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					</table>The Green Energy Corridor Phase III (GEC III) program has the potential to create new opportunities for transmission equipment suppliers, EPC firms, battery storage providers, and grid technology companies as India develops infrastructure to accommodate an extra 135 GW of renewable energy.
The Union Cabinet <a href="https://www.mercomindia.com/cabinet-clears-green-energy-corridor-phase-iii-to-evacuate-135-gw-renewables" target="_blank" rel="noopener">approved</a> the ₹1.86 trillion (~$19.43 billion) program to strengthen intrastate transmission infrastructure and deploy 50 GWh of battery energy storage systems (BESS) by FY 2032-33.
While the scale of the program creates a substantial long-term project pipeline, Mercom Research expects its commercial impact to depend largely on the pace at which states tender and execute individual projects.
Of the total program outlay, ₹1.36 trillion (~$14.21 billion) has been allocated for intrastate transmission systems, while ₹500 billion (~$5.21 billion) has been earmarked for 50 GWh of BESS.
The program will receive central financial support of ₹540.82 billion (~$5.64 billion), partly offsetting intrastate transmission costs and helping limit the impact on electricity costs for consumers.
For transmission equipment manufacturers and EPC companies, the program is expected to generate demand for substations, transmission equipment, network strengthening, and grid upgrades. State transmission utilities will act as the overall implementing agencies.
All greenfield transmission projects will be awarded through tariff-based competitive bidding (TBCB), with transmission service providers developing projects under the build, own, operate, and maintain model. Brownfield upgrades and network strengthening will follow a cost-plus framework.
The two procurement structures present different commercial dynamics. Competitive bidding could increase cost discipline in greenfield transmission development while putting pressure on developer margins. Brownfield works provide an additional project pipeline, although execution will remain subject to land acquisition, approvals, procurement, and coordination.
Srivatsan Iyer, Global CEO at <a href="https://www.herofutureenergies.com/" target="_blank" rel="noopener">Hero Future Energies</a>, said the intrastate focus addresses an important constraint as India&#8217;s renewable capacity expands. &#8220;As renewable capacity scales up, evacuation infrastructure has to keep pace, and much of that constraint sits at the state level. Strengthening intra-state transmission, and building it ahead of generation, is essential to avoid stranded capacity and curtailment.&#8221;
Transmission bottlenecks have emerged as an impediment to renewable project commissioning. At the Mercom India Renewables Summit 2025, industry executives <a href="https://www.mercomindia.com/lack-of-transmission-infrastructure-impacting-power-project-commissioning" target="_blank" rel="noopener">highlighted</a> inadequate transmission infrastructure as one of the major constraints to faster commissioning of renewable energy projects.
Transmission projects have also faced delays arising from right-of-way issues, landholder opposition, compensation disputes, litigation, and forest, wildlife, and tree-cutting approvals.
GEC III&#8217;s ability to ease these constraints will depend on whether transmission infrastructure can be completed in step with renewable energy projects. Timely fund disbursement, equipment availability, financing, grid approvals, and state-level execution will therefore be critical.
50 GWh Creates Significant Storage Opportunity
The storage component creates a substantial prospective market for battery suppliers and companies providing power conversion systems, energy management systems, battery management systems, installation, and maintenance services.
BESS can be installed at renewable energy projects or other locations considered important for grid flexibility. The capacity is intended to address intermittency, congestion, peak-hour curtailment, and electricity requirements during non-solar hours.
Iyer said the planned storage capacity could help absorb surplus solar generation, reduce congestion, and shift electricity into periods when solar generation is unavailable.
&#8220;This is how renewable energy becomes firm and dispatchable, which is what the grid increasingly values,&#8221; he said.
The Central Electricity Authority has projected a requirement of more than 236 GWh of BESS by 2031-32, making the 50 GWh planned under GEC III part of a much larger storage requirement.
Battery storage is also increasingly being considered as a transmission asset in India. The National Committee on Transmission has discussed deploying BESS at strategic grid locations to improve transmission utilization, manage renewable energy curtailment and congestion, and address supply-demand imbalances.
How effectively the 50 GWh addresses these challenges will depend not only on the capacity deployed but also on where and how the systems are used. Siting, operating rules, grid integration, technology selection, procurement structures, and ownership arrangements will influence their effectiveness.
Vineet Mittal, Chairman at <a href="https://www.avaada.com/" target="_blank" rel="noopener">Avaada Group</a>, said combining transmission and battery storage under a single program recognizes the need for generation, delivery, and availability to develop together.
He noted that growing storage deployment could also create additional demand for daytime renewable generation. Batteries could initially absorb surplus electricity from existing projects, while increasing storage utilization and electricity demand could eventually require additional renewable capacity for charging.
However, the extent to which storage drives additional solar capacity will depend on charging sources, operating cycles, battery efficiency, local demand, and the availability of surplus renewable power. &#8220;We should plan these investments as an integrated system,&#8221; Mittal said.
Storage location will also determine its function. BESS installed alongside renewable generation can store surplus electricity and shift supply to other periods. Storage at strategically selected network locations can help relieve congestion and improve the utilization of existing transmission infrastructure.
Mittal said the intrastate component could help states make greater use of their renewable resources and improve electricity delivery to industrial clusters, agricultural areas, and growing towns.
The infrastructure required will vary by location. Areas with suitable renewable resources and demand may benefit from generation and storage located closer to consumption, while others may require stronger transmission links to larger renewable energy projects.
The program could also support demand across the domestic clean energy manufacturing and services value chain, including batteries, transformers, cables, inverters, control systems, solar modules, and cells.
Mittal said the opportunity for Indian companies extends to designing, manufacturing, installing, and maintaining these systems at scale, requiring investment in engineering capabilities, skilled workers, quality, and technology development.
Execution remains the central variable for both the transmission and storage components. &#8220;Transmission, storage and generation need to be planned together, with predictable timelines and consistent tender structures,&#8221; Iyer said. &#8220;Where that happens, capital flows more efficiently, and projects are delivered on time.&#8221;
For the storage industry, commercial opportunities will ultimately depend on the specifications and procurement structures adopted for individual projects, battery prices, technology requirements, tender schedules, and clarity over ownership, operation, and maintenance responsibilities.
For detailed policy analysis, implementation timelines, market implications, and strategic insights, refer to Mercom’s <a href="https://www.mercomindia.com/product/q2-2026-renewable-energy-policy-impact" target="_blank" rel="noopener">Q2 2026 Renewable Energy Policy Impact Report</a>.

Success of Green Energy Corridor III Hinges on Timely Project Execution

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					</table>Battery energy storage system (BESS) developers with existing connectivity can increase the storage duration of their projects without seeking additional grid connectivity capacity under a new procedure issued by the Central Transmission Utility of India (<a href="https://ctuil.in/" target="_blank" rel="noopener">CTUIL</a>).
By separating increases in energy storage capacity, measured in MWh, from increases in charging and discharging capacity, measured in MW, the framework gives developers greater flexibility to expand existing projects as demand for longer-duration storage increases.
Policy Impact
Under CTUIL&#8217;s <a href="https://www.mercomindia.com/ctuil-issues-guidelines-for-enhancing-storage-capacity-of-bess-projects" target="_blank" rel="noopener">advisory</a>, a developer seeking only an increase in MWh capacity must apply under Regulation 5.2 of the General Network Access Regulations. The application must specify the additional MW capacity as &#8220;Nil&#8221; and separately state the proposed MWh enhancement.
The new procedure could improve project economics by allowing developers to add energy capacity while avoiding additional MW connectivity approvals, associated studies, and potential transmission augmentation charges.
This allows an existing BESS to increase its storage duration while retaining the same approved charging and discharging capacity.
For example, a 50 MW/100 MWh system has two hours of storage at its rated power. Increasing the energy capacity to 200 MWh while retaining the 50 MW rating would increase the nominal duration to four hours. This example illustrates how an MWh-only enhancement could work and is not provided by CTUIL in the advisory.
The change could become relevant as storage requirements shift toward longer-duration applications. Additional storage duration is critical for higher renewable energy integration, peak demand management, and grid balancing. Revenue models involving multi-hour discharge, including evening peak shifting, ancillary services, and renewable firming, could also influence developers&#8217; decisions to increase MWh capacity.
Developers could respond to such requirements by expanding storage capacity at existing sites rather than developing separate greenfield projects. The new framework could encourage projects with higher MWh capacity and accelerate augmentation of earlier BESS projects initially configured for one to two hours of storage.
The procedure could also reduce transmission-related constraints associated with expanding storage projects.
Increasing MWh capacity does not increase the project&#8217;s approved MW capacity at the grid connection point. This lets developers expand the energy available for charging and discharging while continuing to use their existing connectivity infrastructure.
According to Mercom’s assessment, this could be particularly relevant in renewable energy-rich corridors where interstate transmission system margins are constrained, and connectivity queues are long. Increasing MWh at an already connected BESS site can add storage capability without adding projects to connectivity queues or requiring new substations.
The framework could consequently create a separate brownfield augmentation opportunity for the storage supply chain.
Existing projects originally developed with lower MWh-to-MW ratios could require additional batteries, enclosures, thermal management systems, and associated balance-of-system components as developers increase storage duration. The Research assessment also identified the possibility of technology upgrades, including higher energy-density cells and improved thermal systems, within the existing MW envelope.
Longer-duration BESS capacity at existing connectivity points could also give grid operators additional flexibility to support renewable energy integration and potentially reduce curtailment.
Higher energy throughput and longer discharge durations could, however, require corresponding changes in operational coordination. CTUIL and State Load Despatch Centres may need to update dispatch models, visibility, and telemetry requirements while continuing performance monitoring and compliance with applicable technical requirements.
Conn-BG3 Clarification
However, one issue affecting the cost of augmentation remains unresolved. Under the existing GNA Regulations, Conn-BG1 and Conn-BG3 provisions apply to applications under Regulation 5.2. Conn-BG3 is defined at ₹200,000 (~$2,084)/MW, creating uncertainty over its application when a developer increases only the MWh capacity and does not add any MW capacity.
CTUIL will seek clarification from the Central Electricity Regulatory Commission on whether Conn-BG3 applies in such cases. Until the Commission provides its clarification, CTUIL will not seek Conn-BG3 for MWh-only enhancements.
Developers could still become liable for Conn-BG3 depending on CERC&#8217;s eventual direction. Failure to submit the applicable guarantee after such clarification could result in CTUIL revoking approval for the additional MWh capacity and encashing Conn-BG1.
CTUIL has also provided for faster processing of these applications. Once the applicable regulatory requirements are fulfilled, it will issue the intimation incorporating the enhanced MWh capacity without waiting for discussion at the relevant Consultation Meeting for Evolving Transmission Schemes. The case will subsequently be placed before the meeting for information and noting.
Developers must continue to comply with land, financial closure, Scheduled Commercial Operation Date, and other applicable regulatory requirements corresponding to the enhanced MWh capacity. CTUIL also clarified that it will process MWh enhancement requests submitted before the advisory under the new procedure.
For detailed policy analysis, implementation timelines, market implications, and strategic insights, refer to Mercom’s <a href="https://www.mercomindia.com/product/q2-2026-renewable-energy-policy-impact" target="_blank" rel="noopener">Q2 2026 Renewable Energy Policy Impact Report</a>.

Battery Storage Projects May Gain from Rule Change on Charging, Discharging

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					</table>The Ministry of New and Renewable Energy&#8217;s (<a href="https://mnre.gov.in/en/" target="_blank" rel="noopener">MNRE</a>) decision to extend the deadline for central financial assistance (CFA) claims for legacy rooftop solar projects could help consumers, vendors, and distribution companies (DISCOMs) settle pending applications.
MNRE recently <a href="https://www.mercomindia.com/mnre-extends-subsidy-claim-deadline-for-legacy-rooftop-solar-applications" target="_blank" rel="noopener">extended</a> the deadline for submitting CFA claims for applications at the redeemed, inspected, or installed stage under the erstwhile Rooftop Solar Phase II Program to November 30, 2026, from December 31, 2025.
The extension provides additional time to settle subsidies for projects that have already progressed through key implementation stages, reducing the risk of eligible consumers losing access to CFA. It also gives vendors and DISCOMs more time to complete documentation and process eligible legacy applications.
Eligible applications will continue to receive CFA under the Rooftop Solar Phase II guidelines rather than the subsidy structure under the PM Surya Ghar: Muft Bijli Yojana.
The transition to PM Surya Ghar did not automatically move ongoing Phase II projects to the new subsidy structure.
Policy impact 
The extension provides relief to consumers whose rooftop solar projects were initiated under the earlier program and have reached an eligible stage but whose CFA claims are yet to be settled.
The previous amendment issued in July 2025 specified that applications submitted before the launch of PM Surya Ghar but where rooftop systems remained uninstalled as of April 1, 2025, would be ineligible for CFA and deleted from the database. Consumers whose applications were deleted could subsequently reapply under PM Surya Ghar.
The latest amendment extends the CFA claim deadline to November 30, 2026, and no longer includes the earlier language requiring deletion of applications uninstalled as of April 1, 2025.
However, the removal of this provision should not be interpreted as automatically restoring CFA eligibility to applications that had previously become ineligible or were deleted. MNRE has not expressly clarified that these applications have regained eligibility.
The revised provision continues to specifically identify applications at the redeemed, inspected, or installed stage as admissible for CFA.
Immediate relief should therefore focus on eligible Phase II projects that have progressed sufficiently but need more time to complete their subsidy claims.
Impact on Vendors and DISCOMs
For rooftop solar vendors, the extension provides a longer window to complete pending documentation and facilitate CFA claims for eligible legacy projects.
This is particularly relevant where installations or inspections are complete, but subsidy-related documentation or processing remains pending. Avoiding the expiry of eligible claims can also provide greater certainty in closing older projects.
DISCOMs, meanwhile, will have to continue processing eligible Phase II applications alongside those under PM Surya Ghar. The additional time could ease the immediate administrative burden and support orderly closure of the Phase II pipeline.
Under the PM Surya Ghar framework, Phase II liabilities remain distinct. MNRE processes claims for projects implemented under Phase II&#8217;s tender mode according to the earlier program&#8217;s guidelines, while the new program&#8217;s funding framework also provides for meeting ongoing Phase II liabilities.
Limited Impact on New Demand
The amendment is unlikely to have a significant direct impact on new residential rooftop solar demand because it does not increase CFA rates or expand subsidy eligibility under PM Surya Ghar.
Instead, its immediate impact will primarily be to settle the remaining pipeline of eligible Phase II applications and ensure that consumers with qualifying legacy projects have additional time to receive the CFA under the earlier program.
PM Surya Ghar remains the principal program for new residential rooftop solar installations. The program targets rooftop solar installations at 10 million households and 30 GW of rooftop solar capacity by FY 2026-27.
The extension therefore addresses unfinished business under the previous rooftop solar program rather than creating a new demand stimulus. For consumers, it preserves additional time to claim eligible subsidies; for vendors and DISCOMs, it provides a longer window to close pending Phase II projects and associated claims.
For detailed policy analysis, implementation timelines, market implications, and strategic insights, 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>.

Deadline Relief Protects Subsidies for Legacy Rooftop Solar Projects

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					</table>Transmission infrastructure development has struggled to keep pace with India&#8217;s rapid addition of renewable energy generation capacity. Transmission projects typically have longer development timelines than generation projects, while right-of-way (RoW) disputes, landowner objections, compensation claims, and challenges to transmission line alignments can further delay execution.
Recently, the Madhya Pradesh High Court <a href="https://www.mercomindia.com/madhya-pradesh-high-court-rules-landowner-consent-not-needed-for-power-lines" target="_blank" rel="noopener">reaffirmed</a> that a transmission licensee vested with powers under Section 164 of the Electricity Act, 2003, does not require prior consent from private landowners to lay transmission lines across their property.
The court upheld Madhya Pradesh Power Transmission Company’s authority to construct the second circuit of the 132 kV DCSS Mandideep-Nahar transmission line and clarified the scope of transmission licensee powers in relation to RoW issues.
What the Court Said
The High Court said transmission line routing is an engineering and safety decision and cannot be interfered with unless it is arbitrary or unlawful. Licensees operating under Section 164 of the Electricity Act are exempt from the prior consent requirement applicable under the Works of Licensees Rules.
The judgment clarified that transmission infrastructure retains its public utility character even when it primarily serves a specific industrial consumer. Alternative routes proposed by landowners can be rejected where they create safety risks or are technically less feasible.
Policy Impact
The judgment reiterates the legal position vis-à-vis the transmission licensee’s powers and provides greater clarity on RoW issues. The ruling could help reduce delays arising from landowner objections and disputes over transmission line alignments.
Both transmission utilities and renewable energy developers are likely to benefit from greater certainty in project execution. Faster resolution of RoW-related issues can help reduce delays in commissioning transmission assets and connecting renewable generation projects.
Transmission infrastructure availability has been a weak link in India’s energy transition story. With the court reiterating its legal position, solar, wind, and hybrid projects can hope to move up faster in the connectivity queue if transmission projects are commissioned on time.  Improved clarity around land access and route approvals can support faster development of renewable energy corridors and grid expansion projects.
The headroom for landowners to stall technically approved transmission routes may be squeezed if their objection is based solely on a preference for alternative alignments.
Disputes surrounding compensating landowners will, however, remain relevant during transmission project execution. In recent years, the Union government and a few state governments have addressed the issue by increasing monetary compensation for landowners impacted by transmission lines passing through their lands.
While the High Court ruling could give transmission developers and utilities more confidence in planning and executing projects, effective stakeholder engagement will remain critical to avoiding prolonged disputes and ensuring smoother implementation.
The judgment strengthens the legal framework supporting transmission infrastructure development by clarifying licensees&#8217; powers and reducing uncertainty around RoW execution. This could support faster grid expansion and improve the reliability of renewable energy evacuation infrastructure.
The ruling reinforces the statutory framework intended to allow essential transmission infrastructure to proceed while preserving landowners&#8217; right to compensation.
For detailed policy analysis, implementation timelines, market implications, and strategic insights to navigate India’s evolving regulatory landscape, refer to Mercom’s <a href="https://www.mercomindia.com/product/q2-2026-renewable-energy-policy-impact" target="_blank" rel="noopener">Q2 2026 Renewable Energy Policy Impact Report</a>.

High Court Ruling Clears Right-of-Way Hurdle, Helps Speed Up Transmission Projects

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					</table>The Central Transmission Utility of India’s (<a href="https://ctuil.in/" target="_blank" rel="noopener">CTUIL</a>) sharp reduction in benchmark project costs could ease financial closure compliance for solar, wind, and battery storage project developers seeking connectivity to the interstate transmission system (ISTS).
CTUIL has <a href="https://www.mercomindia.com/ctuil-cuts-benchmark-project-costs-for-solar-wind-and-bess-projects" target="_blank" rel="noopener">reduced</a> the benchmark project cost for solar by 30% to ₹35 million (~$370,645)/MW from ₹5 million (~$529,493)/MW and for wind by 25% to ₹60 million (~$635,391)/MW from ₹80 million (~$847,188)/MW.
The benchmark cost for battery storage projects has been reduced by 60% to ₹8 million (~$84,719)/MWh from ₹20 million (~$211,797)/MWh, the largest reduction among the technologies. Renewable energy park costs remain unchanged at ₹5 million (~$52,950)/MW.
The benchmark costs are used to assess project costs for financial closure and other eligibility requirements under the Central Electricity Regulatory Commission&#8217;s Connectivity and General Network Access (GNA) Regulations, 2022.
Policy impact 
The revised benchmarks substantially lower the project-cost assumptions used to assess financial closure compliance. For developers, particularly those with large projects, the change could reduce the amount they must demonstrate against the benchmark to meet the applicable financial closure criteria.
For example, the benchmark project cost for a 500 MW solar project declines by ₹7.5 billion (~$79.42 million), from ₹25 billion (~$264.75 million) to ₹17.5 billion (~$185.32 million). For a 500 MW wind project, it falls by ₹10 billion (~$105.89 million), to ₹30 billion (~$317.70 million) from ₹40 billion (~$423.59 million).
The impact is significantly larger for storage. The benchmark project cost for a 1,000 MWh battery storage project falls by ₹12 billion (~$127.08 million), from ₹20 billion (~$211.80 million) to ₹8 billion (~$84.72 million).
The sharp reduction in the battery storage project benchmark cost reflects the rapid decline in storage system costs and changing project economics. Updating the benchmark is important because an outdated, substantially higher cost assumption could require developers to demonstrate financial commitments that no longer reflect prevailing project costs.
However, the revision should not be interpreted as a reduction in the actual capital required to build a project. The benchmark is an assessment parameter for regulatory compliance. Equipment prices, financing costs, project configuration, construction expenses, land, evacuation infrastructure, and other development costs will continue to determine actual capital requirements and project viability.
Pending Projects Could Benefit
The most immediate impact could be on projects whose financial closure compliance remains under consideration by CTUIL.
CTUIL said it may consider the revised benchmarks where a decision on acceptance of financial closure compliance is still pending. This could allow such projects to be evaluated against substantially lower project-cost assumptions than those applicable earlier.
The provision is particularly relevant for projects that may have faced difficulty demonstrating compliance against the earlier benchmarks even though their actual project costs reflected lower prevailing market prices.
The revision, however, does not reopen cases already concluded. CTUIL will not reconsider projects where financial closure compliance has already been accepted or where connectivity has been revoked because financial closure requirements were not met.
This distinction limits the revision&#8217;s retrospective impact while providing relief to projects still in the assessment process.
Land Requirements Become More Technology-Specific
CTUIL has retained the benchmark land requirement at 3 acres/MW for solar projects and 0.25 acres/MW for wind projects.
For wind projects, however, meeting the aggregate acreage requirement alone is not sufficient. CTUIL has clarified that the identified land must be suitable for installing the proposed wind turbine generators, taking into account turbine placement and the required distance between wind turbine generators.
This makes the land assessment more closely linked to the actual project layout. Wind developers must therefore demonstrate not only that sufficient land has been secured, but also that the identified parcels can accommodate the proposed turbine configuration.
CTUIL has also introduced a specific land benchmark for battery storage projects at 1.2 acres per 100 MWh.
At this benchmark, a 500 MWh battery storage project would require 6 acres, while a 1,000 MWh project would require 12 acres.
A dedicated benchmark for battery storage projects gives developers greater certainty about the land requirement considered during connectivity assessment. This becomes increasingly relevant as standalone and co-located storage projects scale and seek ISTS connectivity.
The new benchmark also recognizes that storage has a fundamentally different land-use profile from generation technologies, allowing energy storage applications to be assessed against technology-specific criteria rather than broader renewable energy assumptions.
Lower Benchmarks Better Reflect Changing Project Economics
The scale of the revisions indicates how rapidly project economics, particularly for battery storage, have changed. The 60% reduction in the battery storage benchmark is twice the percentage reduction for solar and substantially higher than the revision for wind.
For developers, the significance is not that projects become cheaper because CTUIL has revised the benchmark, but that the regulatory assessment is being brought closer to prevailing cost structures. This reduces the risk that developers must demonstrate financial readiness against assumptions that materially exceed current project costs.
The impact can become substantial at utility scale. Because the benchmarks apply on a per-MW or per-MWh basis, even relatively modest reductions translate into large differences in assessed project cost as capacity increases. This could give developers greater flexibility in structuring financial closure for large portfolios and projects.
At the same time, lower benchmark costs do not dilute the broader project-readiness requirements under the GNA framework. Developers must continue to meet the applicable financial closure, land, and other eligibility conditions for connectivity.
Taken together, the revised cost and land benchmarks bring CTUIL&#8217;s assessment framework closer to changing renewable energy and storage market conditions. For projects with pending financial closure assessments, particularly large battery storage projects, the changes could materially reduce the benchmark against which financial readiness is evaluated while retaining the underlying discipline required for ISTS connectivity.
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>.

Lower CTUIL Cost Benchmarks Ease Financial Closure for Renewable Projects

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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.

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