Sterling and Wilson Secures Letter of Intent for BoS of 300 MW Solar Project

MERC Approves DISCOM’s Power Sale Agreement for 300 MW Hybrid Power

Tamil Nadu Electricity Regulator Allows Land Lease for BESS Projects at ₹1

JBM ECOLIFE Secures $100 Million Investment from IFC to Deploy 1,455 e-Buses

Andhra Pradesh Releases Battery Energy Storage Regulations

Oil India Partners with Rajasthan DISCOM to Develop Renewable Energy Projects

Daily News Wrap-Up: PM Surya Ghar to Hit 5 Million Installations

New GST Rates on Renewable Energy Goods Likely to Reduce Costs and Tariffs

Rooftop Solar Adoption Faces Policy Hurdles Despite Growing Awareness

Europe’s Solar Industry Wants CBAM Extended to Module and Tracker Imports

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					</table>JBM ECOLIFE Mobility, a subsidiary of electric bus manufacturer <a href="https://jbmbuses.com/" target="_blank" rel="noopener">JBM Auto</a>, has secured a $100 million long-term capital investment from International Financial Corporation (<a href="https://www.ifc.org/en/home" target="_blank" rel="noopener">IFC</a>) to deploy 1,455 air-conditioned electric buses (e-bus) across cities in Maharashtra, Assam, and Gujarat.
In a bourse filing, the company said this is IFC’s first capital investment in the e-bus sector in Asia and its largest globally.
JBM ECOLIFE operates e-buses in several cities, including Mumbai, Delhi, Ahmedabad, Surat, Bhubaneswar, Hyderabad, and Cuttack, and plans to expand further, targeting operations of more than 6,500 buses within the next two years.
The company has deployed over 2,500 e-buses across 10 states and 15 airports and is executing an order book of 11,000 units. Its Delhi-NCR manufacturing facility has an annual capacity of 20,000 e-buses. Since 2018, JBM’s electric fleet has covered 200 million kilometers, saving over 600 million liters of diesel.
Highlighting the significance of buses in India’s mobility landscape, accounting for 70–75% of public transport trips, JBM noted the electrification potential in a country with nearly 2 million buses in operation.
Last year, JBM <a href="https://www.mercomindia.com/adb-aiib-invest-100-million-in-electric-bus-company-jbm-ecolife/" target="_blank" rel="noopener">secured</a> $100 million in funding from the Asian Development Bank and the Asian Infrastructure Investment Bank to support e-bus supply and operations under the gross cost contract model across multiple states. The funding was obtained following thorough Environmental, Social, and Governance audits conducted by approved consultants.
In September last year, the Union Cabinet <a href="https://cms.mercomindia.com/cabinet-pm-edrive-program/" target="_blank" rel="noopener">approved</a> the ‘PM Electric Drive Revolution in Innovative Vehicle Enhancement (PM E-DRIVE) Program,’ and the ‘PM-eBus Sewa-Payment Security Mechanism (PSM) Program.’
The PM E-DRIVE Program, with a total outlay of ₹109 billion (~$1.29 billion), focuses on providing demand incentives, deploying electric vehicles (EV), and developing charging infrastructure to support wider EV adoption.
The PSM Program, with an outlay of ₹34.35 billion (~$409 million), will support the procurement and operation of over 38,000 electric buses from FY 2024-25 to FY 2028-29.

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					</table>The <a href="https://bombayhighcourt.nic.in/index.php" target="_blank" rel="noopener">Bombay High Court</a> has stayed the Maharashtra State Electricity Distribution Company’s (<a href="https://www.mahadiscom.in/en/home/" target="_blank" rel="noopener">MSEDCL</a>) restriction on the use of banked renewable energy to solar hours.
It ruled that the older multi-year tariff (MYT) framework, allowing renewable energy use anytime except during peak hours, would hold.
The court had earlier issued an interim judgment, staying the Maharashtra Electricity Regulatory Commission’s (MERC) review order restricting banked renewable energy usage to the same time-of-day slot and solar hours.
The High Court rejected MSEDCL’s argument that the old rules could not automatically revive after its stay on the MERC review order.
The MERC order had come under severe <a href="https://www.mercomindia.com/maharashtras-energy-banking-rules-could-limit-solar-capacity-additions" target="_blank" rel="noopener">criticism</a> from solar project developers, who contended that the energy banking rules could effectively reduce the savings generated from a solar project and disincentivize solar adoption for MSEDCL consumers.
Background
The petitioner, the National Solar Energy Federation of India, filed writ petitions in the Bombay High Court, challenging MERC’s banked renewable energy usage review order.
It argued that the revised limitations on the use of banked solar power at the same time-of-day slot defeated the purpose of power banking. It also submitted that these changes in power banking would extend to existing open access agreements and long-term transmission contracts, despite settled law that such changes must apply prospectively.
It contended that the new banking restrictions only applied to MSEDCL consumers, while those of Tata Power and Adani Electricity&#8217;s distribution companies remained unaffected.
The court issued interim orders on July 1, 2025, and August 8, directing that the mandate from MERC not be given effect.
Later, the petitioner approached the High Court for relief, claiming that as of July 25, MSEDCL continued to credit renewable energy only during solar hours. It argued that MSEDCL’s actions violated the High Court’s orders and also the original order on the framework, which allowed banked renewable energy usage at any time except during peak hours.
MSEDCL argued that while billing was done for solar hours, the surplus units were not lapsed. This complied with the court’s directions. It also contended that the High Court&#8217;s staying of the MERC order did not revive the original MYT order.
Court’s Analysis
The High Court held that its previous judgments considered the reading of the original MYT’s order. It stated that its orders meant reverting to the previous position, allowing the use of banked renewable energy at any time except during peak hours.
It directed that the billing would be done under the provisions of the original MYT framework order. The petitioners would be at liberty to pay the July 25 bill to MSEDCL under protest.
However, the High Court stated that the order on the writ petitions, which is yet to be issued, would apply to the petitioners.
Subscribe to Mercom’s real-time <a href="https://mercomindia.com/product/mercoms-renewable-energy-regulatory-updates/" target="_blank" rel="noopener">Regulatory Updates</a> to ensure you don’t miss any critical updates from the renewable industry.

Bombay High Court Stays MSEDCL’s Restrictions on Banked Renewable Energy

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					</table>Nearly 4 GW of wind-solar energy has been curtailed in Rajasthan since March 2025 due to delays in transmission projects and lower power demand resulting from above-normal rainfall in north India.
In March 2025, several developers in Rajasthan received notices from the regional load dispatch centres about time-block-wise curtailment of renewable energy. The curtailment, which started at 8.5% in March, rose to 51.5% by August.
Solar and wind projects were granted a ‘must-run’ status in 2021. Any curtailments can only be made for reasons of grid safety and security, and must be communicated in writing to the generators.
Highlighting the plight of developers, the National Solar Energy Federation of India (<a href="https://www.nsefi.in/" target="_blank" rel="noopener">NSEFI</a>) wrote to the Ministry of New and Renewable Energy (MNRE), stating that solar projects in Rajasthan are not being commissioned, due to 18- to 20-month delays in transmission lines.
NSEFI stated that the total general network access (GNA) capacity in Rajasthan is 14,000 MW, while ~22,500 MW is currently commissioned and approved under GNA and temporary GNA. This has resulted in a curtailment of up to 48% during peak hours.
The Federation highlighted that several key solar projects under Phase II of the renewable energy transmission system in Rajasthan (765 kV Khetri–Narela D/C line, 765 kV Bhadla II–Sikar II D/C line, and the 400 kV Narela–Maharani Bagh line) are facing curtailment due to delays in transmission infrastructure by up to two years.
The curtailment is largely for solar projects, but wind projects are being curtailed to a smaller extent.
Kartikeya Narain Sharma, Co-Founder and Chief Business Officer at <a href="https://sunsure-energy.com/" target="_blank" rel="noopener">Sunsure Energy</a>, stated that while Rajasthan is most severely affected by solar curtailment, Gujarat, Maharashtra, and Tamil Nadu have also been impacted.
Developers report that curtailment can reach up to 51.5% during peak solar hours.
“The curtailment starts at 9:30 AM with 15%, rising to 51.5% during the 10:30 AM to 2:30 PM time block. The situation has been prevalent since March 28, 2025. Since the past five months, we have been promised the curtailment will stop within a month,” said a developer.
There has been curtailment in Gujarat at rates of 10% to 30% and in Maharashtra (10% to 15%).
Akshay Hiranandani, CEO of <a href="https://www.serenticaglobal.com/">Serentica Renewables</a>, anticipates that the curtailment will continue until December 2025.
Lower Power Demand
Developers in Rajasthan attribute the curtailment to lower power demand and delays in the transmission infrastructure required for evacuation.
Sharma stated that the extended monsoon has resulted in muted power demand.
In May, the real-time market on the Indian Energy Exchange experienced market-clearing prices plummeting to near-zero levels, due to a surge in power supply and a simultaneous decline in demand caused by unseasonal rains and thunderstorms.
The country’s energy consumption during the month decreased 1.5% year-over-year to 150.04 billion units; however, this dip was only for one month.
Hiranandani said that the curtailment is primarily being carried out on the deemed T-GNA due to the unavailability of transfer capacity after corridor allocation to the prioritized GNA.
He explained that over the past few years, GNA connectivity has expanded rapidly, driven in part by the waiver of interstate transmission system charges, which has led to congestion in the network.
“Essentially, the issue is less about generation capacity being too high and more about grid infrastructure lagging behind the rapid scaling of renewables. The gap between transmission readiness and generation growth is now becoming evident in the form of large-scale curtailment.”
Developers claim that the delay in the transmission line from Khetri (Rajasthan) to Narela (Delhi), which has been the primary driver of the curtailment, has been delayed by nearly two years. According to a project developer, the transmission line was expected to be commissioned by November 2023.
Financial Losses 
Developers report that they are incurring significant losses due to the curtailment.
NSEFI, in its letter to MNRE, stated that developers have incurred losses between ₹2.3 billion (~$26.25 million) to ₹2.5 billion (~$28.53 million) for FY26 so far.
Hiranandani said that a curtailment of 1 GW for four hours a day over 10 months translates into nearly ₹3.6 billion (~$41 million) in lost revenue at a tariff of ₹3 (~$0.034)/kWh. “For capital-intensive renewable projects, where financial models are built on predictable generation, such losses are deeply damaging. They directly affect debt servicing ability, reduce investor returns, and erode overall confidence in the sector.”
A project developer told Mercom that the curtailment is resulting in revenue losses of up to 20-25%, raising concerns about insolvency if the high-level curtailment persists for another six months.
Curtailment to Continue 
While developers say that the transmission issues are expected to get resolved within this year, curtailment could occur in other states once they reach Rajasthan’s installed capacity.
Sharma stated that Rajasthan is the top destination for solar energy. It evacuates a significant amount of power to Uttar Pradesh and the National Capital Region. “Rajasthan was hit this year because it is the first choice for developers. Gujarat, Karnataka, Andhra Pradesh, and Madhya Pradesh are the next choices. Once solar capacity in those states reaches Rajasthan’s scale, they too may face curtailment due to transmission issues.”
He noted that this year saw high curtailment in northern India, but the root cause is expected to be resolved within the current financial year. “In the near term, curtailment due to a lack of transmission corridors is going to be part of life in different parts of the country.”
Is BESS the Solution?
Sharma said that transmission corridors are much harder to build than renewable energy projects, and hence, BESS can aid in utilizing them fully.
He added that Rajasthan is one of the country’s largest renewable energy zones, with around 50 GW of evacuation infrastructure. “But most of the power is solar, so it is used at best for eight hours a day and can only meet 30% to 35% of power requirements. With the addition of battery energy storage systems (BESS), this utilization can extend to 16 hours. The storage system can double the utilization of transmission infrastructure.”
He added that if one compares the prices paid by distribution companies to the exchange during peak hours, with fulfillment rates of up to 20% to 25%, storage is feasible. “It can help solve both the demand-supply gap during peak hours and the underutilization of infrastructure.”
Hiranandani said that BESS can help absorb power during curtailment periods and release it when demand is high or when corridors are unconstrained. “Over time, storage will serve as a buffer against both forecast variability and transmission congestion.”
Another project developer stated that while they are looking to install BESS on a war footing, regulatory challenges are impacting its viability.
Solutions to Avoid Curtailment
Developers emphasize that the timely commissioning of transmission projects is crucial to prevent future curtailments.
Hiranandani stated that adopting dynamic line rating, which can significantly improve transmission efficiency by adjusting line capacity in real-time based on temperature and weather conditions, rather than relying on static ratings, is vital.
He also suggested deploying storage assets at substations, which will enable BESS charging during the daytime and discharging during nighttime.
Another project developer emphasized the need for a strong deterrent to prevent transmission delays and insisted on imposing heavy penalties on transmission infrastructure developers who delay projects.
Hiranandani said independent power producers have written to the authorities seeking redressal. In the absence of a timely resolution, approaching the Central Electricity Regulatory Commission for a structured compensation mechanism will be the logical next step.
In its letter, NSEFI has also urged the government to expedite the implementation of critical transmission system components and build strategic transmission projects under the regulated tariff mechanism.
It also requested that the government establish a comprehensive compensation mechanism for developers to mitigate revenue losses resulting from involuntary curtailment.  The compensation could include providing funds to compensate developers, installing BESS to utilize curtailed power, and facilitating market sales. It also suggested providing viability gap funding for the installation of BESS in substations experiencing congestion.
NSEFI wants the government to incorporate modifications into future power purchase agreement conditions to account for the non-availability of GNA as a ‘change in law’ event.

Rajasthan Curtails 4 GW of Solar and Wind as Transmission Delays Mount

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					</table>REC Power Development and Consultancy (<a href="https://www.recpdcl.in/" target="_blank" rel="noopener">RECPDCL</a>) has invited bids to establish a 400/132 kV AIS substation in Jalna district, Maharashtra. The project will be executed on a build, own, operate, and transfer basis.
Bids must be submitted by October 31, 2025. Bids will be opened on the same day.
Bidders must furnish an earnest money deposit of ₹100 million (~$1.16 million) and a bid document of ₹500,000 (~$5,813.95) plus 18% GST.
Successful bidders must submit a contract performance guarantee of ₹250 million (~$2.91 million).
RECPDCL has said the neighboring regions of Tirthpuri, Ghansawangi, Partur, and Utwad are rich in renewable energy, with a potential of 1 GW to 2 GW that can be transmitted through the proposed substation.
The scope of work includes the survey, design, engineering, procurement, financing, construction, testing, and commissioning of the substation. It also entails providing operation and maintenance services for 35 years.
Selected bidders must install three 315 MVA, 400/132 kV interconnecting transformers (ICTs), one 125 MVAr bus reactor at 400 kV, four 400 kV line bays, three 400 kV ICT bays, one 400 kV reactor bay, 12 132 kV line bays, and three 132 kV ICT bays. The substation will provide space for one additional 315 MVA ICT and future bays.
The project scope covers a loop-in-loop-out (LILO) of the 400 kV Aurangabad-II (Thaptitanda)–Aurangabad-III (Ektuni) double circuit line at AIS Jalna, and multiple 132 kV outgoing double circuit lines, including connections to Jalna MIDC, Partur, Ghansawangi, and Utwad substations, along with LILO of the Jalna–Nagewadi 132 kV line. The respective utilities will provide bays at existing substations. For LILOs, the conductor and optical ground wire specifications must match existing line parameters.
The projects must be commissioned within 24 months.
Bidders must have developed projects with capital expenditures of at least ₹5 billion (~$58.14 million) or have received construction payments of a similar scale.
Bidders must have a minimum net worth of ₹2.5 billion (~$29.07 million).
In June this year, RECPDCL <a href="https://www.mercomindia.com/recpdcl-invites-bids-to-enhance-western-southern-grid-power-connectivity" target="_blank" rel="noopener">invited</a> bids for the implementation of a 765 kV interstate transmission system between Parli New, Maharashtra, and Bidar, Karnataka, on a build, own, operate, and transfer basis.
In the same month, RECPDCL <a href="https://www.mercomindia.com/recpdcl-invites-bids-to-evacuate-2-gw-of-power-from-solar-park-in-tumkur" target="_blank" rel="noopener">issued</a> a request for proposal for developing a 2,000 MW intrastate transmission system to evacuate power from a proposed solar park at Ryapte village in Tumkur district, Karnataka.

REC Invites Bids for 400/132 kV Substation Project in Maharashtra

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					</table>The Jharkhand State Electricity Regulatory Commission (<a href="https://jserc.org/" target="_blank" rel="noopener">JSERC</a>) has issued the draft “Terms and Conditions for Determination of Distribution Tariff Regulations, 2025.” These regulations, with a control period from April 1, 2026, to March 31, 2031, establish the financial and operational framework for electricity distribution in the state.
The draft aims to promote competition among distribution licensees, improve operational efficiency, ensure prudent investment in infrastructure, and guarantee a reliable electricity supply to consumers.
Scope and Applicability
The regulations apply to all distribution licensees operating in Jharkhand and cover the determination of aggregate revenue requirement (ARR) and tariffs for electricity wheeling and retail supply.
To promote competition, the Commission may prescribe a maximum ceiling tariff for retail supply only, where multiple licensees supply electricity in the same area. For consumers with open access permissions, the Commission will determine wheeling tariffs, cross-subsidy surcharges, additional surcharges, and related charges in accordance with the JSERC Intra-State Open Access Regulations, 2016.
The tariffs determined under these regulations are considered ceiling tariffs. Distribution licensees are permitted to propose reduced tariffs for consumers. However, such reductions will not affect their revenue requirement as approved by the Commission.
Multi-Year Tariff Framework
The multi-year tariff (MYT) framework is a central component of the regulations. It requires distribution licensees to file MYT applications with supporting documents, including audited accounts for the fiscal years (FY) 2021 to 2025, revised estimates for the FY 2026, and projections for each year of the control period.
The guiding principles include filing a business plan for the entire control period, forecasting ARR and tariffs for each year, prescribing trajectories for performance parameters, and conducting annual performance reviews.
Variations in performance are categorized into controllable and uncontrollable factors. A mechanism has been established to distribute gains and losses from controllable factors between licensees and consumers, while fully accounting for uncontrollable variations.
Segregation of Accounts
Licensees must maintain separate accounts for wheeling and retail supply businesses. Where accounts are not fully segregated, allocation statements must apportion revenues, costs, and assets.
The allocations must be approved by the board of directors and accompanied by a clear methodology. If a methodology is not provided, the Commission can adopt previously approved allocation norms, such as allocating 40% of employee costs to supply and 60% to wheeling, or assigning 100% of power purchase costs to supply.
Business Plan Requirements
Every licensee must submit a business plan for the control period, separately for retail supply and wheeling businesses. The plan must include:
<ul>
<li>Capital investment plan: A program-wise plan detailing purpose, approval, capital structure, detailed project reports, cost-benefit analysis, capitalization schedule, and implementation timelines. Projects must cover load growth, asset replacement, reduction of technical and commercial losses, quality improvements, and enhancements to customer service</li>
<li>Sales and demand forecasts: Category-wise and voltage-wise projections for each year, based on historical growth, consumption patterns, and anticipated demand</li>
<li>Power procurement plan: Covering demand forecasts, renewable purchase obligations, energy efficiency, and demand-side management</li>
<li>Targets for controllable parameters: Including distribution loss reduction, billing efficiency, collection efficiency, working capital requirements, and quality of supply metrics such as system average interruption frequency index (average number of interruptions per customer per year), system average interruption duration index, and momentary average interruption frequency index (average number of momentary interruptions per customer per year)</li>
<li>Human resource plan: Year-wise manpower additions and retirements to meet demand growth</li>
<li>Non-tariff income and other business proposals: Itemized revenue streams and their projections</li>
</ul>
The business plan must also include audited data from the previous control period, covering capital investment, consumer base, power procurement, and expenses.
Power Procurement Framework
Licensees must prepare power procurement plans for the entire control period, based on sales forecasts and demand projections. These plans can include long-term (12 to 25 years), medium-term (three months to 3 years), and short-term (up to one month) contracts. Short-term procurement is discouraged except in cases of supply failure, emergencies, or cost reduction.
Each plan must include monthly demand and supply projections in MW and million units, base and peak load requirements, renewable energy procurement, and measures for energy conservation.
A mandatory, application-based, automated tool utilizing artificial intelligence and machine learning must be implemented to manage procurement portfolios. This tool must optimize procurement cost, minimize deviation settlement mechanism charges, and improve demand-supply forecasting.
All power purchase agreements require prior Commission approval. Cost overruns without approval may be disallowed. Short-term purchases must be reported to the Commission within 15 days.
Operation and Maintenance Expenses
Operation and maintenance (O&amp;M) expenses consist of employee costs, administrative and general (A&amp;G) expenses, and repairs and maintenance (R&amp;M). For the base year, O&amp;M expenses will be determined based on audited accounts for FY 2021 to FY 2025, estimates for FY 2026, and prudence checks.
Future O&amp;M costs are indexed. R&amp;M expenses are determined by linking to Gross Fixed Assets (GFA) using the formula R&amp;M = K × GFA × (Indexn / Index0), where K is a constant and the index is based on the consumer price index and the wholesale price index.
Employee and A&amp;G expenses are similarly indexed, with the Consumer Price Index carrying a 55% weight and the Wholesale Price Index a 45% weight. Terminal liabilities will be allowed at actuals. Pay commission revisions and wage agreements will be considered separately.
Legal expenses can be claimed, provided supporting documentation is submitted, such as invoices, fee receipts, and case references. However, costs related to cases filed against Commission orders are not recoverable.
Capitalization and Financing
Capital costs include expenditure on the original scope of work, financing charges, and interest during construction. Capitalized initial spares are allowed up to 1.5% of the project cost. Costs funded by consumer contributions, grants, or deposit works will be deducted from the capital base.
Additional capitalization is permitted for deferred liabilities, arbitration awards, statutory orders, changes in law, and force majeure events. De-capitalization requires statutory auditor certification and corresponding adjustments to loan and equity accounts. Asset monetization proposals may be considered, provided grid security is not compromised.
Financial Parameters
Debt-Equity Ratio
For programs capitalized after April 1, 2026, a normative debt-equity ratio of 70:30 is prescribed. If actual equity exceeds 30%, the excess will be treated as debt. If actual equity is less than 30%, the actual ratio will apply.
Return on Equity
The return on equity (RoE) is fixed at 14.5% (post-tax) for assets capitalized before the notification of these regulations and 14% thereafter. An additional 0.5% RoE may be granted if uninterrupted supply is provided to universal service obligated entities, such as hospitals, schools, public water supply systems, street lighting, and renewable energy projects. Non-compliance with renewable purchase obligations may reduce RoE by up to 1.5%.
Tariff Recovery and Fixed Charges
Tariffs determined under these regulations serve as ceilings. Licensees may propose reduced tariffs, but the revenue requirement will not be lowered. Recovery of fixed charges is linked to the minimum hours of supply.
Cross-Subsidy and Additional Surcharges
Cross-subsidy surcharge is calculated using the formula: S = T – \[C / (1 – (L / 100)) + D + R], where T is the tariff payable by the consumer category, C is the weighted average power purchase cost, D is transmission and wheeling charges, L is losses, and R is regulatory asset cost. The surcharge is capped at 20% of the average cost of supply. An additional surcharge will be levied only if stranded costs are demonstrated.
Fuel and Power Purchase Adjustment Surcharge
The fuel and power purchase adjustment surcharge (FPPAS) mechanism allows recovery of variations in power procurement costs. It will be billed in the second subsequent month.
If the variation is up to 5%, the full amount will automatically be recoverable. For variations above 5%, 90% of the balance is recoverable automatically, with the remaining portion subject to Commission approval.
The formula for FPPAS accounts for actual power purchase, bulk sales, incremental average power purchase cost, transmission charges, and approved losses. Carry-forward is permitted for up to two months, with carrying costs allowed at bank rate plus 150 basis points.
Excess recovery must be refunded, including carrying cost, at 1.2 times the approved rate. Licensees must update their billing systems to implement this mechanism and publish all calculations on their websites.
Late Payment Surcharge
Consumers must pay bills within 15 days (for high-tension/extra-high-tension) or 21 days (for low-tension). Delays incur a late payment surcharge at 12% per annum for up to 60 days and 14% per annum for delays between 60 and 90 days. These charges will apply on a simple interest basis to outstanding amounts, including taxes, duties, and levies.
In July this year, JSERC <a href="https://www.mercomindia.com/jharkhand-draft-regulations-determine-solar-tariffs" target="_blank" rel="noopener">issued</a> draft regulations to determine the tariff for procuring power from solar and solar-thermal power projects.
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Jharkhand Issues Draft Regulations for Electricity Tariffs

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					</table>Power Grid Corporation of India (<a href="https://www.powergrid.in/" target="_blank" rel="noopener">POWERGRID</a>) has received a letter of intent from REC Power Development and Consultancy (<a href="https://www.recpdcl.in/" target="_blank" rel="noopener">RECPDCL</a>) to establish an interstate transmission system (ISTS) in Karnataka to integrate renewable energy generation.
POWERGRID must install four 500 MVA, 400/220 kV ICTs (5th-8th) at Davanagere pooling station (PS), along with associated 400 kV and 220 kV ICT bays. They must also augment Davanagere/Chitradurga PS with one 1500 MVA, 765/400 kV ICT, complete with its 765 kV and 400 kV ICT bays.
Two 220 kV line bays will also be added at Davanagere/Chitradurga PS to terminate dedicated transmission lines from renewable energy generation projects.
The scheduled commercial operation date (COD) for the 765/400 kV, 1×1500 MVA ICTS augmentation is 24 months.
The tender for this project was <a href="https://www.mercomindia.com/recpdcl-invites-bids-for-transmission-system-augmentation-in-karnataka/" target="_blank" rel="noopener">issued</a> in May this year. The other bidders were H. G. Infra Engineering, Techno Electric &amp; Engineering Company, and Ramalingam Construction Company.
POWERGRID’s scope of work includes the engineering, procurement, construction, financing, and commissioning of the ISTS. Additionally, it involves providing operation and maintenance (O&amp;M) services for 35 years from COD.
After the O&amp;M period, all project assets, including the substation land, right-of-way, and clearances, will be transferred to the Central Transmission Utility or its successors at no cost and free from encumbrance.
The Ministry of New and Renewable Energy identified a renewable energy potential of 4 GW in Davanagere/ Chitradurga. The transmission system for integrating 2 GW of renewable energy is already under implementation. Connectivity of about 1,850 MW has been granted/agreed for grant at Davanagere PS with the transmission system. Additionally, applications for connectivity of about 1,325 MW have been received at Davanagare PS.
In March, POWEGRID <a href="https://www.mercomindia.com/powergrid-transmission-project-renewable-energy/" target="_blank" rel="noopener">received</a> a letter of intent from PFC Consulting to establish an ISTS at Kurnool-III PS, Andhra Pradesh, to integrate 4.5 GW of renewable energy. This project involves augmenting the transformation capacity at the existing Kurnool-III substation, along with a 765 kV direct current transmission line.
POWERGRID also <a href="https://www.mercomindia.com/powergrid-wins-three-renewable-energy-transmission-projects-from-recpdcl/" target="_blank" rel="noopener">received</a> letters of intent for three transmission projects from RECPDCL, cumulatively worth ₹107.5 billion (~$1.2 billion). The three projects are a transmission system for power evacuation from the Rajasthan Renewable Energy Zone (REZ) Phase V, an augmentation of transformation capacity at Banaskantha, Gujarat, and another transmission system project for the integration of Kurnool-IV REZ Phase I in Andhra Pradesh.

POWERGRID Bags Transmission Project to Integrate Renewable Energy in Karnataka

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					</table>India’s power transmission sector is staring at supply chain shortages and higher procurement costs due to a high demand for transformers and other critical transmission components.
Stakeholders report a growing stress in the power system supply chain, with supply falling short of meeting demand for components such as transformers, control relay panels, tower parts, insulators, and gas-insulated switchgear (GIS). Longer lead times for procuring these components are leading to delays in transmission and power generation projects.
R K Tyagi, Chairman and Managing Director at Power Grid Corporation of India (<a href="https://www.powergrid.in/en/" target="_blank" rel="noopener">POWERGRID</a>), recently spoke at length on the transmission sector’s challenges arising from steep inflation. According to him, transformer costs alone have doubled in the last seven years.
“Transformers, which cost about ₹140 million (~$1.59 million), are now almost at ₹300 million (~$3.41 million). A GIS bay, which cost ₹60 million (~$683,946), now costs ₹150 million (~$1.7 million),” he told an analysts’ conference recently.
“We do not get bids from more than two equipment suppliers for each tender. Everybody’s hands are full,” said Tyagi.
To overcome the problem, POWERGRID procures enough transformers for two to three projects in advance.
A seller-market scenario is prevailing, with suppliers dictating prices. Tyagi said there is no option but to buy at the costs quoted by suppliers.
Industry leaders echoed these concerns at the recent <a href="https://www.mercomindia.com/event/renewables-summit-2025" target="_blank" rel="noopener">Mercom India Renewable Summit 2025</a>. Simarpreet Singh, CEO at <a href="https://hartek.com/" target="_blank" rel="noopener">Hartek Group</a>, pointed to the problem of the lack of timely availability of equipment. He said long equipment delivery timelines are now the main reasons for project delays.
“We are also facing challenges with equipment such as circuit breakers, isolators, and control relay panels. We must address the lack of quality manufacturers in the high-voltage and extra-high-voltage segments,” said Singh.
He stated that while significant attention has been given to the domestic manufacturing of solar modules, other components essential to the transmission and distribution ecosystem have not received adequate policy or investment focus.
Vaibhav Roongta, Chief Business Officer at <a href="https://rayspowerinfra.com/" target="_blank" rel="noopener">Rays Power Infra</a>, drew attention to the growing lead times for critical high-voltage equipment, such as 220 kV and 400 kV switchyards, transformers, and isolators, which have now reached almost 20 months, exacerbating project delays.
The government has <a href="https://www.mercomindia.com/india-to-expand-power-transmission-network-to-meet-458-gw-demand-by-2032" target="_blank" rel="noopener">targeted</a> expanding India’s power transmission network to 648,000 circuit kilometers (ckm) in 2032 from 485,000 ckm in 2024. The plan is to meet a peak electricity demand of 458 GW by 2032. The demand-supply mismatch for critical transmission equipment could jeopardize this target if not addressed in time.
Transformer supply crunch is not a problem limited to India alone. A recent Wood Mackenzie report <a href="https://www.mercomindia.com/us-struggles-with-transformer-supply-shortages" target="_blank" rel="noopener">said</a> power transformers and distribution transformers in the U.S. are currently in a supply deficit of 30% and 6%, respectively, based on annual supply and demand estimates.

Supply Chain Shortages and Inflation Delay Power Transmission Projects

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					</table>Power Finance Corporation (<a href="https://www.pfcindia.co.in/" target="_blank" rel="noopener">PFC</a>) has signed a loan agreement for €150 million (~$175.13 million) with <a href="https://www.kfw-entwicklungsbank.de/International-financing/KfW-Entwicklungsbank/" target="_blank" rel="noopener">KfW Development Bank</a>, a German state-owned investment and development bank.
PFC will utilize the loan proceeds to finance projects under the Indian government’s Revamped Distribution Sector Scheme (RDSS).
According to the National Smart Grid Mission data, 8.76 million smart meters have been <a href="https://www.mercomindia.com/smart-meter-deployment-dismal-sunset-date-just-a-year-away" target="_blank" rel="noopener">installed</a> under RDSS as of February 2025.
In January 2025, the Japan Bank for International Cooperation (JBIC) <a href="https://www.mercomindia.com/japan-bank-signs-agreement-to-lend-770-million-to-pfc" target="_blank" rel="noopener">signed</a> an agreement to set up a credit line of JPY120 billion (~$770.64 million) with  PFC. JBIC’s share of the total credit line will be JPY72 billion (~$462.38 million).
Renewable energy in India is <a href="https://www.mercomindia.com/indias-renewable-energy-space-is-mainstream-now-for-lenders" target="_blank" rel="noopener">increasingly</a> being viewed as a mainstream segment by lenders who are eager to finance various clean energy projects. Capital is no longer a constraint for well-governed companies with a good track record.
In the financial year 2025, PFC primarily<a href="https://www.mercomindia.com/higher-net-interest-income-strengthens-pfcs-q4-fy-2025-financials" target="_blank" rel="noopener"> lent</a> to the government sector, which accounted for 77% of the loans disbursed, with the remainder going to the private sector. Its loan assets totaled ₹5.43 trillion (~$63.43 billion), and loan disbursements reached ₹1.68 trillion (~$19.62 billion).
As of March 31, 2025, PFC had a borrowing mix of ₹888.77 billion (~$10.38 billion) of rupee term loans from banks/financial institutions (19%), ₹891.32 billion (~$10.41 billion) of foreign currency borrowings (19%), and ₹2.61 trillion (~$30.49 billion) of domestic bonds (56%).
On June 30, 2025, the Ministry of Power <a href="https://www.mercomindia.com/government-conceives-india-energy-stack-to-digitalize-power-sector" target="_blank" rel="noopener">announced</a> the launch of a task force to establish the India Energy Stack under the RDSS program. The initiative aims to create a unified, secure, and interoperable digital infrastructure for the country’s energy sector.
In March 2025, the Ministry of Power <a href="https://www.mercomindia.com/two-year-extension-of-distribution-sector-reforms-program-on-the-cards" target="_blank" rel="noopener">informed</a> Parliament’s Standing Committee on Energy that it requires a two-year extension of the RDSS program, aimed at introducing operational efficiencies and financial discipline into India’s power distribution sector.

PFC Secures €150 Million Loan from KfW for Power Distribution Program

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					</table>Power and distribution transformers in the U.S. are seeing supply deficits of 30% and 6% respectively, based on annual supply and demand estimates, according to a <a href="https://www.woodmac.com/" target="_blank" rel="noopener">Wood Mackenzie</a> report.
Transformer costs are likely to continue increasing with the imposition of U.S. trade tariffs, as the industry is highly dependent on imports for both finished equipment and underlying components and commodities.
Not only will the average cost per transformer increase significantly due to the tariffs, but lead times will grow as imports from high-tariff countries become cost-prohibitive.
“The ongoing market deficit, combined with the aggressive trade policy, will continue putting upward pressure on U.S. transformer prices over the coming years. We calculate that prices will jump by a further 20% to 30% depending on the specification, further straining project costs.”
Impacts range from less than 2% to over 15% depending on the transformer type and tariff scenario.
The tariffs factored into each case are as follows:
<ul>
<li>Base case: includes existing tariffs as of August 2025, including the new 50% copper tariff, 50% Indian and Brazil tariff, and 35% on non-U.S.-Mexico-Canada Agreement-compliant imports from Canada</li>
<li>Low case: represents the unsuccessful appeal of the tariff ban, which would revert to 50% commodity-specific tariffs only</li>
<li>High case: includes all tariffs factored into the base case as well as additional tariffs on countries without an agreement, including China and the European Union</li>
</ul>
Many of the largest transformer original equipment manufacturers have announced capacity expansions worth $1.8 billion since 2023 to address the market shortage. However, the demand growth rate will require even more investment to rebalance the market.
<a href="https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/US-Transformer-image-1.png"><img loading="lazy" decoding="async" class="aligncenter wp-image-83753 size-full" src="https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/US-Transformer-image-1.png" alt="U.S. Transformer 1" width="752" height="225" srcset="https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/US-Transformer-image-1.png 752w, https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/US-Transformer-image-1-300x90.png 300w, https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/US-Transformer-image-1-650x194.png 650w, https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/US-Transformer-image-1-624x187.png 624w, https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/US-Transformer-image-1-600x180.png 600w" sizes="(max-width: 752px) 100vw, 752px" /></a>
Transformer Demand Surge
Transformer demand in the U.S. has surged due to a 7% rise in electricity consumption between 2010 and 2020. This growth has been driven by rapid data center expansion, a nearly doubling of manufacturing construction spending due to the tax incentives of the 2022 Inflation Reduction Act, and widespread electrification.
Ageing equipment is adding to the shortage. A 2024 Department of Energy study found that 40 million units, or 55% of in-service distribution transformers, were over 33 years old and well beyond their service life. An increase in extreme weather events has heightened the risks to grid reliability. Domestic manufacturing capacity has been unable to keep pace with the growing demand.
Wood Mackenzie stated that utilities are increasingly relying on imports, with estimates suggesting that imports account for 80% of U.S. power transformer supply and 50% of distribution transformer supply.
This trend is most evident in power and generation step-up transformers, where demand is estimated to have increased 116% and 274%, respectively, since 2019. Even distribution transformers, which comprise nearly 98% of transformer demand on a unit basis, have seen growth ranging from 30% to 80%.
Long Lead Times
The shortage has led to a significant rise in both lead times and prices in most transformer categories. Since 2019, unit costs have risen by 45% for generation step-up, 77% for power, and 78% to 95% for distribution transformers. However, higher-voltage units have seen larger U.S. dollar-based cost escalations due to higher baseline costs.
<a href="https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/US-Transformer-image-2.png"><img loading="lazy" decoding="async" class="aligncenter wp-image-83754 size-full" src="https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/US-Transformer-image-2.png" alt="US Transformer 2" width="752" height="310" srcset="https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/US-Transformer-image-2.png 752w, https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/US-Transformer-image-2-300x124.png 300w, https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/US-Transformer-image-2-650x268.png 650w, https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/US-Transformer-image-2-624x257.png 624w, https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/US-Transformer-image-2-600x247.png 600w" sizes="(max-width: 752px) 100vw, 752px" /></a>
Wood Mackenzie also highlighted market volatility for grain-oriented electrical steel, for which prices have reached all-time highs. The U.S. relies on a single domestic supplier, forcing many original equipment manufacturers to import raw electrical steel or semi-finished transformer cores.
Copper windings have emerged as another potential bottleneck to transformer production, due to their highly technical manufacturing process and niche specifications. The U.S. government’s 50% copper tariffs are likely to worsen the issue.
Besides the shortage of specialist technical manpower in transformer manufacturing, the domestic sector is cautious about expanding capacity due to uncertainties caused by the “One Big Beautiful Bill.”
The U.S. Treasury Department recently <a href="https://www.mercomindia.com/us-treasury-guidance-tightens-renewable-energy-tax-credit-rules" target="_blank" rel="noopener">announced</a> new rules to limit wind and solar companies from claiming federal tax breaks. It also obligated utility-scale projects to conduct off-site physical work tests for power equipment, including transformers.
The Indian renewable energy industry is also grappling with transformer shortages, as renewable energy installations and pipelines continue to rise consistently. Last year, Mercom <a href="https://www.mercomindia.com/shortage-power-transformers-india-solar" target="_blank" rel="noopener">reported</a> that solar projects were being delayed due to longer lead times for power transformers.

US Struggles with Transformer Supply Shortages

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					</table>For nearly a decade, India’s interstate transmission system (ISTS) charges waiver has quietly shaped renewable power economics. By lowering landed tariffs on interstate sales, it encouraged the adoption of corporate open access and gave developers the confidence to scale. That cushion is now disappearing. The full waiver for solar and onshore wind expired on June 30, 2025, and has been replaced with a phased taper that will run until June 30, 2028.
The new framework <a href="https://www.mercomindia.com/no-ists-charges-waiver-solar-wind-june-2028" target="_blank" rel="noopener">reduces</a> charges by 75% in the financial year (FY) 2026, 50% in FY 2027, and 25% in FY 2028 before complete withdrawal. Developers and offtakers are now weighing how this shift will alter tariffs, project viability, and long-term growth in a sector that leaned heavily on waiver-driven competitiveness.
Tariff Impacts 
Industry leaders are split on how much the tapering will affect tariffs. Some argue it has no direct bearing on discovered prices, while others warn it will push landed costs higher and dampen demand.
Rahul Mishra, Senior VP and Head of C&amp;I Business at <a href="https://blupineenergy.com/" target="_blank" rel="noopener">BluPine Energy</a>, believes that competitive bidding shields tariffs from transmission charges. Since bids are placed at the grid substation level, transmission costs are not factored into the quoted price.
He feels efficiency in capital deployment, technology, and execution discipline matter far more than transmission dynamics.
Others see the reality differently. Sanjeev Gupta, Director – Technical and Projects at <a href="https://hartek.com/" target="_blank" rel="noopener">Hartek Group</a>, pointed out that the full waiver effectively lowered landed tariffs by ₹0.40 (~$0.00457)/kWh to ₹0.50 (~$0.00571)/kWh. With tapering, he expects tariffs for distribution companies (DISCOMs) and corporate buyers to climb, which could strain procurement in a price-sensitive market.
Siddharth Bhatia, Managing Director at <a href="https://www.oysterrenewable.com/" target="_blank" rel="noopener">Oyster Renewables</a>, added that once the waiver is fully withdrawn, renewable power supplied through the grid could cost ₹0.80 (~$0.00914)/kWh to ₹1 (~$0.01143)/kWh more. While operational efficiencies and contract arrangements may offset some of the increase, buyers would still see higher bills overall.
The contrasting views highlight a deeper divide: tender tariffs may not formally reflect transmission costs, but landed prices at the buyer’s end do. Gupta warned, “Under the 75%, 50%, and 25% phase-down, tariffs could move upwards by 8% to 12%,” a level that could influence demand in states with strict tariff caps.
Deadline Pressure 
The phase-down has triggered a wave of accelerated project execution. Developers across the sector pushed capacity forward to meet waiver-linked commissioning deadlines.
BluPine fast-tracked projects to align with the June 2025 cutoff and sought the Ministry of New and Renewable Energy-backed extensions in cases where land clearances, supply disruptions, or force majeure held things up.
Oyster Renewables adopted a similar approach, front-loading parts of its pipeline to maintain tariff competitiveness for DISCOMs and commercial and industrial buyers, while documenting bottlenecks, such as land acquisition delays or module import slowdowns, to justify extensions. Hartek moved aggressively to speed up nearly a third of its planned pipeline.
The net effect has been a sector-wide rush to deliver, driven not only by market economics but by regulatory timelines that have left little room for slippage.
Rethinking Siting Strategies
The taper is also pushing companies to rethink where they build. BluPine is already shifting its attention to within-state, state transmission utility-connected projects for corporate buyers, viewing them as a means to retain competitiveness once interstate transmission charges fully return after 2028.
Mishra noted that factors such as falling equipment prices and efficiency gains could eventually help absorb transmission costs. Still, in-state siting provides an added layer of cost stability for clients.
Oyster Renewables is taking a dual approach. The company continues to develop interstate projects where scale and resource quality give it an advantage, while selectively pursuing in-state supply structures when they reduce transmission risk.
Bhatia described this as a portfolio strategy that balances cost, optimizes capacity utilization, and secures predictable revenue.
Hartek is exploring similar site-level flexibility, preparing to keep power within state borders wherever viable once ISTS costs are reinstated.
Transmission Bottlenecks Under the GNA Framework
The General Network Access (GNA) regime, <a href="https://www.mercomindia.com/cerc-connectivity-general-network-access-regulations" target="_blank" rel="noopener">introduced</a> in 2022, was meant to streamline approvals and improve transparency. Experiences so far have been mixed.
BluPine reports smooth approvals at the initial stage, though execution of supporting infrastructure has required careful coordination. Its Central Transmission Utility projects have avoided curtailment so far; however, the company closely monitors congestion forecasts.
Oyster’s experience has been more uneven. While the framework has created more standardization, augmentation delays, and right-of-way challenges persist in high-demand corridors, and curtailments remain a real risk during peak renewable generation.
Hartek notes bottlenecks in augmentation and congestion are adding costs and undermining project economics.
The consensus among developers is that while the framework has improved the approval process, the physical build-out of transmission infrastructure continues to lag behind the growth of renewable energy sources.
Storage and Risk Management 
Battery storage is emerging as a key hedge against the taper. BluPine is weighing the economics of co-located battery energy storage systems to retain the 100% ISTS charges waiver until June 2028, citing dispatch flexibility and grid stability benefits. Hartek is moving in the same direction, pairing storage with upcoming projects to sustain competitiveness.
Oyster is more cautious, warning that storage inevitably raises tariffs. Instead, it is experimenting with customized solutions that vary battery size depending on customer needs, aiming to smooth the supply curve while keeping overall costs in check.
Beyond storage, developers are looking at financial and operational hedges. BluPine sees short-term sales through day-ahead and real-time markets or limited-period GNA as likely strategies for independent power producers once central transmission utility projects go live. Oyster is already evaluating similar approaches as part of its broader risk management toolkit.
Uneven State-Level Impacts
The effects of tapering will not be evenly distributed. Developers expect sharper consequences in states with strict tariff caps and limited corridor availability.
Haryana and Rajasthan are expected to be among the hardest hit, while states with more flexible open-access rules may remain attractive. Resource-rich exporters like Rajasthan, Gujarat, and Tamil Nadu may also face challenges, not because of their generation economics but because long corridors raise landed tariffs for buyers. In contrast, states such as Madhya Pradesh, Maharashtra, and Karnataka could emerge relatively unscathed, and in some cases may even benefit from developers choosing in-state siting.
Prashant Mathur, CEO at <a href="https://saatvikgroup.com/" target="_blank" rel="noopener">Saatvik Green Energy</a>, emphasized the broader transition underway. “The tapering of ISTS charges waiver highlights the evolving economics of renewable energy and the importance of strategic planning to sustain competitiveness. Earlier, the full waiver significantly reduced the cost of transmitting electricity across state lines, helping renewables gain a strong competitive edge. With the phase-down now underway, developers will need to adapt to higher landed tariffs while continuing to attract buyers.”
For the sector, this transition underscores the importance of open access transmission, which can still enable businesses to procure renewable energy from anywhere in the country and reduce regional cost disparities. Done correctly, this will keep the sector attractive for investors and ensure consumers continue to benefit from affordable green power.
Mathur noted that waiver-linked deadlines have already driven faster execution, while the GNA framework has improved transparency, albeit with persisting challenges around augmentation and congestion. States with longer evacuation corridors, such as Rajasthan and Gujarat, may face sharper impacts once the waiver phases down, whereas projects closer to demand centres will remain relatively insulated.
A Defining Moment 
The phase-out of the ISTS charges waiver represents a structural recalibration for Indian renewables. For some developers, it is a threat. Gupta cautioned that without calibrated deadline extensions, “several projects could turn borderline unviable,” potentially slowing India’s broader energy transition. For others, it is a catalyst for adaptation.
Mathur argued that sector competitiveness will now hinge on innovation, diversified offtake models, and continued policy support. Open access transmission, he said, will remain a powerful driver of corporate procurement. With the right mix of policy backing and business innovation, India can still stay on track for its 500 GW non-fossil target by 2030.
The taper removes a long-standing incentive, but it is also forcing developers to adjust strategies, whether through in-state siting, storage integration, portfolio diversification, or market hedging. Those shifts could ultimately make the sector more resilient in the decade ahead.

How Renewable Energy Developers are Rewriting Strategies for Post-ISTS Charges Waiver

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					</table>The Bihar Electricity Regulatory Commission (<a href="https://berc.co.in/" target="_blank" rel="noopener">BERC</a>) has issued the draft regulations for the deviation settlement mechanism.
The regulations apply to all intra-state and grid-connected entities in Bihar, including distribution licensees and deemed distribution licensees. It will also apply to open access consumers (both partial and full) connected to the intra-state transmission system (InSTS). The renewable energy generation stations connected to these InSTS must have at least 5 MW of exportable capacity.
The Commission has invited comments on the deviation settlement mechanism from stakeholders and the public before September 8, 2025. It will also hold a public hearing on September 11, 2025.
Computation of Deviation
Deviation in a time block for general sellers will be computed as follows:
Deviation-general seller (DGS) (in MWh) = [(Actual injection in MWh)–
(Scheduled generation in MWh)].
Deviation-general seller (DGS) (in %) = 100 x [(Actual injection in
MWh) – (Scheduled generation in MWh)]/[(Scheduled generation in MWh)].
Deviation in a time block for WS sellers shall be computed as follows:
Deviation &#8211; WS seller (DWS) (in MWh) = [(Actual Injection in MWh)–
(Scheduled generation in MWh)].
Deviation-WS seller (DWS) (in%) =100 x [(Actual Injection in MWh)–
(Scheduled generation in MWh)]/[(Available Capacity].
Deviation in a time block for buyers shall be computed as follows:
Deviation- buyer ((DBUY) (in MWh) = [(Actual drawal in MWh) –
(Scheduled drawal in MWh)].
Deviation- buyer ((DBUY) (in %) = 100 x [(Actual drawal in MWh) –
(Scheduled drawal in MWh)] / [(Scheduled drawal in MWh)].
Normal Rate of Charges
The normal deviation charge rate for a particular time block will be the highest of the following:
<ul>
<li>The weighted average clearing price (ACP) of the integrated-day-ahead market segments of all the power exchanges</li>
<li>The weighted average ACP of the real-time market segments of all the power exchanges</li>
<li>The sum of 1/3 [ weighted average of ACP of the integrated-day ahead market segments of all power exchanges, 1/3 [ weighted average ACP of the real-time market segments of all the power exchanges, and 1/3 [ancillary service charge computed based on the total quantum of ancillary services (secondary reserve ancillary service – UP and tertiary reserve ancillary service – UP) deployed and the net charges payable to the ancillary service providers for all the regions]</li>
</ul>
Calculation of Deviation Charges
Deviation charges for general sellers (other than a run-of-river (RoR) generating station and a generating station based on municipal solid waste) will be as follows:
<a href="https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/Berc-dsm-1.png"><img loading="lazy" decoding="async" class="aligncenter wp-image-83555 size-full" src="https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/Berc-dsm-1.png" alt="" width="794" height="570" srcset="https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/Berc-dsm-1.png 794w, https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/Berc-dsm-1-300x215.png 300w, https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/Berc-dsm-1-768x551.png 768w, https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/Berc-dsm-1-650x467.png 650w, https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/Berc-dsm-1-624x448.png 624w, https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/Berc-dsm-1-600x431.png 600w" sizes="(max-width: 794px) 100vw, 794px" /></a>
Deviation charges for a RoR generating station without any linkage to grid frequency will be as follows:
<a href="https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/Berc-dsm-2.png"><img loading="lazy" decoding="async" class="aligncenter wp-image-83556 size-full" src="https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/Berc-dsm-2.png" alt="" width="819" height="292" srcset="https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/Berc-dsm-2.png 819w, https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/Berc-dsm-2-300x107.png 300w, https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/Berc-dsm-2-768x274.png 768w, https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/Berc-dsm-2-650x232.png 650w, https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/Berc-dsm-2-624x222.png 624w, https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/Berc-dsm-2-600x214.png 600w" sizes="(max-width: 819px) 100vw, 819px" /></a>
Deviation charges for a generating station based on municipal solid waste without any linkage to grid frequency will be as follows:
<a href="https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/Berc-dsm-3.png"><img loading="lazy" decoding="async" class="aligncenter wp-image-83557 size-full" src="https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/Berc-dsm-3.png" alt="" width="780" height="201" srcset="https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/Berc-dsm-3.png 780w, https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/Berc-dsm-3-300x77.png 300w, https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/Berc-dsm-3-768x198.png 768w, https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/Berc-dsm-3-650x168.png 650w, https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/Berc-dsm-3-624x161.png 624w, https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/Berc-dsm-3-600x155.png 600w" sizes="(max-width: 780px) 100vw, 780px" /></a>
A wind-solar hybrid power generator (WS seller), including such generating stations aggregated at a pooling station through a qualified coordinating agency, shall be without any linkage to grid frequency and will be as follows:
<a href="https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/Berc-dsm-5.png"><img loading="lazy" decoding="async" class="aligncenter wp-image-83563 size-full" src="https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/Berc-dsm-5.png" alt="" width="793" height="222" srcset="https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/Berc-dsm-5.png 793w, https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/Berc-dsm-5-300x84.png 300w, https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/Berc-dsm-5-768x215.png 768w, https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/Berc-dsm-5-650x182.png 650w, https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/Berc-dsm-5-624x175.png 624w, https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/Berc-dsm-5-600x168.png 600w" sizes="(max-width: 793px) 100vw, 793px" /></a>
Deviation charges for a standalone energy storage system (ESS) will be the same as applicable to a general seller (other than a RoR generating station and a generating station based on municipal solid waste).
In the charging mode, deviation through overdrawal will be treated as under injection, and through underdrawal will be treated as over injection.
The deviation charges will be settled as follows:
Deviation charges, including the computation formula of deviation for charging when a pumped storage project is a standalone ESS, will be the same as for a generating station based on solar resources.
Deviation charges, including the formula for deviation computation for a WS Seller with ESS connected at the same interconnection point, can be as follows:
<ul>
<li>As applicable to a WS seller of the respective category during the period solar or wind, or hybrid generating station is injecting power</li>
<li>As applicable to a standalone ESS when only the storage system is injecting power</li>
<li>As applicable to a standalone ESS for drawal by the storage system based on the schedule from the grid</li>
</ul>
Deviation charges for receivable/payable for the buyer will be as follows:
<a href="https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/Berc-dsm-4.png"><img loading="lazy" decoding="async" class="aligncenter wp-image-83558 size-full" src="https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/Berc-dsm-4.png" alt="" width="772" height="671" srcset="https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/Berc-dsm-4.png 772w, https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/Berc-dsm-4-300x261.png 300w, https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/Berc-dsm-4-768x668.png 768w, https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/Berc-dsm-4-650x565.png 650w, https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/Berc-dsm-4-624x542.png 624w, https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/Berc-dsm-4-600x522.png 600w" sizes="(max-width: 772px) 100vw, 772px" /></a>
Deviation charges for injecting infirm power will be as follows:
There will be no charges for injecting infirm power into the grid.
For thermal power stations, any infirm power injected into the grid from the date of first synchronization until the successful completion of the trial run will be paid at the normal rate of deviation charges. However, this payment will be capped at ₹2.86/kWh or as revised by the Central Commission.
Once the trial run is completed, any scheduled infirm power will be treated like regular generation. In such cases, deviations will be charged per the rules applicable to general or WS sellers.
There will be no charges for injecting infirm power or for any deviation of scheduled infirm power caused by over-injection from a general or WS seller if the grid frequency is above 50.05 Hz.
Charges for Startup Power and Deviations
Any drawal of startup power by a generating unit before its commercial operation date (COD) will be treated as a deviation.
The deviation charges for drawal of startup power before COD or to run auxiliaries during a project shutdown will be payable at the reference charge rate or the contract rate.
In cases of forced or partial seller outage, deviation charges will be per the reference charge rate for a maximum of eight-time blocks, or until the seller revises its schedule, whichever is earlier.
For a seller whose bids are cleared in the high price day-ahead market (HP-DAM), the reference charge rate for under-injection will be equal to the weighted average ACP of HP-DAM segments across all power exchanges for that time block.
Accounting of Charges for Deviation Pool Account 
The state load dispatch centre (SLDC) will prepare a weekly statement of deviation charges every Thursday.
A state deviation pool account will be maintained and operated by the SLDC. However, the Commission may assign this responsibility to another entity if required.
The state deviation pool account will be credited from the following sources:
<ul>
<li>Payments of deviation charges and late payment surcharges</li>
<li>Receipts from the deviation and ancillary services pool account-regional towards reactive energy exchange, DSM issued for the state by Eastern Regional Power Committee (ERPC) per the Indian Electricity Grid Code (IEGC)/Central Electricity Regulatory Commission (CERC) Deviation Settlement Mechanism Regulations.</li>
<li>Any other charges as may be notified by the Commission.</li>
</ul>
The state deviation pool account will be debited for expenses, including the cost of recovering deviation charges and any other related expenses.
The state deviation pool account will also be charged for the following:
<ul>
<li>Overdues or penal interest</li>
<li>Normal interest</li>
<li>Transfers to the Regional Deviation Pool Account</li>
<li>Payments to the Deviation and Ancillary Services Pool Account-Regional towards reactive energy exchange, DSM issued by the ERPC for the state as per IGEC/CERC DSM Regulations.</li>
<li>Any other charges as notified by the Commission.</li>
</ul>
The SLDC will maintain separate settlement accounts for interstate and intra-state deviations.
Any surplus funds in the state deviation pool account at the end of a financial year will be used to improve power system operations.
The funds can also be spent on studies and measures to enhance the reliability, security, and safety of grid operations, and capacity-building and training programmes related to system and market operations.
The SLDC will prepare programs and submit an annual plan to utilise the surplus fund before the Commission. The Commission may also invite proposals or suggestions from stakeholders before approving the use of surplus funds.
If there is a shortfall of funds in the state deviation pool account at the end of the weekly settlement cycle, the deficit will be recovered by levying an additional charge on state entities.
Deviation Accounting Procedure
The SLDC will prepare a detailed energy accounting procedure within 30 days of the notification of these regulations. This procedure must be submitted to the Commission for approval.
Before submission, the SLDC will conduct a stakeholder consultation by publishing the draft procedure on its website and seeking feedback.
The settlement of deviations for consumers connected to the intra-state transmission system, as well as those connected to the distribution network, will be carried out in line with the provisions of the open access regulations and their subsequent amendments.
Payment Schedule for Deviation Charges
State entities must pay the due amounts within 10 days of the SLDC stating the charges.
Any delay will attract a late payment surcharge of 0.04% per day.
If a state entity fails to make timely payments during the previous financial year, it will be required to open a letter of credit (LC) in favor of the SLDC. The LC must be 110% of its average weekly deviation liability from the previous year and must be opened within 15 days of the new financial year.
If a state entity fails to pay deviation charges within 10 days from the date of issue of the statement of deviation charges, the SLDC will have the right to encash the LC to recover the dues. The entity will then be required to replenish the LC amount within three days.
Reactive Energy Management
The SLDC will manage reactive energy requirements per the IEGC provisions. The settlement of the reactive energy pool account will also follow IEGC procedures.
Recently, BERC <a href="https://mercomindia.com/bihar-adds-distributed-renewable-energy-to-its-proposed-rpo-targets" target="_blank" rel="noopener">proposed</a> including a new category of distributed renewable energy in its Renewable Power Obligation for the financial year 2030.

BERC Issues Draft Deviation Settlement Mechanism Regulations

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					</table><a href="https://www.grinfra.com/" target="_blank" rel="noopener">G R Infraprojects</a> has won REC Power Development and Consultancy’s (<a href="https://recpdcl.in/" target="_blank" rel="noopener">RECPDCL</a>) transmission project to evacuate 2,500 MW of power from renewable energy projects in Rajgarh and Neemuch Special Economic Zones in Madhya Pradesh.
The tender was <a href="https://www.mercomindia.com/recpdcl-invites-bids-for-2-5-gw-renewable-energy-transmission-projects" target="_blank" rel="noopener">floated</a> in March this year.
The annual transmission charges are ₹3.67 billion (~$42.67 million). The projects must be completed within 24 months from the date of acquisition of the special purpose vehicle. The operations and maintenance period will run for 35 years.
The scope of work includes the establishment of a 2&#215;500 MVA, 400/220 kV substation at Handiya, equipped with two 125 MVAr 420 kV bus reactors. At Neemuch Power Station (PS), a new 220 kV Bus Section-II will be created, with augmentation of transformation capacity through three 500 MVA, 400/220 kV interconnecting transformers (ICTs) and the construction of four new 220 kV line bays for renewable energy interconnection.
Additionally, a new 220 kV Bus Section will be set up with a 220 kV Bus Sectionalizer, augmentation of transformation capacity through another set of three 500 MVA, 400/220 kV ICTs, and three 220 kV line bays for renewable energy interconnection.
The project also includes the installation of a 220 kV line bay for renewable energy interconnection for Purvah Green Power and a 1&#215;125 MVAr, 420 kV bus reactor at Pachora PS (400 kV Bus Section-II).
Further works include four 400 kV line bays, two at Rajgarh (PG) and two at Pachora PS, along with four 420 kV switchable line reactors (two each at Rajgarh and Pachora), and four switching equipment units for the 400 kV line reactors.
Transmission line construction includes a 400 kV double-circuit (D/C) line with associated line bays and 50 MVAr switchable line reactors on each circuit at both ends. Additional 400 kV D/C lines of similar specifications will be built with associated line bays at Pachora PS and Handiya substation, including a 400 kV D/C (Twin Moose) line at Handiya substation.
The project, titled “Transmission system for Evacuation of Power from RE Projects in Rajgarh (1500 MW) SEZ in Madhya Pradesh-Phase III and Evacuation of Power from RE Projects in Neemuch (1000 MW) SEZ in Madhya Pradesh-Phase II,” will be implemented on a build, own, operate, transfer basis.
Last December, G R Infraprojects was <a href="https://www.mercomindia.com/g-r-infraprojects-transmission-system-karnataka" target="_blank" rel="noopener">awarded</a> a contract from PFC Consulting to establish an inter-state transmission system to integrate the Bijapur Renewable Energy Zone in Karnataka.

GR Infraprojects Wins RECPDCL’s Project to Evacuate 2.5 GW Renewable Energy

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					</table>The Ministry of Heavy Industries (<a href="https://heavyindustries.gov.in/" target="_blank" rel="noopener">MHI</a>) has modified the incentives for electric three-wheelers (e-3W) under the PM Electric Drive Revolution in Innovative Vehicle Enhancement (PM E-DRIVE) program.
The incentives have been modified for two segments.
For the first segment (registered e-rickshaws and e-carts), the Ministry reduced the incentives to ₹2,500 (~$28.56)/kWh, capped at ₹12,500 (~$142.79) per vehicle for the financial year (FY) 2026, from ₹5,000 (~$57.12)/kWh, capped at ₹25,000 (~$285.59) per vehicle for FY 2025. The maximum number of such vehicles supported under the program remains at 39,034.
The highest vehicle ex-factory price to qualify for the incentives is ₹250,000 (~$2,855.87). The total incentive outlay will come up to ₹500 million (~$5.71 million).
Incentives for the second segment (e-3W registered under L5 category) have been reduced to ₹2,500 (~$28.56)/kWh, capped at ₹25,000 (~$285.59) per vehicle for those registered on the government’s Vahan portal from November 8, 2024, to March 31, 2026. The number of such vehicles supported under the program during this period has been increased to 208,263.
The earlier incentive, for vehicles registered on the portal from April 1, 2024, to November 7, 2024, was ₹5,000 (~$57.12)/kWh, capped at ₹50,000 (~$571.17) per vehicle. The number of supported vehicles during this period was 80,546.
The highest vehicle ex-factory price to qualify for the incentives is ₹500,000 (~$5,711.74). The total incentive outlay will come up to ₹8.57 billion (~$97.9 million).
MNRE added that the proposed incentive amount per kWh is subject to review per the vehicle cost reductions. The incentive outlay of the Electric Mobility Promotion Scheme-2024 will be subsumed within the PM E-DRIVE outlay.
Along with these reductions for both segments, the incentive amount can be capped at 15% of the ex-factory price of e-2W or e-3W, whichever is lower.
In July this year, MHI <a href="https://www.mercomindia.com/government-amends-pm-e-drive-program-to-focus-on-indigenization" target="_blank" rel="noopener">amended</a> the Phased Manufacturing Programme for the electric vehicle public charging stations component of PM E-DRIVE. According to the Ministry’s revised guidelines, domestic manufacturing of charger enclosures or panels, internal wiring harnesses, and IS/IEC 60309 connectors must have commenced by December 1, 2021.
Software/mobile applications for the Open Charge Point Protocol, as well as the central server, must be developed indigenously from the same date. Auxiliary power supply, DC meters, and output switchgears, such as DC contactors, relays, voltage/current isolators, and fuses, must have been domestically manufactured from June 1, 2022.

Government Modifies PM E-DRIVE Incentives for Electric Three-Wheelers

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					</table>Corporate funding for energy storage companies fell sharply in the first half (1H) of 2025 to $9.1 billion across 55 deals, according to Mercom Capital Group’s <a href="https://mercomcapital.com/product/1h-2025-funding-ma-report-energy-storage/" target="_blank" rel="noopener">1H and Q2 2025 Funding and M&amp;A Report for Energy Storage</a>.
This represents a 41% year-over-year (YoY) decline from $15.4 billion, resulting from 64 deals, in the same period of 2024.
The downturn was attributed to the uncertainty surrounding multiple policy and tariff changes in the U.S., including proposed cuts to the  Investment Tax Credit and several provisions of the Inflation Reduction Act.
Raj Prabhu, CEO at Mercom Capital Group, stated, “This uncertainty led to a slowdown in deal closures as the market adopted a &#8216;wait-and-see&#8217; approach. Once the bill was finalized, even with some unfavorable provisions, the resulting policy clarity is expected to restore investor confidence in the second half of the year.”
<a href="https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/Energy-Storage-1H-Q2-funding-1.png"><img loading="lazy" decoding="async" class="aligncenter wp-image-83162 size-full" src="https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/Energy-Storage-1H-Q2-funding-1.png" alt="Energy Storage 1H Q2 funding" width="1543" height="929" srcset="https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/Energy-Storage-1H-Q2-funding-1.png 1543w, https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/Energy-Storage-1H-Q2-funding-1-300x181.png 300w, https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/Energy-Storage-1H-Q2-funding-1-768x462.png 768w, https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/Energy-Storage-1H-Q2-funding-1-1536x925.png 1536w, https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/Energy-Storage-1H-Q2-funding-1-650x391.png 650w, https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/Energy-Storage-1H-Q2-funding-1-624x376.png 624w, https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/Energy-Storage-1H-Q2-funding-1-600x361.png 600w" sizes="(max-width: 1543px) 100vw, 1543px" /></a>
The venture capital (VC) funding for energy storage companies in 1H of 2025 totaled $1.7 billion across 36 deals, representing a 29% decrease from the $2.4 billion invested in 48 deals during the same period in 2024. Energy storage downstream companies attracted the largest share of VC funding, followed by companies in materials and components, energy storage systems, sodium-based batteries, and thermal energy storage segments.
The top five VC transactions included KoBold Metals raising $537 million, Green Flexibility securing $411 million, Base Power receiving $200 million, RayGen Resources raising $76 million, and Exowatt bringing in $70 million.
<a href="https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/energy-storage-1H-Q2-VC.png"><img loading="lazy" decoding="async" class="aligncenter wp-image-83165 size-full" src="https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/energy-storage-1H-Q2-VC.png" alt="energy storage 1H Q2 VC" width="558" height="438" srcset="https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/energy-storage-1H-Q2-VC.png 558w, https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/energy-storage-1H-Q2-VC-300x235.png 300w" sizes="(max-width: 558px) 100vw, 558px" /></a>
Announced debt and public market financing for energy storage companies reached $7.4 billion in 19 deals in 1H 2025, a 43% decline compared to $13 billion in 16 deals in 1H 2024.
Mergers and acquisitions (M&amp;A) activity in the energy storage sector also slowed, with only three corporate transactions recorded in the first half of 2025 compared to 14 in the same period last year.
However, M&amp;A activity for energy storage projects increased sharply, with 31 project-related transactions in 1H 2025, representing a 138% increase from 13 transactions in 1H 2024.
The report highlights how regulatory developments and trade-related policy shifts significantly influenced investment flows and deal activity in the energy storage market.
Prabhu noted that advanced-stage projects, those licensed, permitted, under construction, or nearing completion, were in high demand. “Even during a period of uncertainty, buyers saw opportunities,” he said. He pointed out that some projects were acquired at more favorable valuations due to market conditions.
Despite the weaker first half, Prabhu stated that energy storage fared relatively well in the final legislation, with tax credits for storage installations preserved. This contrasted with solar and wind, which saw greater adverse policy impacts. “Now that policy direction is settled, the second half should see stronger performance than in the past two to three quarters.”
Smart Grid
Corporate funding for global smart grid companies in the first half of 2025 totaled $1.4 billion across 48 deals, according to Mercom Capital Group’s <a href="https://mercomcapital.com/product/1h-2025-funding-ma-report-smart-grid/" target="_blank" rel="noopener">1H and Q2 2025 Funding and M&amp;A Report for Smart Grid</a>.
This represents a 13% decline compared to the $1.6 billion raised in 36 deals during the same period in 2024.
<a href="https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/Smart-Grid-1H-Q2-funding-1.png"><img loading="lazy" decoding="async" class="aligncenter wp-image-83166 size-full" src="https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/Smart-Grid-1H-Q2-funding-1.png" alt="Smart Grid 1H Q2 funding" width="1375" height="876" srcset="https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/Smart-Grid-1H-Q2-funding-1.png 1375w, https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/Smart-Grid-1H-Q2-funding-1-300x191.png 300w, https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/Smart-Grid-1H-Q2-funding-1-768x489.png 768w, https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/Smart-Grid-1H-Q2-funding-1-650x415.png 650w, https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/Smart-Grid-1H-Q2-funding-1-624x398.png 624w, https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/Smart-Grid-1H-Q2-funding-1-600x382.png 600w" sizes="(max-width: 1375px) 100vw, 1375px" /></a>
Substantial investments in smart charging companies supported the funding performance in 1H 2025. VC funding across all smart grid companies was $1.1 billion in 41 deals, an 8% YoY decrease from the $1.2 billion raised in 29 deals.
Prabhu said the smart grid sector managed to avoid a steeper decline seen in other clean energy segments. “Smart grid funding has been driven largely by investments in smart charging technologies, a trend that continued this quarter,” he explained.
The top five VC funding deals in the smart grid segment during 1H 2025 were led by Believ with $410 million, followed by Connected Kerb with $81 million, Smart Wires with $65 million, Utilidata with $60 million, and GreenWay with $54 million.
<a href="https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/Smart-grid-1H-Q2-VC.png"><img loading="lazy" decoding="async" class="aligncenter wp-image-83168 size-full" src="https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/Smart-grid-1H-Q2-VC.png" alt="Smart grid 1H Q2 VC" width="591" height="422" srcset="https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/Smart-grid-1H-Q2-VC.png 591w, https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/Smart-grid-1H-Q2-VC-300x214.png 300w" sizes="(max-width: 591px) 100vw, 591px" /></a>
“Funding flowed into grid and infrastructure technologies, which are essential to handle the intermittency of growing solar and wind installations. The critical need for grid optimization technologies helped sustain investors in the smart grid sector,” Prabhu said.
Debt and public market financing for smart grid technology companies in 1H 2025 totaled $300 million through seven deals, a slight decrease from the $321 million raised in the same number of deals during 1H 2024.
The M&amp;A activity in the smart grid sector also saw changes compared to the previous year. In 1H 2025, there were four smart grid M&amp;A transactions, with one transaction having disclosed financial details. In comparison, 1H 2024 recorded three M&amp;A deals, all of which were undisclosed in value.
To learn more about the energy storage report, visit: <a href="https://mercomcapital.com/product/1h-2025-funding-ma-report-energy-storage/" target="_blank" rel="noopener">https://mercomcapital.com/product/1h-2025-funding-ma-report-energy-storage/</a>
To learn more about the smart grid report, visit: <a href="https://mercomcapital.com/product/1h-2025-funding-ma-report-smart-grid/" target="_blank" rel="noopener">https://mercomcapital.com/product/1h-2025-funding-ma-report-smart-grid/</a>

Energy Storage Funding Declines in 1H 2025

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					</table><a href="https://www.pfcclindia.com/" target="_blank" rel="noopener">PFC Consulting</a> has issued a request for proposal (RfP) to establish an intrastate transmission system to enhance power evacuation capacity by 1.5 to 2 GW from the renewable energy-rich areas of Wagdari, Akkalkot, and South Solapur in Maharashtra.
Bids must be submitted by October 13, 2025. The bids will be opened on the same day.
Bidders must submit a document fee of ₹500,000 (~$5,813.95) plus 18% GST, and a bid bond of ₹140.8 million (~$1.64 million). The successful bidder must submit a performance bank guarantee of ₹352 million (~$4.09 million).
The tender will be implemented on a build, own, operate, and transfer basis, with the selected bidder acquiring 100% equity in Wagdari Transmission, a special purpose vehicle set up for the project.
The project, located in Wagdari, will connect to 765 kV Pune (East), 400 kV Solapur Pooling Station (Power Grid), the proposed 220 kV AIS Wagdari, and the existing 220 kV AIS Narangwadi.
The scope of work includes the construction of the AIS Wagdari substation with three 500 MVA, 400/220 kV, one 125 MVAr bus reactor at 400 kV, and associated line bays.
It also covers 400 kV double circuit lines to 765 kV Pune (East) and 400 kV Solapur Pooling Station, 220 kV lines to AIS Wagdari and AIS Narangwadi, and renewable integration bays for solar generators.
Successful bidders will be responsible for the survey, design, engineering, procurement and construction, commissioning, operation, and maintenance (O&amp;M) clearances, and land acquisition.
The project must be commissioned within 24 months, with an O&amp;M period until transfer of assets to Maharashtra State Transmission Utility or the state government after 35 years from the commercial operation date.
Bidders must have project experience in the last five years with aggregate capital expenditure or payments of at least ₹7.04 billion (~$81.86 million), with each project valued at a minimum of ₹1.40 billion (~$16.28 million).
Bidders must have a net worth of at least ₹2.81 billion (~$32.67 million) in any of the last three financial years.
Recently, PFC Consulting <a href="https://www.mercomindia.com/pfc-consulting-invites-bids-to-evacuate-7-gw-of-solar-power-from-maharashtra" target="_blank" rel="noopener">invited</a> bids to augment the interstate transmission system to evacuate 7 GW of solar power from Dharashiv, Beed district, Maharashtra.
In May this year, PFC Consulting <a href="https://www.mercomindia.com/pfc-consulting-invites-bids-to-evacuate-3-gw-renewable-energy-from-kurnool" target="_blank" rel="noopener">invited</a> bids to establish an interstate transmission system to evacuate 3 GW from Kurnool IV Renewable Energy Zone Phase II, Andhra Pradesh.

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