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POWERGRID Bags Transmission Project to Integrate Renewable Energy in Karnataka

Supply Chain Shortages and Inflation Delay Power Transmission Projects

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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.

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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.

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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) 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. 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 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 waivers 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 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 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.

PFC Consulting Invites Bids to Evacuate 2 GW of Renewable Energy in Maharashtra

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					</table>The Ministry of New and Renewable Energy (<a href="https://mnre.gov.in/" target="_blank" rel="noopener">MNRE</a>) has issued revised program guidelines for the implementation of pilot projects using green hydrogen and its derivatives in the residential, commercial, and decentralized sectors that were previously not mentioned in earlier programs.
The revised guidelines focus on deploying green hydrogen in off-grid, localized, community-based applications. Decentralized production models using rooftop solar, small or micro hydropower, floating solar, biomass, and wastewater will be key features of the pilot projects.
These systems will also support uses such as cooking, heating, off-grid electricity generation, and off-road mobility, including construction and mining applications.
In the shipping sector, the program will support pilot projects that involve green hydrogen or its derivatives, such as green ammonia and methanol.
The projects will be implemented by the scheme implementing agencies (SIAs) that are designated for specific sectors under this initiative.
The program is <a href="https://www.mercomindia.com/cabinet-approves-%E2%82%B9197-billion-hydrogen-mission" target="_blank" rel="noopener">part</a> of the larger National Green Hydrogen Mission (NGHM).
Budget and Structure
The revised guidelines have a total budgetary outlay of ₹2 billion (~$23.26 million) until the end of the financial year 2026. This funding falls under Mode 2A of the NGHM, which pertains to pilot projects in sectors other than steel and transport.
The program is split into two main parts, each with an allocation of ₹1 billion (~$11.63 million). Part A supports biomass and other technology-based pilot projects, with a cap of ₹250 million (~$2.85 million)/project. Part B is intended for startups proposing innovative green hydrogen production or utilization technologies, with a cap of ₹50 million (~$581,395)/project.
Eligibility
Eligible applicants include central and state government entities, public sector undertakings, private sector companies, and ports and shipping firms. Consortiums involving multiple stakeholders, such as technology providers, port authorities, and project developers, are also allowed.
Preference will be given to projects with clear replication potential and substantial long-term impact. All pilot projects must have a minimum operational life of 10 years. The ownership of assets created under the program must not be transferred during this period without MNRE’s prior approval.
Implementation Methodology and Approval
SIAs will manage the selection and monitoring processes. Project selection will be carried out through a transparent request for selection mechanism. Proposals submitted will be assessed based on predefined technical and financial criteria, including innovation potential, feasibility, and alignment with India&#8217;s emissions commitments.
A project appraisal committee constituted by MNRE will evaluate and recommend projects for final approval. Upon selection, project proponents will sign implementation agreements with an SIA, detailing responsibilities, fund disbursement schedules, reporting requirements, and monitoring mechanisms.
All selected projects must be commissioned within 24 months from the agreement signing date. MNRE may allow extensions in justified cases, but failure to commission the projects within 30 months may result in cancellation of support and recovery of funds. Once operational, the projects are expected to run for at least 10 years and maintain detailed operational data throughout this period.
The data will be critical for assessing technical feasibility, learning from the pilot phase, and designing subsequent large-scale deployments. In the event of non-performance or deviation from agreed deliverables, financial support may be curtailed, and recovery of disbursed funds could be initiated.
Financial Support and Disbursement 
Each project is eligible for financial assistance of up to ₹500 million (~$5.81 million), based on its requirements and evaluation results. The disbursement of funds will take place in three tranches, linked to project milestones.
The program outlines a three-stage financial disbursement mechanism. The first tranche of 20% of the Central Financial Assistance (CFA) will be released upon the letter of award issuance. The second tranche, comprising 70% of the CFA, will be disbursed based on milestone achievements. The last 10% will be released after successful project completion.
For private entities, CFA will cover up to 80% of equipment costs, while for government organizations, it will cover 100% of equipment costs. The CFA granted will be limited to the lower of the applicable ceilings under Part A and Part B.
Project proponents are required to contribute at least 10% of the total project cost as promoters&#8217; equity. They must bear any escalation in project cost beyond the approved budget. In the event of delays or failure to meet predefined milestones, MNRE can reduce or cancel the sanctioned financial support.
Recently, MNRE <a href="https://www.mercomindia.com/mnre-invites-second-round-of-rd-proposals-under-green-hydrogen-mission" target="_blank" rel="noopener">issued</a> the second call for Research and Development proposals under the National Green Hydrogen Mission.

MNRE Issues Guidelines for Green Hydrogen Use in Residential Sector

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					</table>Integrated power company, <a href="https://www.tatapower.com/" target="_blank" rel="noopener">Tata Power</a>, reported a profit after tax of ₹12.62 billion (~$144 million) in the first quarter (Q1) of the financial year (FY) 2026, a 6% year-over-year (YoY) increase from ₹11.89 billion (~$135.67 million).
The company reported revenue of ₹174.64 billion (~$1.99 billion), up by 4% from ₹168 billion (~$1.91 billion) in the same quarter last year.
Praveer Sinha, CEO and MD at Tata Power, said in the earnings call that the company witnessed a quarter in which power consumption declined by 1.3% after five to six years. “It was due to the early onset of the monsoon, which came in mid-May. With rains moving away from the central and western parts of India and northern India, we will have high temperatures along with humidity, which will lead to higher power demand in the latter part of August and September.”
The revenue growth can be attributed to a 52% YoY increase in revenue from renewables to ₹36.26 billion (~$413.74 million) from ₹23.83 billion (~$271.9 million) in the previous year.
The renewable business earned a profit of ₹5.31 billion (~$60.5 million), a 95% YoY increase.
Tata Power commissioned 94 MW of renewable energy capacity during the quarter, bringing the total operational renewable capacity to 5.6 GW.
Revenue from thermal and other conventional sources also fell by 7% to ₹48.44 billion (~$552.72 million) from ₹52.16 billion (~$595.17 million) last year.
The company said its coal-based power generation segment is underperforming due to lower coal prices in Indonesia.
Revenue from the rooftop solar segment doubled YoY to ₹8.23 billion (~$93.9 million) during the quarter.
The company’s earnings before interest, taxes, depreciation, and amortization (EBITDA) grew 17% YoY to ₹39.3 billion (~$448.43 million) from ₹33.5 billion (~$382.25 million).
Its earnings per share (EPS) came in at ₹3.31 (~$0.037) against an EPS of ₹3.03 (~$0.034) in Q1 FY 2025.
The company achieved over 200,000 rooftop solar installations and a cumulative capacity exceeding 3.4 GW. It installed over 45,500 rooftop solar systems with a total capacity of 270 MW in the quarter, contributing to a profit of ₹900 million (~$10.26 million), a 260% YoY increase.
In Q1, it commissioned 270 MW of solar projects, a 143% increase from 111 MW in the same period last year.
Tata Power said that it commissioned 652 MW of renewable energy engineering, procurement, and construction projects in Q1, nearly double the quantity that was commissioned last year.
Sinha said that of the 652 MW, 560 MW was for third-party projects, and 92 MW was for utility-scale projects. “The third-party projects will be completed in Q2 and Q3. Thereafter, we expect nearly 1,600 MW of our utility-scale projects to come up in the next three quarters,” added Sinha.
Tata Power’s manufacturing subsidiary, TP Solar, reported a profit of ₹1 billion (~$11.41 million) and a revenue of ₹16.13 billion (~$184.05 million) in Q1 FY 2026.
The company manufactured 949 MW of solar modules and 904 MW of solar cells during the quarter. During the same period, it sold 107 MW of modules and 54 MW of cells to third parties, with an order value of ₹13.03 billion (~$148.67 million).
Tata Power said that it is using a very limited portion of imported cells and is largely using its own solar modules.
Regarding not being listed in the Approved List of Models and Manufacturers, Sinha said that Tata Power will be listed once the plant inspection is completed.
The company is manufacturing Mono PERC modules mainly but will soon foray into TOPCon.
In Q1 FY 2026, Tata Power commissioned 652 MW of renewable projects, including 94 MW of its portfolio and 560 MW through third-party engineering, procurement, and construction contracts.
Its total utility-scale operational capacity now stands at 5.6 GW, comprising 4.6 GW of solar and 1 GW of wind capacity. The company plans to add 1.6 GW of capacity over the next three quarters of FY 2026.
Business Highlights
In Q1 FY 2026, Tata Power held a portfolio of nearly 26.03 GW of power projects under operation and construction. This portfolio included an estimated 17.2 GW of renewable energy projects and with 10.2 GW of projects under construction. Renewable project capacity included 4,085 MW of operational solar projects.
The company also has nearly 4.9 GW of integrated cell and module manufacturing capacity.
It collaborated with Tata Motors to set up a 131 MW wind-solar hybrid project for its manufacturing units across Maharashtra and Gujarat.
Tata Power secured a letter of award for an 88 MW round-the-clock renewable project under SJVN’s Firm and Dispatchable Renewable Energy (FDRE)-3 program.
It also signed a power purchase agreement for 200 MW FDRE with NTPC.
The company is planning to expand its electricity distribution license in Maharashtra, targeting key growth areas including parts of Thane, Navi Mumbai, Panvel, Pune, Nashik, and Chhatrapati Sambhaji Nagar.
In Q4 FY 2025, Tata Power <a href="https://mercomindia.com/tata-powers-hits-record-revenue-of-%E2%82%B9645-04-billion-in-fy-2025-on-higher-sales#:~:text=Tata%20Power%2C%20an%20integrated%20power,10.46%20billion%20(~%24122.3%20million)." target="_blank" rel="noopener">reported</a> a profit of ₹13.06 billion (~$152 million), a 25% YoY growth from ₹10.46 billion (~$122.3 million). Its quarterly revenue stood at ₹172.38 billion (~$2 billion), growing 7% from the same period of the previous year.

Renewables Growth Drives Tata Power’s Revenue, Profit Up in Q1 FY 2026

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					</table>The <a href="https://www.sci.gov.in/" target="_blank" rel="noopener">Supreme Court of India</a> has directed the states to clear the pending dues of approximately ₹1.74 trillion (~$19.72 billion) owed to distribution companies (DISCOMs) within four years. New dues created after April 1, 2024, must be liquidated within three years.
The Court said the practice of creating dues, termed as ‘regulatory assets’ by electricity regulatory commissions, cannot be allowed to continue unchecked. Such regulatory assets, which represent unrecovered costs of distribution licensees deferred to future tariff periods, must only be created in exceptional circumstances and must be liquidated within a specified time.
The judgment enforces Rule 23 of the Electricity (Amendment) Rules 2024, which limits regulatory assets to no more than 3% of the approved annual revenue requirement.
The Court directed the Appellate Tribunal for Electricity (APTEL) to register a suo motu case under Section 121 of the Electricity Act to monitor the liquidation of regulatory assets nationwide, and issue binding orders and directions to ensure compliance by state commissions.
Background 
The case emerged from a long-standing dispute between Delhi’s DISCOMs and the Delhi Electricity Regulatory Commission (DERC) over the issue of under-recovery of revenue due to delayed or insufficient tariff revisions.
The petitioners, BSES Rajdhani Power, BSES Yamuna Power, and Tata Power Delhi Distribution, argued that over multiple years, DERC had failed to allow cost-reflective tariffs despite the audited accounts and annual revenue requirement filings submitted by them. As a result, a large volume of revenue shortfall was carried forward each year in the form of regulatory assets.
According to the petitioners, these regulatory assets had grown to over ₹272 billion (~$3.09 billion) by the financial year 2024 and continued to accumulate carrying costs due to the time value of money. They claimed that such deferment was unsustainable and contrary to the provisions of the Electricity Act, 2003, which mandates regular and transparent tariff determination. The petitioner also relied on past judgments of APTEL, which had ruled that the DISCOMs were entitled to cost-reflective tariffs and recovery of carrying costs.
The respondents included DERC, the Delhi Government, and the Union Ministry of Power. DERC countered the claims by asserting that the regulatory assets had been created at the request of the DISCOMs themselves in the early years following the privatization of distribution. It argued that tariff increases and surcharges had already been granted periodically and that the DISCOMs were exaggerating the impact of under-recovery.
The Delhi government submitted that the DISCOMs had received significant financial assistance through loans and subsidies, and that any claims regarding revenue gaps had to be assessed within the broader regulatory framework. It opposed any attempt to shift the burden of past inefficiencies onto consumers.
The Ministry of Power highlighted the importance of following Rule 23 of the Electricity Rules, 2024, which permits regulatory assets only in extraordinary situations such as natural calamities or force majeure events and mandates liquidation within five years.
Given the broader implications of the dispute, the Court had earlier directed all state electricity regulators and state governments to file affidavits detailing the status of regulatory assets across the country. This revealed significant regional disparities, with states like Tamil Nadu, Kerala, Chhattisgarh, and Rajasthan reporting dues of over ₹1.46 trillion (~$16.64 billion). In contrast, others like Assam, Odisha, and Uttar Pradesh had no such liabilities. These disclosures underscored the systemic nature of the problem and the need for judicial clarity.
Supreme Court’s Analysis 
The Supreme Court emphasized that Sections 61 and 62 of the Electricity Act place a clear obligation on the regulators to determine tariffs that are cost-reflective and provide a reasonable return to distribution licensees while ensuring consumer interest.
It rejected the argument that political or financial constraints justify prolonged deferment of revenue recovery. It held that the regulatory commissions cannot avoid their statutory duty by deferring legitimate costs under the guise of consumer protection. It also noted that the creation of regulatory assets without timely liquidation leads to accumulated carrying costs, which ultimately burdens consumers more heavily in the long run and destabilizes the financial health of DISCOMs.
On the issue of consumer interest, the Supreme Court observed that true consumer protection lies in ensuring uninterrupted and quality supply of electricity at fair tariffs, not in artificially suppressing tariffs while endangering the viability of the distribution system. It called for a balance between the right of consumers to affordable power and the right of DISCOMs to recover legitimate costs efficiently.
The Court further examined Rule 23 of the Electricity (Amendment) Rules, 2024, which allows for the creation of regulatory assets only in exceptional circumstances such as natural disasters, war, or other force majeure events. It noted that none of the conditions in Rule 23 had been satisfied in the Delhi case, and that the regulatory asset mechanism had been abused as a routine tool to defer tariff increases.
The apex court also addressed the role of state governments in subsidizing electricity tariffs. It held that any subsidy must be provided transparently, in advance, and through budgetary allocations under Section 65 of the Electricity Act. Regulatory commissions cannot reduce tariffs artificially in anticipation of state subsidies unless those amounts are actually received.
The court had recently ruled that the regulatory commissions must be <a href="https://www.mercomindia.com/unilateral-termination-ppas-against-public-interest-supreme-court">guided</a> by the public interest when approving tariffs for power purchases.
Subscribe to Mercom’s real-time <a href="https://www.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.

Supreme Court Orders States to Pay ₹1.74 Trillion Dues to DISCOMs in Four Years

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					</table>The Maharashtra Electricity Regulatory Commission (<a href="https://merc.gov.in/" target="_blank" rel="noopener">MERC</a>) has released the Draft Deviation Settlement Mechanism (DSM) and Related Matters Regulations, 2025, proposing significant changes to deviation accounting, scheduling, despatch, and financial settlements in the state’s power sector.
Applicability
These regulations will apply to all generating stations connected to the intrastate transmission and distribution system, including conventional power generators, solar and wind generating stations, bagasse/biomass-based cogeneration plants, captive generators, buyers, including distribution licensees and open access consumers, and all entities engaged in wheeling, banking, or self-consumption of electricity.
The regulations extend to all transactions using short, medium, or long-term open access and those involving power exchanges. Generating stations whose scheduling is managed by the state load despatch centre (SLDC), as well as users of the state grid engaging in cross-border or inter/intra-state transactions that affect the Maharashtra grid, are also covered.
Wind and solar generators will remain under the existing MERC (Forecasting, Scheduling and Deviation Settlement for Solar and Wind Generation) Regulations, 2018, unless amended.
Deviation Computation
Deviation will be computed as the difference between actual injection or drawal and the scheduled injection or drawal in MWh for each 15-minute time block. The computation is applicable at the generating station level, the pooling station level (for renewable energy generators), and the buyer level.
The computation will involve the difference between the actual injection or withdrawal and the. The formula for general sellers is Deviation (MWh) = Actual Injection – Scheduled Generation. The deviation percentage will be calculated as 100 × (Actual – Scheduled)/Scheduled.
The same formula applies for buyers, replacing injection with drawal. In case of intra-state hydroelectric projects, deviation will be computed based on actual generation instead of scheduled generation, unless grid constraints arise.
Special energy meter readings must support deviation data in accordance with Central Electricity Authority (CEA) norms. The SLDC will be responsible for providing weekly deviation statements based on meter reading instrument data.
Errors in scheduling caused by transmission constraints or force majeure events may be revised accordingly. The deviation must also adhere to the technical limits of the generator to maintain grid stability.
Category-Wise Deviation Charges
Deviation charges differ based on the type of generator or consumer. They are frequency-linked for conventional power generators and buyers. For instance, if the grid frequency drops below 49.85 Hz, the deviation charge will be 150% of the normal rate.
Between 49.85 Hz and 50.05 Hz, the charges will follow a DSM rate table specified by the Commission. When the frequency exceeds 50.05 Hz, the rate will become zero or negative to discourage over-injection.
Renewable energy generators (wind and solar) with a capacity greater than 1 MW will be allowed a ±10% deviation band. No charges will be applied within this band. Deviations beyond 10% but less than or equal to 15% will be penalized at ₹0.5 (~$0.0057)/kWh, between 15% and 20% at ₹1 (~$0.011)/kWh, and above 20% at ₹1.5 (~$0.017)/kWh.
Deviations will be settled at the power purchase agreement rate. Captive renewable energy generators that consume their own generated electricity will be exempted from deviation charges.
Pooling stations for renewable energy will be treated as a single entity. Deviations at this level will be computed collectively, and costs will be allocated proportionally to generators based on their contribution to the deviation. Standalone energy storage systems will be treated like general sellers. In charging mode, overdrawal will be considered under-injection and underdrawal as over-injection.
For buyers, three volume limit bands are proposed, based on deviation severity and peak demand. If the grid frequency falls below 49.90 Hz, charges can go up to 200% of the normal rate. If the frequency exceeds 50.10 Hz, charges will reduce to zero or 10% of the normal rate.
Infirm power injected before the completion of the trial run will be capped at ₹2.86 (~$0.033)/kWh. After a successful trial run, charges will be per the general seller category. Start-up power will be billed at the reference rate, the weighted average clearing price (ACP), or the contract rate, whichever is applicable.
Normal Rate for Deviations
The normal rate for deviation charges in a time block is determined as the highest among three calculated values:
<ul>
<li>Weighted average ACP (in paise/kWh) of the integrated day-ahead market (I-DAM) segment across all power exchanges</li>
<li>Weighted average ACP of the real-time market (RTM) segments of all power exchanges</li>
<li>An aggregate value derived by summing one-third of the weighted average ACP from I-DAM, one-third from RTM, and one-third of the ancillary service charges</li>
</ul>
Ancillary service charges will be calculated based on the total quantum of secondary reserve ancillary services and tertiary reserve ancillary services deployed and the net charges payable to the ancillary service providers.
Deviation Charges
<a href="https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/MERC-DSM-image-1.png"><img loading="lazy" decoding="async" class="aligncenter wp-image-82861 size-full" src="https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/MERC-DSM-image-1.png" alt="MERC DSM 1" width="809" height="621" srcset="https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/MERC-DSM-image-1.png 809w, https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/MERC-DSM-image-1-300x230.png 300w, https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/MERC-DSM-image-1-768x590.png 768w, https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/MERC-DSM-image-1-650x499.png 650w, https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/MERC-DSM-image-1-624x479.png 624w, https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/MERC-DSM-image-1-600x461.png 600w" sizes="(max-width: 809px) 100vw, 809px" /></a>
<a href="https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/MERC-DSM-image-2.png"><img loading="lazy" decoding="async" class="aligncenter wp-image-82862 size-full" src="https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/MERC-DSM-image-2.png" alt="MERC DSM 2" width="819" height="292" srcset="https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/MERC-DSM-image-2.png 819w, https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/MERC-DSM-image-2-300x107.png 300w, https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/MERC-DSM-image-2-768x274.png 768w, https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/MERC-DSM-image-2-650x232.png 650w, https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/MERC-DSM-image-2-624x222.png 624w, https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/MERC-DSM-image-2-600x214.png 600w" sizes="(max-width: 819px) 100vw, 819px" /></a>
<a href="https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/MERC-DSM-image-3.png"><img loading="lazy" decoding="async" class="aligncenter wp-image-82863 size-full" src="https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/MERC-DSM-image-3.png" alt="MERC DSM 3" width="772" height="698" srcset="https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/MERC-DSM-image-3.png 772w, https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/MERC-DSM-image-3-300x271.png 300w, https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/MERC-DSM-image-3-768x694.png 768w, https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/MERC-DSM-image-3-650x588.png 650w, https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/MERC-DSM-image-3-624x564.png 624w, https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/MERC-DSM-image-3-600x542.png 600w" sizes="(max-width: 772px) 100vw, 772px" /></a>
Scheduling and Despatch Framework
Scheduling will be conducted in 96 time blocks per day (15 minutes each). The SLDC can revise the block size via notification. The scheduling framework must comply with the MERC State Grid Code 2020 and the Indian Electricity Grid Code.
Renewable energy generators will follow the 2018 DSM regulations applicable to wind and solar generation.
Day-ahead and intraday schedules will be allowed under the regulations. Revisions will be permitted with the following conditions: conventional generators must provide two hours of prior notice, while renewable energy generators will be allowed for up to 16 schedule revisions per day.
The SLDC will make real-time despatch decisions based on merit order despatch, technical feasibility, congestion, and economic efficiency.
It will have curtailment powers in emergencies, congestion, or voltage and frequency deviation scenarios. All curtailments must be logged, and weekly reports on SLDC interventions must be published, along with time-block-wise settlement details based on energy charge rates.
DSM Charges Settlement
All deviation charges will be settled through a State Deviation Pool Account maintained by SLDC. The deviation settlement will be carried out weekly, and payments are based on the deviation volume and applicable rate.
State energy accounts will be prepared monthly by the SLDC, covering injection, drawal, and reactive energy charges. Distribution licensees must separately bill partial open-access consumers. These accounts will be subject to a third-party audit annually.
The regulations introduced the concept of a virtual state entity as a counterparty for SLDC’s real-time interventions. When real-time changes are made, the revised schedule will be assigned to the generator directly and not to the original beneficiary.
Payments to and from the virtual state entity will be routed through the Deviation Pool Account and settled at the prevailing energy charge rate.
All deviation-related dues must be settled within 10 days of the receipt of SLDC’s deviation statement. A late payment interest of 0.05% per day will be applicable if payment is not made within 12 days.
The SLDC must disburse receivables within two working days after receiving funds into the pool account. In case of underpayment, SLDC can deduct the due amount from ongoing transactions or invoke bank guarantees.
Financial Provisions and Security Mechanisms
The State Deviation Pool Account will be utilized for settling deviation payments, reactive energy compensation, and funding grid reliability projects, system studies, and capacity building exercises. Any shortfall in the pool account will be recovered proportionally from state entities through supplementary bills.
A letter of credit (LC) is mandatory for entities in default and must be equivalent to 110% of their average weekly liability. If an entity’s weekly deviation exceeds 50% of its historical average, the LC value will be revised upwards.
The SLDC can also demand a bank guarantee amounting to two weeks of deviation liability from entities with prior defaults. The Maharashtra SLDC (MSLDC) fees and charges for managing DSM will be paid in advance by state entities.
Existing fees under the 2019 DSM Regulations will remain applicable until a new fee structure is finalized. The DSM Pool Account will undergo an annual audit by an independent chartered accountant firm to ensure transparency and compliance.
In 2021, MERC <a href="https://www.mercomindia.com/dsm-implementation-maharashtra" target="_blank" rel="noopener">passed</a> an order to resolve multiple issues relating to the commercial implementation of the Deviation Settlement MDSM Regulations.
Subscribe to Mercom’s real-time <a href="https://www.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.

Maharashtra Issues Draft Deviation Settlement Mechanism Regulations

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					</table>Renewable energy is set to achieve a historic milestone by overtaking coal-fired generation either in 2025 or by 2026 at the latest, according to the International Energy Agency’s (<a href="https://www.iea.org/" target="_blank" rel="noopener">IEA</a>) Electricity Mid-Year Update 2025.
Solar and wind power are leading this transformation, together expected to meet over 90% of the net increase in global electricity demand in 2025.
Combined output from these two technologies exceeded 4,000 TWh in 2024, is projected to surpass 5,000 TWh in 2025 and approach 6,000 TWh by 2026. Their share of total electricity generation is expected to rise from 15% in 2024 to 17% in 2025 and almost 20% in 2026, compared with just 4% a decade earlier.
Hydropower, which remains the largest single renewable source with a global share of 14 %, will likely remain stable in 2025 before growing by more than 2% in 2026, assuming normal rainfall patterns.
Coal-fired generation, after expanding by 1.3 % in 2024, is expected to decline slightly in 2025 as growth in India, the U.S., and parts of Asia is outweighed by reductions in China and Europe. The global decline will accelerate in 2026 to about 1.3 % as renewable capacity growth continues and coal-to-gas switching increases.
Gas-fired generation is expected to increase by 1.3% in 2025, driven by Middle Eastern oil-to-gas transitions and continued growth in Asia, before rising by the same rate in 2026.
Nuclear generation is on track to reach a record high in 2025 due to new reactor startups in China, India, Korea, and other countries, plant restarts in Japan, and sustained strong output from the U.S. and France. Nuclear output is projected to grow by about 2 % annually, reaching close to 3,000 TWh in 2026.
<img loading="lazy" decoding="async" class="aligncenter wp-image-82832 size-full" src="https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/IEA-new.png" alt="IEA new" width="737" height="357" srcset="https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/IEA-new.png 737w, https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/IEA-new-300x145.png 300w, https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/IEA-new-650x315.png 650w, https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/IEA-new-624x302.png 624w, https://mercomindia.s3.ap-south-1.amazonaws.com/wp-content/uploads/2025/08/IEA-new-600x291.png 600w" sizes="(max-width: 737px) 100vw, 737px" />
Electricity Demand
The IEA forecasts global electricity consumption to increase by 3.3% in 2025 and 3.7% in 2026, moderating from the exceptionally high 4.4% recorded in 2024 but still among the fastest rates seen in the past decade.
This expansion is occurring despite downgraded global GDP growth expectations, with demand driven by rising industrial activity, continued electrification of transport and heating, the expansion of air conditioning in response to recurring heatwaves, and the rapid growth of electricity-intensive data centers. By 2026, electricity demand will grow more than twice as fast as total energy demand, pushing global consumption above 29,000 TWh.
China remains the single largest driver of global electricity growth. After surging by 7% in 2024, demand in China is expected to rise by 5% in 2025, a slowdown linked to weaker industrial development and the impact of tariffs on exports. Nevertheless, the country will account for around half of the world’s total increase in electricity use this year. The growth rate is projected to accelerate to 5.7 % in 2026 as industrial activity recovers.
India follows a similar pattern, with <a href="https://www.mercomindia.com/iea-global-electricity-consumption-grow-annually-4/" target="_blank" rel="noopener">demand</a> growth slowing to 4% in 2025 from 6% the previous year due to a cooler summer and subdued industrial activity, before rebounding to 6.6% in 2026.
In the U.S., electricity consumption is projected to expand by 2.3% in 2025 and 2.2% in 2026, supported by new high-tech manufacturing facilities, continued electrification, and the rapid scaling of data center capacity, which consumed around 180 TWh in 2024 and is projected to rise sharply in the coming years.
The EU is still in a phase of gradual recovery, with demand expected to grow by 1.1% in 2025 and 1.5% in 2026, following a rebound of 1.6% in 2024 after two years of contraction.
Global investments in the energy sector are set to <a href="https://www.mercomindia.com/global-investment-energy-sector-3-3-trillion-2025/" target="_blank" rel="noopener">reach</a> a record $3.3 trillion in 2025, a 2% increase from 2024. Approximately $2.2 trillion is being invested collectively in renewables, nuclear energy, grids, storage, low-emission fuels, efficiency, and electrification. This investment is twice the $1.1 trillion allocated to oil, natural gas, and coal.
Prices and Electricity System Security
Electricity prices have shown sharply diverging regional trends in 2025. Wholesale prices in the European Union and the U.S. rose by between 30 and 40 % in the first half of the year due to higher natural gas prices, lower wind and hydropower output, and increased reliance on fossil-fired generation.
By contrast, India and Australia experienced price declines of between 5 and 15%, supported by lower fuel costs, new capacity additions, and strong seasonal renewable generation.
Negative wholesale prices, a symptom of high renewable penetration and inflexible demand, have become more frequent in European markets such as Germany, the Netherlands, and Spain, where they accounted for 8 to 9% of total hours in the first half of 2025, up from 4 to 5% the year before.
The IEA warns that recent large-scale blackouts underline the need for greater investment in electricity system security. In February 2025, a transmission failure left 99% of Chile without power for 17 hours, while in April, a cascade of events caused a blackout across Spain and Portugal, affecting tens of millions of people for more than 10 hours.
As electrification spreads across industries, transport, and heating, ensuring a reliable supply will require not only expanding generation capacity but also strengthening grid infrastructure, enhancing operational flexibility, and updating regulatory frameworks.
Carbon Emissions
The shift toward low-emission sources is helping to curb carbon dioxide emissions from electricity generation. After rising by 1.2% in 2024, emissions are expected to plateau in 2025 and decline slightly in 2026. This is despite continued global temperature records and associated increases in cooling demand.
The carbon intensity of global electricity generation is projected to fall from 445 grams of CO₂/kWh in 2024 to 415 grams by 2026, a reduction of nearly 7% in just two years. The European Union is expected to see the steepest drop, from 175 grams to 140 grams/kWh, while China is projected to achieve a reduction from 565 grams to 505 grams over the same period.

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