are likely to incur higher upfront capital costs due to mandatory storage integration. Project tariffs, internal rates of return, debt requirements, and bidding strategies will be impacted.
Projects awarded through renewable energy auctions could face pressure if storage requirements are introduced after bids have already been structured around standalone solar or wind economics.
A Significant Demand Driver for BESS
The proposed regulation will increase demand for battery energy storage.
Unlike storage tenders that procure a predetermined amount of BESS capacity, the CEA proposal would link storage deployment directly to future solar and onshore wind commissioning.
The regulation could provide greater visibility to battery manufacturers, system integrators, energy management system providers, and EPC companies, and encourage expansion of domestic storage manufacturing and integration capabilities.
Grid-Forming Inverters 
The CEA has also proposed that renewable energy projects commissioned after July 1, 2027, should have at least 15% of their inverters equipped with grid-forming control. All PCS used in BESS would need grid-forming capability and comply with the technical requirements specified under CEA&#8217;s grid connectivity regulations.
The draft regulations come a month after the CEA <a href="https://www.mercomindia.com/cea-favors-100-grid-forming-inverters-for-future-battery-storage-projects" target="_blank" rel="noopener">recommended</a> using 100% grid-forming inverters in all future BESS projects to strengthen grid stability as renewable energy capacity continues to grow.
Developers would need to ensure that equipment suppliers can provide compliant grid-forming technology, while inverter and PCS manufacturers would need to adapt their product portfolios to meet the technical specifications.
For grid operators and utilities, the proposed requirements can strengthen system stability as renewable penetration increases. Grid-forming inverters and storage systems can provide additional support for frequency management, voltage control, and integration of inverter-based renewable resources.
Grid-Supportive Renewables 
The proposed requirements indicate a shift in the role expected of renewable energy projects.
Solar and wind projects have traditionally been developed primarily to inject electricity when the underlying renewable resource is available. Combining mandatory storage with grid-forming capability could gradually move projects toward providing greater flexibility and grid-support functionality.
Co-located batteries could shift some renewable generation away from periods of high output, while grid-forming inverters could help power-electronics-based resources contribute more actively to grid stability.
Commissioning Date Critical
The proposed July 1, 2027, applicability date could become an important consideration for projects currently under development.
Projects approaching that commissioning window may have been conceived, financed, or awarded without mandatory storage or grid-forming equipment being incorporated into their original planning and execution.
Developers could therefore have an incentive to commission eligible projects before the requirement becomes applicable, particularly where adding storage would require redesigning electrical systems or arranging additional financing.
The transition to four-hour storage after July 1, 2029, could create a similar commissioning consideration.
The phased implementation provides developers with time to adapt project planning and procurement strategies. However, future CEA revisions to increase ESS capacity or grid-forming requirements could influence long-term project costs and technology choices.
Policy Risk Remains
The CEA has retained flexibility to revise the required percentage of grid-forming capability or ESS capacity over time.
While this gives CEA room to respond to changing grid requirements and technology developments, it could also introduce planning uncertainty for developers.
Changes in mandatory storage capacity after project award could have significant financial consequences unless regulations clearly establish whether revised requirements apply only to new projects.
Stakeholders may therefore seek predictable transition mechanisms and grandfathering provisions whenever future requirements are revised.
What the Industry Will Watch
Among the key issues are likely to be how the mandate applies to projects already awarded but commissioned after July 1, 2027; whether delayed projects become subject to the new requirements; how storage sizing will be measured and maintained over the project life; whether augmentation will be required as batteries degrade; and whether developers will have flexibility in operating and monetizing the storage capacity.
CEA has invited stakeholder comments on the draft regulations by October 4, 2026.
For detailed policy analysis, implementation timelines, market implications, and strategic insights to navigate India’s evolving regulatory landscape, refer to <a href="https://www.mercomindia.com/product/q2-2026-renewable-energy-policy-impact" target="_blank" rel="noopener">Mercom’s Q2 2026 Renewable Energy Policy Impact Report</a>.

CEA’s Proposed Storage Mandate Could Reshape Solar and Wind Project Economics

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					</table>The Gujarat Electricity Regulatory Commission’s (<a href="https://www.gercin.org/" target="_blank" rel="noopener">GERC</a>) decision to <a href="https://www.mercomindia.com/gujarat-cuts-green-energy-open-access-banking-charges-to-%E2%82%B91-kwh" target="_blank" rel="noopener">reduce</a> banking charges to ₹1 (~$0.01)/kWh from ₹1.5 (~$0.015)/kWh after a 2.5-year interval has provided much-needed relief to open access consumers and improved project economics.
The 33.3% reduction in banking charges is expected to provide near-term relief to green energy open access consumers by lowering the cost of managing variability in renewable generation.
Increasing Variable Costs
However, from April 1, 2027, GERC will fundamentally change the methodology for determining banking charges by adopting a more cost-reflective framework. Banking charges will be calculated using 15-minute interval injection and consumption data, power exchange prices, variable generation costs, transmission charges, and other relevant parameters.
Under the new methodology, banking charges may be determined at a floor of ₹0.5 (~$0.005)/kWh and a ceiling of ₹1.5 (~$0.016)/kWh.
The revised framework reflects the actual economic impact of renewable energy banking on distribution companies (DISCOMs). A fixed banking charge cannot account for fluctuations in Indian Energy Exchange prices, thermal generation variable costs, transmission charges, battery energy storage system economics, or changes in the volume of surplus renewable power absorbed by DISCOMs.
The new framework places greater responsibility on DISCOMs to provide data on the variables affecting their banking costs.
The banking facility remains limited to 30% of a consumer’s monthly electricity consumption from DISCOMs. Unused banked energy and surplus energy exceeding the permitted limit will be treated as lapsed. The monthly banking cycle, the 30% limit, and the lapse of unused energy reduce dependence on unrestricted energy adjustment and encourage more accurate demand forecasting.
If the DISCOMs fail to provide the data, the Commission may also determine the banking charge to be nil until satisfactory information is provided.
For a 100 MW open access solar project, the impact can be illustrated using an assumption of 15,000 MWh of monthly generation.
At the transitional banking charge of ₹1(~$0.01)kWh, banking 3,000 MWh of monthly surplus would cost about ₹3 million (~$31,421) per month.
Once the formula-based methodology applies, the proposed floor of ₹0.5 (~$0.005)/kWh would reduce the same banking cost to about ₹1.5 million (~$15,710) per month, while the ceiling of ₹1.5 (~$0.016)/kWh would increase it to about ₹4.5 million (~$47,131) per month.
This creates a potential monthly cost variation of ₹3 million (~$31,421) for the same volume of banked energy.
For a 100 MW project, the new framework therefore makes banking costs more sensitive to market and grid conditions. Developers and open access consumers may increasingly try to reduce surplus banking through better load matching, power exchange sales, hybrid generation, or storage.
While the floor and ceiling provide some protection against extreme variation, projects highly dependent on banking could see a meaningful change in operating costs once the formula-based charge replaces the fixed ₹1 (~$0.01)/kWh rate.
What it Means for Consumers and Developers
Open access and captive consumers will need to factor in greater variability in banking costs when relying heavily on banking to manage renewable generation variability. The monthly settlement cycle and lapse of unused banked energy require closer alignment between generation and consumption, particularly for consumers with seasonal or fluctuating demand.
For renewable energy developers, the revised framework could influence project design and contracting strategies, as the value and cost of banking will increasingly depend on consumer load profiles and prevailing system costs.
Projects serving consumers with predictable demand profiles are likely to remain better positioned. Consumers with variable demand may increasingly consider hybrid renewable systems, energy storage, or alternative procurement structures to reduce their dependence on banking.
Energy storage and hybrid renewable developers could benefit as consumers seek alternatives to conventional banking. Storage can help shift surplus generation to periods of higher demand and improve renewable energy utilization where banking flexibility is constrained.
Overall, the revised framework encourages greater use of demand management, energy storage, and generation-consumption matching in open access projects. While it may reduce reliance on banking as a flexible balancing mechanism, it establishes a more transparent methodology for determining banking charges and improves long-term regulatory certainty.

Gujarat Energy Banking Reform Reduces Near-Term Costs for Open Access

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					</table>As a conditional relief measure for renewable energy developers granted grid connectivity access, the Central Electricity Regulatory Commission (<a href="https://cercind.gov.in/" target="_blank" rel="noopener">CERC</a>) recently introduced a standardized mechanism that allows them additional time to meet land, financial closure, and commercial operation milestones by paying milestone extension charges.
Policy Impact 
While developers get more time to meet the milestones, opting to use the full 12-month extension window comes at a hefty price. For example, a 300 MW renewable energy project utilizing the full extension window for delayed commercial operation could incur ~₹421 million (~$4.40 million) in milestone extension charges (MEC). This is even before accounting for applicable mismatch charges or contractual liabilities under its power purchase agreement (PPA).
However, developers under the new general network access regime will avoid losing grid access if they fail to meet the prescribed deadlines. The extra time does not reset several other timelines governing the project.
This could make the cost of a delay potentially bigger than the MEC itself.
The CERC introduced the mechanism after several entities facing or anticipating connectivity revocation sought additional time to meet GNA milestones. Some projects had already reached advanced stages of implementation.
The Commission decided that projects demonstrating sufficient progress should have an opportunity to retain connectivity by paying compensation. Its reasoning hinges on the scarcity of connectivity. A delayed project can prevent another project from accessing the transmission system.
What it Does Not Change
The significance of the mechanism lies partly in what an extension does not change.
The CERC has expressly retained the original firm start date of connectivity, even when additional time is granted to meet a milestone. The developer consequently remains liable for applicable mismatch charges under the Sharing Regulations.
The additional time also does not modify or dilute obligations under a PPA, including provisions concerning liquidated damages.
A project can therefore receive additional time to achieve commercial operation while still facing liabilities tied to other project timelines.
This requires developers to independently manage their land and financial closure milestones, commercial operation requirements, firm start date of connectivity, and contractual commissioning schedule.
The impact is particularly relevant when delays begin early in development. Land acquisition delays can affect financial closure, procurement, and construction, eventually pushing commissioning beyond its prescribed deadline.
CERC treats these milestones independently. If a developer requires additional time for more than one milestone, MEC must be paid separately for each extension. A single underlying project delay can therefore result in charges at multiple stages.
The Cost Rises Quickly
Financial exposure becomes substantial as project capacity and delay duration increase.
For land compliance, the MEC starts at ₹1,000 (~$10.45) /MW/day for the first 30 days, increases to ₹1,100 (~$11.50) /MW/day for the second 30-day period, and ₹1,200 (~$12.54) /MW/day for the third.
A 300 MW project using the entire three-month land extension would consequently pay ₹29.7 million (~$310,442).
Financial closure can be extended by up to six months. MEC remains ₹1,000 (~$10.45) /MW/day for the first three months before increasing to ₹1,100 (~$11.50)/MW/day in the fourth month, ₹1,200 (~$12.54)/MW/day in the fifth, and ₹1,300 (~$13.59)/MW/day in the sixth.
For a 300 MW project using all six months, the resulting MEC would be ₹59.4 million (~$620,884).
COD delays carry considerably greater exposure.
CERC has set the base charge at ₹3,000 (~$31.36)/MW/day for the first six months. It increases to ₹3,300 (~$34.49) /MW/day in the seventh month, ₹3,600 (~$37.63)/MW/day in the eighth, and ₹3,900 (~$40.77)/MW/day in the ninth. From the tenth through twelfth months, the charge rises to ₹6,000 (~$62.72)/MW/day
A 300 MW project using the full 12-month extension would therefore pay approximately ₹421.2 million (~$4.40 million).
These charges apply to the capacity that has not achieved COD. Partial commissioning can therefore reduce the quantum on which subsequent COD extension charges apply.
Delays Beyond a Developer&#8217;s Control Still Attract MEC
Who bears the cost when the developer did not cause the original delay?
Stakeholders wanted an exemption from, or a reduction in, charges for delays caused by force majeure and other circumstances beyond the developers&#8217; control.
CERC rejected an attribution-based exemption from the standardized mechanism.
It held that MEC is payable irrespective of the reason for the delay. It reasoned that connectivity remains a scarce resource regardless of what caused the project to fall behind schedule.
The framework therefore places the immediate cost of retaining connectivity on the entity holding it. It does not itself distinguish between developer-caused delays and uncontrollable delays.
CERC also clarified that MEC payments cannot be treated as a change-in-law event.
Why Developers May Still Pay
The alternative to paying MEC can carry larger consequences for projects that have already committed capital and made substantial development progress.
The MEC mechanism gives progressing projects the option to retain connectivity while completing the remaining work.
Eligibility requirements are designed to restrict that option to projects demonstrating measurable progress.
A developer seeking additional time for land compliance must already have documents covering at least 20% of the required land. A 20% land threshold also applies to financial closure extensions for the applicable routes.
The threshold rises substantially for COD extensions. Projects under the Land or Land Bank Guarantee route must demonstrate land availability covering at least 75% of the requirement, while projects under the Letter of Award or PPA route must demonstrate at least 50%.
Recovering a Delay Has a Financial Reward
The framework rewards developers for recovering project schedules.
When a project achieves commercial operation on time. 50% of the MEC paid for additional time relating to land and financial closure, corresponding to the capacity commissioned within the permitted period, can be returned without interest.
Developers can also ask the Central Transmission Utility of India (CTUIL) to retain the unused MEC already paid for one milestone and adjust it against the MEC required for another milestone.
Clearing Connectivity Held by Stalled Projects
The mechanism also changes how CTUIL can deal with delayed projects.
Instead of relying on individual proceedings whenever a project seeks relief from an approaching milestone, CTUIL now has standardized eligibility criteria, processing timelines, and charges for determining whether a project can retain connectivity.
Once CTUIL approves additional time and communicates the applicable MEC, the developer must make the prescribed payment within three working days. Failure to do so leaves connectivity subject to the existing GNA Regulations.
The proceeds also feed back into transmission charges. The ERC has directed that 100% of MEC collected for COD extensions and 50% collected for land and financial closure extensions be used to reduce monthly transmission charges.
The remaining 50% collected for land and financial closure extensions will be held separately because it may have to be returned to developers that subsequently meet the prescribed COD conditions. Amounts that do not qualify for refund will ultimately also be used to reduce monthly transmission charges.

CERC’s Connectivity Relief a Double-Edged Sword for Delayed Renewable Projects

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