Category: Uncategorized

India’s renewable energy (RE) sector marked a historic milestone in fiscal 2025, with a record capacity addition of 28.7 GW. Solar power led the charge with 23.8 GW, reflecting a robust 59% growth over fiscal 2024, while wind contributed 4.1 GW, up 28% on-year. The remaining capacity came from biomass, waste-to-energy, and small hydro projects.

By March 2025, India’s cumulative solar and wind capacity had reached 156 GW, with a pipeline of 166 GW poised for development. The progress underscores India’s commitment to clean energy. That said, significant hurdles remain, which could hamper the nation’s ability to sustain the momentum and meet its 2030 targets.

Over fiscals 2024 and 2025, India tendered 97.6 GW of solar and wind capacity through competitive bidding, with 48.5 GW in fiscal 2024 and 49.1 GW in fiscal 2025. Of this, 45.2 GW and 43 GW were allocated, respectively. However, the composition of tenders shifted notably.

Pure solar allocations dropped from 27 GW in fiscal 2024 to 16.8 GW in fiscal 2025, and pure wind allocations fell from 2.3 GW to 0.8 GW. This decline reflects the growing demand for hybrid configurations, which promise a higher generation and firmer supply. Hybrid capacity allocation surged 2.5x to 15.8 GW in fiscal 2025 from 6.5 GW in fiscal 2024.

Figure: Capacity allocation and tariff discovered through competitive bidding process

Source: Crisil-Bridge To IndiaNote: (i) Tendered capacity allocations are based on results announced in a financial year (ii) Hybrids include combination of solar and wind (iii) Only utility scale tenders with capacity equal to or greater than 200 MW are considered and agriculture-based solar tenders are excluded.

Tariff trends reveal mixed dynamics. Solar tariffs remained steady at Rs 2.62/kWh, while wind tariffs rose 10% to Rs 3.79/kWh from Rs 3.44/kWh because of complexities in execution. Hybrid tariffs, however, fell 3% to Rs 3.47/kWh from Rs 3.58/kWh, signalling improving economics.

Subscription rates highlight further sectoral disparities: solar tenders saw 178% oversubscription, hybrids 128%, but wind lagged at 69%, hampered by installation and commissioning challenges.

That said, RE projects paired with energy storage are gaining momentum, with allocations of 8.7 GW in fiscal 2024 and 5.2 GW in fiscal 2025. Solar projects with storage, primarily for peak power supply, saw a dramatic rise from 600 MW in fiscal 2024 to 4.4 GW in fiscal 2025.

Tariffs for these projects plummeted to Rs 3.38/kWh from Rs 6.69/kWh driven by falling battery storage costs. Participation in solar-with-storage bids was strong, averaging 169% over two years, compared with 115% for other storage configurations.

Despite these achievements, India’s renewable energy sector faces structural challenges. Tendering far outpaces actual capacity addition, with the 166 GW pipeline signalling a need for accelerated execution.

While domestic manufacturing and supply chains are robust, land availability and transmission infrastructure remain bottlenecks.

Central agencies, led by Renewable Energy Implementing Agencies (REIAs), dominate tendering, accounting for 70% of capacity tendered through competitive bidding process in fiscals 2024 and 2025, while state agencies contribute only 26%. Regionally, Gujarat, Maharashtra, Rajasthan and Madhya Pradesh lead in tendering and offtaking RE on their own, but other states lag, undermining national goals.

Offtake issues further complicate progress, with each REIA having concluded reverse auction, but having unsigned power sale agreements (PSAs) for 6–10 GW, potentially delaying project deployment.

The Uniform Renewable Energy Tariff (URET) mechanism, introduced in 2023 to streamline pricing, has stalled, leaving the market fragmented. Weak enforcement of Renewable Purchase Obligations (RPOs) across states exacerbates the challenge, with compliance gaps threatening India’s 2030 RE targets.

To sum up, India’s fiscal 2025 RE boom showcases its potential as a global clean energy leader. However, unlocking the full promise of the 166 GW pipeline demands urgent action. Strengthening transmission networks, securing land and streamlining project execution are critical. Reviving URET and enforcing RPOs will ensure market stability and equitable progress across states.

India’s progress towards a future powered by renewable energy is gathering pace, driven by adoption of battery energy storage system (BESS). Substantial investments, strategic deals and robust policy support are powering growth in the BESS segment as the country targets 500 GW of non-fossil-fuel installed generation capacity by 2030. The Central Electricity Authority (CEA) estimates 60.6 GW of energy storage requirement by 2029-30, with BESS contributing ~69% (41.6 GW/208 GWh) and pumped storage plants contributing ~31% (18.98 GW/128.15 GWh).

Demand for batteries is widespread, spanning sectors such as grid-scale energy storage, electric vehicles and off-grid applications. This, in turn, has attracted a wide range of investors, including domestic conglomerates such as Reliance and Adani, and global players such as Fluence. In the grid-scale segment, energy storage demand from utilities has seen significant growth. For standalone BESS projects, the capacity tendered surged to 21.5 GWh in 2023 from only 6 GWh in 2022. However, the capacity tendered dropped to 5.5 GWh in 2024, driven by sharper focus on integrated BESS with RE projects. Notably, around 15 GW of RE capacity in 2024 required BESS as part of the project configuration.

As demand and market participation continue to rise, the capital investment in battery manufacturing in India is expected to surge to Rs 2.2 lakh crore between fiscals 2026 and 2030.

Government initiatives are playing a crucial role in unlocking investments in the BESS sector. These initiatives recognise the importance of energy storage for grid stability and facilitating increased renewable energy penetration. On the demand side, the 5% mandate of energy storage obligation on states by 2030 is a significant enabler, driving adoption of BESS. On the supply side, the government has mandated that at least 10% energy storage capacity should be co-located with solar power projects. The government has also launched the Viability Gap Funding scheme, allocating Rs 3,760 crore to subsidise 40% of the capital costs for 13.2 GWh of grid-scale BESS projects to be developed by 2026. The scheme was approved in September 2024.

In May 2021, the government approved a Production Linked Incentive (PLI) scheme for Advanced Chemistry Cell (ACC) battery storage, with a budget outlay of Rs 18,100 crore, aimed at boosting domestic manufacturing of advanced batteries, reducing import dependence and strengthening the ecosystem for electric mobility and renewable energy storage. The scheme targets establishment of 50 GWh of ACC manufacturing capacity, with an additional 5 GWh for niche ACC technologies.

Figure: Capacity awarded under PLI scheme for ACC, GWh

Source: Crisil-Bridge To India

That said, despite the growth in demand and policy support, the BESS domestic supply chain has been a slowcoach. The PLI scheme has been facing challenges, with no operational gigafactories established as of March 2025. The Ministry of Heavy Industries has already imposed considerable penalties on manufacturers for the missed deadline.

The tight timelines pose a significant challenge, further exacerbated by lack of indigenous R&D in India and scarcity of skilled manpower in ACC technologies. Notably, the PLI scheme requires a 25% domestic value addition (DVA) within two years and 60% within five years. Meanwhile, India continues to rely heavily on imports for critical battery inputs such as lithium, cobalt, nickel and graphite. Establishing a local supply chain is a long-term endeavour as lithium mining, such as in Jammu and Kashmir, is still in the nascent stage and there is no refining capacity. As a result, companies are forced to rely on expensive imports, at least in the initial stage, which undermines their ability to meet DVA targets and maintain profitability.

The industry is also exploring alternative battery chemistry such as solid-state and sodium-ion batteries to mitigate the supply-chain risk associated with critical minerals. However, establishing a domestic supply chain will require a significant investment of time and resources, besides further policy support.

Project delays are hampering India’s progress towards its ambitious target of generating 500 GW electricity from non-fossil fuel sources by 2030.

A report by the Central Electricity Authority (CEA) on renewable energy (RE) projects under construction/ development as of September 2024 shows that, of the 174 GW renewable capacity in the pipeline, 25 GW is delayed.

The CEA report shows an average delay of 16 months in commissioning utility-scale projects, with solar and hybrid ventures getting delayed by 16 months, and wind projects by 19. In extreme cases, delays have stretched to 43 months, with several projects even facing termination.

There are multiple reasons for the delays. Regulatory issues such as slow power purchase agreements (PPAs), and state approvals and clearances delayed 59% of the projects, reveals a review of 27 petitions pertaining to delayed projects. Further, external factors such as Covid-19 stalled 48% of the projects, while 30% were delayed due to the grid not being ready and land acquisition challenges delayed another 15%.

Figure: Reason and extent of delays in project commissioning

Note:i. The above represents data from 27 orders issued by respective regulatory authorities in 2023 and 2024 related to the delays in RE project commissioning, aggregating to 4.2 GW.ii. This does not include petitions for which orders are yet to be issued.Source: State Electricity Regulatory Commissions (SERCs), Central Electricity Regulatory Commission (CERC)

A significant factor in these delays is the procedural bottleneck in signing PPAs, the backbone of project viability. Debt-laden electricity distribution companies (discoms) are hesitant to sign new PPAs, especially when coming at tariffs which would not be in alignment with their cost expectations at times realized at a later stage.

Even when the project does get constructed, evacuating power is another matter. Right-of-way disputes ecological clearances, and complex geography, slow down the construction of transmission infrastructure, stalling projects for months. Without evacuation lines, the plants become financial liabilities. The transmission infrastructure required to realise the capacity in the pipeline is likely to become operational only over the next 3-5 years.

To tackle right-of way delays caused due to compensation disputes, the government has increased transmission infrastructure compensation, from 85% to 200% of the land value for tower base area, whereas corridor compensation has been revised from 15% of the land value to 30%, 45% and 60% for rural, urban and metropolitan areas. This could accelerate power evacuation infrastructure development, bridging the mismatch between project capacity and available transmission lines.

Challenges pertaining to land acquisition, along with fragmented state-level laws, delayed approvals and disputes over land use stall projects for years. Though some state governments have eased the process with pre-allotted lands for renewable projects, lack of streamlined policy has made the overall process cumbersome.

Further, the government’s aggressive push to release 50 GW of bids annually from fiscal 2024 to 2028 has outpaced demand and readiness of discoms and developers. This has exacerbated the delay and resulted in projects with limited offtake.

Delays also lead to inflated costs. Land acquisition costs, idle labour, and penalties erode returns. Meanwhile, the reluctance among discoms to sign PPAs force developers to sit on equity or risk-sunk costs. Developers are forced to juggle between administrative formalities, ecological clearances and community pushback, costing them time and money.

India’s RE surge needs to be addressed through a multi-pronged approach starting with harmonising state land acquisition laws, providing fast-track approvals, and expanding pre-allotted land parcels for such projects.

The focus should first be on setting up transmission lines and then completing the project. Central agencies must prioritise development of power evacuation infrastructure, especially in RE-rich states.

Additionally, streamlining the clearance process, especially related to regulatory matters, can expedite project development. Enforcing renewable purchase obligation norms could prompt discoms to sign PPAs, thereby boosting execution.

The ambitious target of 500 GW is achievable, but only if the bottlenecks are dismantled.

The solar photovoltaic (PV) module market is at a critical juncture as technology obsolescence accelerates across industries.

Since 2017, the market has been dominated by passivated emitter and rear cell (PERC) technology globally. Now, with tunnel oxide passivated contact (TOPCon) and heterojunction technology (HJT), which provide higher efficiency, lower degradation and better cost competitiveness, emerging as the new gold standards in PV modules, a rapid shift in the technology can be seen.

The PERC technology, which boosted P-type cell efficiency — a measure of how well a solar cell converts sunlight into electricity — to ~22%, is approaching its theoretical efficiency limit of 24.5%. In contrast, N-type technologies such as TOPCon and HJT offer efficiencies exceeding 25%, with laboratory results reaching 26% for TOPCon and 27% for HJT. N-type cells also exhibit lower light-induced degradation (LID) and better temperature coefficients, enhancing energy yield in real-world conditions.

TOPCon technology involves the addition of a thin tunnel oxide layer to minimise recombination losses, i.e. restricting current flow. This also can be integrated into existing production lines with relatively moderate upgrades, making it a cost-effective solution for manufacturers seeking to transition to higher-efficiency modules.

The upshot is a rapid uptake of the new technologies, which can be gauged from the fact that the share of PERC in global PV shipments, shrunk to 34% in 2023 from 76% in 2021. And in 2024, the share is estimated to have reduced further to 22%, based on Infolink’s assessment of top 10 manufacturers, whereas N-type TOPCon module shipments accounted for nearly 70% and Back Contact (BC) products account for 3%.

Figure: Global annual PV shipments by technology

Source: National Renewable Energy Laboratory, Crisil-Bridge To India

The main reason for the sharp cut has been China — which accounts for 80–85% of global solar module manufacturing — aggressively transitioning to N-type.

The Chinese government has maintained high efficiency requirement from module manufacturers. The new efficiency benchmarks set in the revised guidelines released by its Ministry of Industry and Information Technology in November 2024 are a minimum 23.7% for P-type cells and 26% for N-type cells.

In contrast, in India, the Approved List of Models and Manufacturers (ALMM), which lists the approved models of PV modules that are allowed for all PV installations in India (as updated on February 17, 2025) marks TOPCon module efficiency considerably lower at 19.2-23.6% and PERC module efficiency at 17.0-22.0%. To boot, domestic TOPCon module manufacturers comprise only ~15% market share vs China’s overwhelming majority.

The global solar PV industry is shifting towards N-type technologies due to their superior efficiency and economic benefits. Clearly, Indian module manufacturers have been slow to embrace the change. And while the ALMM mandate shields them from global competition, it may not suffice to secure a strong position in the export market, also affecting its ambitious renewable energy targets.

The imperative, therefore, is for all to see. To catch up, India must upgrade to N-type technologies with higher efficiency — and fast.

The recent recommendation of the Central Electricity Authority (CEA) that all renewable energy implementing agencies and state utilities incorporate at least two-hour co-located energy storage systems (ESS), equivalent to 10% of the installed solar project capacity, in future solar tenders is expected to result in 14 gigawatt (GW) storage capacity being installed by 2030.

As of December 31, 2024, India’s total installed ESS capacity stood at 4.86 GW, comprising 4.75 GW of pumped storage plants (PSP) and 0.11 GW of battery energy storage system (BESS) projects.

The Ministry of Power said the mandate will help alleviate intermittency issues and provide crucial support during periods of peak demand. It also suggested that distribution licensees consider making two-hour storage mandatory for rooftop solar installations.

The government believes storage systems can operate in one of two modes: a single-cycle operation, in which they are charged using co-located solar power and discharged during evening hours, or a double-cycle operation, in which they can be charged using both solar power and energy from the grid during off-peak hours and discharged during peak hours.

The CEA recommendation, though in line with India’s aim to reach 500 GW of non-fossil fuel energy capacity by 2030, is likely to restrain tendering of standalone solar projects and accelerate deployment of energy storage facilities.

That said, given the prolonged construction timelines and stringent environmental clearance requirements in PSP hybrid projects, firms are likely to opt for BESS projects to meet the mandates. BESS offers multiple advantages over PSP, including lower prices of critical minerals, operations and maintenance costs, and operational risks.

Implementation of the recommendation is expected to take the installed storage capacity to 35-45 GW by fiscal 2030, which will marginally increase the reserve margin to 4-5% in fiscal 2030 from 3.6% in fiscal 2024.

Figure: Installed storage capacity to be 35-45 GW, or 5-6% of total installed capacity, by FY30, GW

Source: Crisil Intelligence

That said, current estimates of storage capacity addition are deemed insufficient to achieve substantial reserve margin ratios.

Besides, although the CEA mandate is expected to bring additional capital expenditure for solar power projects, their levelized cost of energy (LCOE) is projected to remain below that of fossil-based power plants. In fiscal 2024, the LCOE for solar-storage hybrid power plants was Rs 3-4 per kilowatt hour (kWh), compared with Rs 5-6 per kWh for coal and Rs 13-14 per kWh for gas-based power plants.

The gap is expected to widen by fiscal 2030, making solar hybrid projects more lucrative than coal- and gas-based power plants, on the expectation that battery prices will remain stable or fall further.

Figure: Declining hybrid tariff to support storage-based installations, Rs per kWh

Note: Mixed resources include solar and wind hybrid projectsSource: Crisil Intelligence

To attain a reserve margin of 10% by fiscal 2030, India will require additional storage capacity of 35-45 GW. To achieve the global benchmark of 15% by that year, India will need additional capacity of 40-50 GW of ESS, excluding the current estimates of storage capacity addition.

Thus, successful implementation of the policy will depend on factors such as battery prices, ease of battery procurement and overall project execution efficiency. These will be key to facilitating seamless implementation by power generation companies and ensuring timely execution of projects.

Building on the success of the PM Surya Ghar: Muft Bijli Yojana, the government has issued guidelines to further promote rooftop solar (RTS) installations under the renewable energy service company (RESCO) and utility-led aggregation (ULA) models. Launched in February 2024, PM Surya Ghar: Muft Bijli Yojana has achieved remarkable success with over 8 lakh RTS installations in just one year.

The new guidelines expand central financial assistance (CFA) to include the RESCO model for new residential RTS installations up to 3 kW. However, this support is subject to conditions — only domestic solar modules and cells can be used, and it is not available to existing solar users and non-residential consumers.

To be sure, the RESCO model, which involves third-party developers to install and maintain RTS systems, has not been as successful as expected. Of the total 16.9 GW rooftop capacity as of June 2024, RESCO-based projects accounted for only 19%.

Primary challenges with this model are:

Small project size: RTS projects, especially in the residential category, are often small. Additionally, the 25-year power purchase agreement (PPA) tenure is too long for small-scale projects, limiting their commercial attractiveness

Creditworthiness of offtakers: Limited credit information/ratings on small consumers increases the risk of delayed payments for developers

High operations and maintenance (O&M) costs: The distributed nature of these assets across various locations increases the O&M cost for developers

RESCO will continue to face challenges due to high transaction costs associated with consumer identification, and system commissioning and maintenance. Furthermore, as the PPA tenure is reduced from 25 years to 5 years, the landed tariff of RTS for the consumer may increase up to two times, leading to higher costs compared with utility supply, especially in states having low energy charges.

The ULA model, on its part, offers two approaches — utility-owned assets, where utilities own and manage solar systems; and consumer-owned assets, where households own the systems with utility support. This model can be implemented by distribution companies (discoms), state governments or designated entities.

ULA addresses the creditworthiness issue of offtakers and provides a payment security mechanism, reducing the risk for developers and easing financing. A total of Rs 100 crore has been earmarked for the payment security mechanism, managed by the National Program Implementation Agency. This fund can be accessed by ULA proposals executed under RESCO, with a contribution of Rs 2,000 per installation. A state guarantee is also required for utilities to access the fund.

Table: Summary of guidelines

Source: MNRE, Crisil-Bridge To India research

Historically, utilities have followed a model similar to consumer-owned assets, aggregating consumers for RTS and selecting developers for installation and commissioning, thereby achieving competitive price discovery. While the guidelines propose that consumers invest only up to 10% of the benchmark cost, with additional grants available, the availability of state funds remains uncertain.

Some states have implemented unique utility-led models. For example, Kerala’s state utility, KSEBL, has invested in setting up RTS on consumers’ roofs under the Soura programme launched in 2019. The programme implemented a rooftop lease model for residential consumers, where the discom invests in setting up the RTS and procures entire power from it. Consumers receive a roof lease benefit equivalent to 10% of the solar generation as an energy rebate on their utility bills. KSEBL awarded 46.5 MW capacity under this model and has successfully commissioned it.

Another unique utility-led model was designed by Andhra Pradesh, which targeted low-paying residential consumers. Here, the AP discom tied up with a bank for financing RTS projects, with less than 10% contribution from consumers. To ensure payment security for the bank, the discom collected the EMI as part of the consumers’ utility bills. Although this business model received approval from the state electricity regulatory commission, it did not materialise due to institutional challenges.

To sum up, while the guidelines aim to address the challenges associated with RESCO-based projects, standalone RESCO models may continue to face issues due to high transaction costs.

The ULA-based model, on the other hand, offers a promising alternative by addressing creditworthiness issues and providing payment security. Furthermore, the reduced PPA tenure and increased CFA availability would help boost participation from developers and consumers in the RTS sector.

The Bureau of Energy Efficiency (BEE) has released a detailed guide outlining acceptable project structures for the offset mechanism within the Carbon Credit Trading Scheme (CCTS). This scheme applies to various sectors, including renewable energy, hydrogen production, energy efficiency, waste handling, agriculture, forestry and transport. 

Table: List of draft methodologies for offset mechanisms under Carbon Credit Trading Scheme

Source: Bureau of Energy Efficiency

The carbon credit market consists of two components: compliance schemes and offset schemes. Compliance schemes target obligated entities mandated by the government to reduce emissions, while offset schemes involve voluntary emission reduction efforts.

The government has, for now, identified nine sectors as obligated entities, with emission reduction targets expected to be notified by the end of the current fiscal. These targets will be applicable until 2027, with the first target period starting next fiscal. Compliance will begin in March 2026 and carbon credit certificates are expected to be issued to industries by October 2026, followed by trading.

To support the trading framework, the BEE’s draft methodologies provide clear guidelines for project developers to establish facilities that can produce tradable carbon credit certificates. As one of the largest suppliers of credits in the international voluntary carbon markets, India’s efforts to strengthen its carbon credit trading system have been significant. The country has issued over 11% of the global carbon credits as of 2023.

Article 6 of the Paris Agreement establishes a framework for international carbon markets and cooperative emission reduction efforts. A key component is the internationally transferred mitigation outcome (ITMO), a unit of carbon credit representing greenhouse gas emission reductions. For successful ITMO trading, it is essential for the participating countries to adopt standardised frameworks that ensure consistency and transparency across borders.

The Indian carbon market’s methodologies are consistent with those of the UNFCCC’s Clean Development Mechanism (CDM). In the renewable energy sector, the scope of the Indian carbon market is limited to hybrid systems with or without energy storage, excluding standalone solar and wind projects.

This approach is in line with global concerns about the integrity of renewable energy carbon credits, particularly regarding additionality. In recent years, these concerns have led to significant changes in the market. For instance, in 2020, major carbon credit standards such as Gold Standard and Verra introduced restrictions on new renewable energy projects.

More recently, the Integrity Council for the Voluntary Carbon Market (ICVCM) took a significant step by deciding in 2024 to withhold its Core Carbon Principles (CCP) label from renewable energy projects. This decision was made due to concerns about additionality and the inadequacy of existing methodologies in assessing project viability without carbon credits. The Indian carbon market’s offset mechanism methodologies have adopted similar standards, ensuring alignment with international best practices and maintaining the integrity of the market.

Compliance carbon markets differ from voluntary markets. Compliance credits, subject to stricter verification and monitoring processes, typically command higher prices than voluntary credits. Concerns about greenwashing and less rigorous verification in voluntary markets contribute to their lower prices.

Figures: Prices of carbon credit across global markets, $/mtCO2e

Source: S&P Global Platts Carbon Price Explorer

Within the voluntary market, technology-based carbon capture credits trade at a premium when compared with other standards. This price reflects the high cost of the technology and greater confidence in the additionality of emission reductions. Conversely, renewable energy credits (RECs) trade at the lowest prices, around $1 per mtCO2e, likely due to lower demand and questions surrounding their additionality in avoiding carbon emissions.

India’s carbon market is evolving with a structured approach that aligns with global best practices and addresses domestic priorities. The emphasis on hybrid renewable energy systems, rigorous verification standards, and alignment with Article 6 of the Paris Agreement indicate a clear strategy to enhance market credibility. While the compliance market targets the major energy intensive sectors, the voluntary market facilitates adoption of emerging emission reduction technologies that can potentially generate high-quality carbon credits.

However, challenges remain, including the need for broader participation from industries, stronger price signals for carbon credits, and integration with international carbon trading mechanisms. If successfully implemented, the CCTS could position India as a key player in global carbon finance, attracting investments in decarbonisation, while supporting its net-zero ambitions.

The US government’s recent decisions to withdraw from the Paris climate agreement and relax regulations on production and use of fossil fuels have added a new layer of complexity to the evolving global energy landscape as countries strive to strike a balance between energy security, economic growth and environmental sustainability.

A significant player in the global energy landscape, the US accounted for approximately 14% of the world’s installed generation capacity as of 2023. Renewable energy sources made up 32% of the country’s generation capacity. Notably, the per capita energy consumption in the US is four times the global average of at 3.6 MWh. India weighs in at a much lower 1.2 MWh.

In the context, the US government’s withdrawal from the Paris climate agreement marks a substantial departure from previous climate commitments and could potentially be seen as an opportunity for others to relax their efforts in reducing carbon emissions, thereby slowing down advancements in addressing climate change.

The timing of the move is especially critical, coming after the UN COP29 conference where developing nations pushed for an increase in climate finance to $1.3 trillion per year but the final agreement settled at a much lower target of $300 billion per year until 2035. Given that the previous $100 billion annual target, set in 2009, was only met for the first time in 2022, the US withdrawal is expected to intensify the challenges in meeting the climate finance targets.

Further, the Trump administration is prioritising energy security by easing regulations on oil and gas production, lifting restrictions on resource extraction and declaring a national energy emergency to expedite approvals for fossil fuel, biofuel, nuclear and critical mineral infrastructure projects.

For India, the US focus on fossil fuels presents both opportunities and challenges. As a country heavily reliant on fossil fuels for its energy needs, India could see its dependence on US energy supplies increase. Between 2017 and 2024, the US was the fifth-largest supplier of liquefied natural gas (LNG) and crude oil to India. The US policy shift favouring fossil fuels could ensure stable supply to India, mitigating short-term energy security risks. As for opportunity, India could attract more climate-focused financing from global markets that are shifting away from fossil-fuel investments in response to the US policy changes.

Figure: Renewable energy capacity addition in key international markets, GW

Source: IRENANote: Figures include solar, wind, hydro, bioenergy and geothermal sources

On the flipside, the US policy shift has a particularly negative impact on wind power. The new restrictions include halting new offshore leasing, suspending federal leasing and permissions, and an indefinite ban on new wind project approvals. While the global impact of this move might be limited, it will certainly slow the development of offshore wind projects, which are already facing challenges due to high costs and project delays.

The likely impact on the solar sector is unclear. The Inflation Reduction Act (IRA) of 2022 had spurred significant growth in the manufacturing of solar equipment in the US, driving adoption. Currently, solar module production prices in the US range between $0.22 and $0.30 per Watt peak (Wp), nearly three times the price of Chinese modules and almost double that of Indian ones. However, with the administration putting the IRA incentives on hold, there is haze over the trajectory.

The US is a key export market for Indian solar manufacturers, accounting for 97% of the solar module exports in fiscal 2024 and the first half of fiscal 2025. However, with the US government emphasising domestic manufacturing and increasing tariffs, India must diversify its exports.  While Canada, South Africa, Nigeria and Turkey have emerged as significant export markets for India over the past two years, Indian manufacturers will have to enhance cost competitiveness and explore new trade partnerships to compete with China in the international markets.

To sum up, the US energy policy shift creates significant uncertainty globally. Its withdrawal from the Paris Agreement weakens global climate action efforts and complicates climate finance commitments. The focus on fossil fuels, while potentially beneficial for some nations in the short term, is in conflict with the long-term need for a clean energy transition.

In the milieu, India should leverage the global focus on clean energy to attract investments and accelerate its own transition to a more sustainable energy future.

The market for green energy open access has hit a speed breaker with the Karnataka High Court recently striking down the Green Energy Open Access Rules, 2022, and the Karnataka Electricity Regulatory Commission (KERC) Regulations, 2022, under its state’s jurisdiction. This decision has significant implications for green energy open access, under which consumers can directly purchase renewable energy from the generators instead of distribution companies (discoms). The central government aims to enforce these rules uniformly across states to establish consistent standards and facilitate open access at a broader level.

However, a group of hydro power generation companies had challenged the legitimacy of the rules and regulations in the high court, arguing that these exceeded the authority granted by the Electricity Act, 2003, and contravened the principles of fairness. The companies claimed that implementation of the rules would harm their commercial interests and substantially raise their operating expenses as the charges are not determined rationally.

The high court ruled that the rules lacked legal authority because the central government exceeded the limits of authority conferred by the Electricity Act, 2003. In the case of open access regulations, the Commission is vested with the exclusive power to frame regulations, as per Section 181(2)(p) to (s) of the Act, the court said. According to the court, the KERC, as the state regulator, should have exercised its autonomy to draft the regulations with a well-defined methodology, rather than relying simply on the rules framed by the central government. As a result, the regulations framed by the KERC pursuant to these rules were also liable to be struck down, the court added.

Other than Karnataka, 28 states and union territories have adopted regulations based on Green Energy Open Access Rules, 2022, as of January 2024.

Figure: Adoption of Green Energy Open Access Rules as of January 2025

Source: Bridge to India, Crisil Intelligence

The central government aims to standardise various aspects through these rules across states, promoting a more favourable open access market. Specifically, the rules seek to clarify the applicability of open access charges, such as additional surcharges and standby charges, which would ultimately reduce the cost of supply through open access. The rules also lower the threshold for open access, making green energy more accessible for consumers to adopt renewable energy through open access.

These also address the availability of energy banking arrangement with the grid, which had previously varied significantly across states in terms of duration and applicable charges. Banking of power remains a contentious issue as there is no statutory requirement for states to provide this facility. Nevertheless, states continue to promote banking of power to encourage renewable-energy adoption. For instance, a 2022 study conducted by KERC found that the monthly cost of banking ranged from 16.1% to 19.3% of the wheeled energy, while the state proposes a charge of only 8% of the wheeled energy.

Based on the high court’s directives, the KERC has issued a new draft of Green Energy Open Access Regulations, applicable to all open -access customers, including those that have filed applications before the state nodal agency from January 13, 2023, in case of short-term open access and from January 2, 2023, in the case of long-term and medium-term open access. While most of the provisions pertaining to the procedures remain the same, the new draft provides a methodology for determining open access charges.

The development can impact the renewable energy sector significantly, particularly if other states follow Karnataka’s lead. While the KERC’s new draft regulation is a step in the right direction, it remains to be seen how other states will treat their open access regulations. The influence of discoms may lead to regulations that are not in the best interest of the open access market, as seen in the past. For instance, Gujarat’s open access charges in 2021 resulted in a 30-40% increase in tariffs for solar projects due to banking charges alone.

In the milieu, the treatment of open access regulations by other states will bear watching.

The domestic renewable energy sector is poised to sustain its growth momentum in 2025, driven by both utility-scale procurement and commercial and industrial (C&I) sector demand.

In 2024, capacity addition in the sector surged to a historic high of 27 GW, according to the Ministry of New and Renewable Energy (MNRE) data. Solar energy saw a remarkable four-fold increase in capacity addition on-year. However, wind, with a modest capacity addition of around 3.5 GW — still the second highest in a year after the 5.2 GW recorded in 2017 — continued to struggle. The C&I sector is estimated to have accounted for around 45% of the solar and wind capacity added in 2024.

Major factors that will shape the growth trajectory of the domestic renewable energy sector in 2025 are as follows:

Domestic solar cell manufacturing capacity: Expansion of the Approved List of Models and Manufacturers (ALMM) to include solar cells, effective July 2026, has provided a significant impetus to domestic solar cell manufacturing capacity, which currently stands at approximately 10 GW. The list, which is updated periodically by MNRE, restricts imports of solar components, which, in turn, boosts domestic production. Industry trends and announcements suggest the domestic solar cell manufacturing capacity will grow substantially to 43-47 GW by June 2026. Timely commissioning of these facilities will be key to ensuring a stable and reliable supply chain and mitigating potential risks associated with supply deficits and price volatility.
Residential consumers to drive rooftop growth: Launched in February 2024, the PM – Surya Ghar Muft Bijli Yojana has generated substantial consumer interest in residential rooftop projects. In the first half of 2024, 3.3 GW of rooftop solar capacity was added in the country, with the residential sector accounting for 56% of this, surpassing the C&I sector for the first time. As of November 2024, the National Portal of India reported 1.46 crore registrations, 27.19 lakh applications and 6.58 lakh installations under the scheme. The outstanding applications are expected to contribute over 6 GW of capacity, assuming an average of 3 kWp per application. This momentum is anticipated to continue and expand further in 2025.
Rising interest in flexible RE solutions: Popularity of flexible RE solutions is on the rise, with both states and open-access consumers evincing increased interest. In 2024, the country saw issuance of RE tenders of approximately 88 GW, resulting in allocation of around 48 GW of capacity. Notably, the share of pure-play solar and wind bids decreased from 65% in 2023 to 56% in 2024, indicating a shift towards more flexible RE solutions. Furthermore, the total RE allocation in 2024 was 20% higher on-year, laying the groundwork for a robust pipeline in 2025.
Expansion of evacuation infrastructure: Development of evacuation infrastructure is gaining momentum, with significant progress made in recent years. As of October 2024, a substantial portion of the planned transmission infrastructure, including 28% of the targeted 114,687 circuit km of transmission lines and 20% of the planned 776 GVA substations, was completed. Giving further impetus, the government is expected to announce the Green Energy Corridor Phase III in the upcoming Union Budget. Phase 1 and 2, currently underway, aim to support evacuation of over 44 GW of RE. Phase 3 will further strengthen the evacuation infrastructure, enhancing resource adequacy among states.
Project development timelines: To meet the government’s goal of 500 GW of non-fossil fuel-based power by 2030, the RE project installations have to speed up further. In 2024, solar installation of 25 GW was achieved. This needs to increase to 40 GW annually. While many large projects have been approved, execution has to be quickened. As of September 2024, there were 122 GW of solar and 38 GW of wind projects in the pipeline. Further, challenges need to be addressed in the wind sector, which has seen only 1-3 GW of new capacity added each year since 2018 owing to limited availability of suitable land and delays in project execution.
Availability of finance: With RE capacity addition accelerating, demand for financing has also increased. Fortunately, domestic banks have concurrently increased their lending to the sector. For instance, the Indian Renewable Energy Development Agency’s loans for RE projects jumped 31% on year in 2024. Loan portfolios of Rural Electrification Corporation (REC) and PFC also reported a significant 49% and 19% on-year growth, respectively, during January-September 2024. However, to further stimulate growth, fund flow to the sector has to be stronger. While the Reserve Bank of India has classified RE as a priority sector, distinguishing it from the broader power sector could incentivise banks to lend more to this sector.
Offshore wind development: India’s first offshore wind project, located off Gujarat coast, is currently underway with a bidding process that will define the future course of the sector. Globally, offshore wind development is facing major challenges due to delays in project development and high costs, making it an expensive proposition. However, in the Indian context, the government’s decision to provide support via viability gap funding for the initial 1 GW of capacity could help mitigate some of the costs.

Net-net, in 2025, government support and emerging technologies will continue to aid growth of the renewable energy sector. However, addressing challenges in project development, transmission infrastructure and manufacturing will be crucial to achieve the target of 500 GW non-fossil fuel-based power by 2030.

India’s solar and wind energy sector demonstrated remarkable growth in 2024, fueled by government support, declining technology costs, and increased investor confidence.

Record capacity addition: India witnessed an unprecedented surge in solar energy installations in 2024. Between January to November, the country added 20.8 GW of solar capacity and 3.2 GW of wind capacity, ~87% YoY growth. India crossed the milestone of 200 GW of cumulative installed Renewable Energy Capacity in September, of which solar and wind contributed 43% and 24% respectively.

Module price falls further: China module prices dipped another 32% in 2024, reaching USD 8 cents/Wp. Massive capacity addition and supply glut continue to challenge the Chinese manufacturers as majority operate under losses. India’s manufacturers on the other hand were safeguarded with reimposition of ALMM from April 2024. With huge domestic demand but increasing module manufacturing capacity and falling component prices led to the domestic module prices dropping by 36% year-on-year to USD 14 cents/Wp at the end of the year. 

Energy storage push: As per market estimates, lithium-ion battery prices dropped 20% from $144/kWh in 2023 to $115/kWh in 2024. This led to increased incorporation in bids of adoption of the technology coupled with RE fuels, largely for peak power supply or load following supply applications. Removal of BCD on critical minerals such as lithium and cobalt further economized BESS. In year 2024, Out of 63 GW allocation of utility scale RE projects, 12.6 GW allocation was for RE coupled with storage projects.

Rooftop Surge: India added over 4 GW of rooftop solar capacity between January to November 2024. This remarkable growth was fueled by PM Surya Ghar Yojana. As of November 2024, around 2.6 million applications were submitted under the scheme and 0.6 million systems were installed, translating to around 1.8 GW capacity.

Figure: Monthly Solar and Wind capacity addition in 2024

Source: MNRE, CRISIL-Bridge To India Research

While the year observed record capacity addition, the sector continues to face some challenges, which need to be addressed to make the RE ecosystem more attractive.  

Land and Connectivity Issue: The renewable energy sector is hindered by significant scalability challenges, primarily due to delays in the development of transmission infrastructure, which are often caused by right-of-way disputes and land availability issues. Furthermore, many of the most promising wind farm locations are currently occupied by outdated wind turbines, which require repowering to unlock their full potential.

Technology upgradation: While TOPCon cells are gaining prominence globally, India’s manufacturing sector still relies heavily on PERC technology, with half of its production capacity dedicated to it. However, with industry forecasts suggesting that PERC may become obsolete by 2027, Indian manufacturers need to consider upgrading to TOPCon technology, particularly since most of the production capacity for cell is now under planning.

Frequent policy changes: This leads to uncertainty and hinders the growth of the RE  industry. While the government aims to notify policy changes in advance, recent actions have disrupted the sector. For instance, the imposition of anti-dumping duty on solar glass in December, following the introduction of custom duty in October, creates significant and sudden cost increase. This move, coupled with insufficient domestic capacity, will inevitably escalate project costs.

India’s renewable energy sector is poised for large scale growth in the coming years. The government’s commitment to clean energy, coupled with declining technology costs and increasing investor confidence, provides a strong foundation for the sector’s future development. By addressing the challenges and implementing effective solutions, India can strive to achieve its ambitious renewable energy targets as planned.

Timely commissioning of the solar cell manufacturing projects announced so far will be crucial to ensure there is adequate capacity to meet demand in years to come. For while the announcements suggest supply will be adequate, the typical utilisation factor arithmetic and other imponderables could spell a transient shortfall till manufacturing ramps up.

Earlier this year, the government extended the Approved List of Models and Manufacturers (ALMM) to solar cells from June 1, 2026, in a bid to accelerate solar cell manufacturing in India.  

Domestic solar cell production capacity is estimated to increase fourfold to 43-47 GW by June 2026 from 10 GW in March 2024. As against this, annual demand is expected to average 40-45 GW between fiscals 2027 and 2030.

So, production needs to catch up and fast.

As things stand, of the 79 corporate entities that together own the country’s 62 GW installed solar power capacity as of December 2024, only 13 have an integrated cell manufacturing base. The rest will have to decide between expanding capacity or competing for domestic cell supplies.

Further, the high prices of domestically manufactured cells could impact tariff levels bid at solar power project auctions. Today, Indian solar cells are 1.5-2.0x costlier than alternatives from China, even after basic customs duty. Based on current market dynamics, such high prices can drive up the capital cost of solar power projects by Rs 5-10 million/MW and require tariff increase of Rs 0.40-0.50 per unit as offset.

The industry has seen announcements of over 55 GW through the Production Linked Incentive scheme and beyond. This augurs well because data shows cell-to-module integrated plants enjoy 2-6 percentage points better Ebitda margins versus an only-module unit historically.

Although 12 non-integrated players have announced plans to install ~32 GW capacity by 2029, the relatively higher capital cost of cell manufacturing plants compared with module assembly lines and falling prices of the solar value chain could slow things down.

Figure: Majority of ALMM-enlisted module players need to consider integration

Source: MNRE, CRISIL-Bridge To India Research

The ALMM cell mandate could also pose challenges for companies that don’t develop domestic cell manufacturing capability as they would not be complying and, thus, could face module-supply challenges that can impact their market share over the long term.

Overall, the non-tariff barrier will protect domestic manufacturers that are vulnerable to global supply shocks and even aid exports as the United States, a key market, continues to manufacture modules at 30-35% higher prices owing to lack of upstream components.

India’s ambitious renewable energy targets have sparked a crucial debate about the role of import duties in promoting domestic manufacturing while ensuring affordability. The government’s efforts to promote domestic manufacturing are laudable, but the higher cost of imported components and domestic capacity constraints have created challenges for developers and engineering, procurement and construction (EPC) contractors. 

India has added around 20 GW of annual solar capacity in the past two years, but needs to scale up to at least 35 GW annually to meet its 2030 renewable energy targets. On the other hand, India’s module manufacturing capacity surpassed 78 GW in December 2024, providing Indian manufacturers an opportunity to export. This capacity surplus can be leveraged to meet the domestic demand, reducing the reliance on imported components.

The government has imposed a complex set of import duties on solar components from time to time. Currently, a basic customs duty (BCD) of 40% is applicable on modules, 25% on cells and 20% on solar invertors.

In recent months, the government has introduced additional duties on other components of solar projects, such as a 10% BCD on solar glass effective October 2024. The government has also introduced an anti-dumping duty on solar glass imports from China ($ 673-677/MT) and Vietnam ($565/MT) for six months from December 4, 2024, on the Directorate of Trade Remedies’ recommendation.

On September 27, 2024, the government introduced an anti-dumping duty of $403-577/MT on imports of anodised aluminium frames for solar modules from China.

The figure below presents three cases to compare the impact of duties on the overall cost of a solar project:

Case 1: Import of components with no import duties applicable

Case 2: Import of modules with basic custom duty

Case 3: Domestically assembled modules with imported cells, glass and other components

Figure: Landed cost of solar projects based on applicable duties

Source: CRISIL-Bridge To India ResearchNote: Imports considered are from China, with modules priced at $0.09/Wp, cells at $0.09/Wp, solar glass at $2.92/sqm and aluminium frames at $3/kg

With the introduction of the Approved Lists of Models and Manufacturers (ALMM), most of the modules being supplied fall under Case 3. Of the 62 GW installed capacity owned by 79 entities as of December 2024, only 13 manufacturers have an integrated cell manufacturing base, while the rest import cells and assemble modules domestically.

Without any duty, the EPC cost of a solar project would be ~Rs19.7/Wp, which would increase to ~ Rs 22.2 /Wp in case of a duty on module and invertor imports. Factoring in a duty on the import of solar cells, glass and aluminium frames, with domestic assembly of modules, the EPC cost rises to ~ Rs 26/Wp.

Duties on solar glass and anodised aluminium frames will push up the module cost by Rs 2.2 Wp and Rs 0.25/Wp, respectively, taking it to Rs 14.2/ Wp ($0.16/Wp). China-made modules are currently priced at $0.08-0.09/Wp.

The impact of import duties on the market has been multifaceted. While there is an impact on cost, the duties have encouraged domestic manufacturing, with companies investing heavily in solar manufacturing, enabling self-reliance and avoiding geopolitical risks.

To achieve its renewable energy targets sustainably and cost-effectively, India must navigate the challenges and opportunities presented by import duties, striking a delicate balance between promoting domestic manufacturing and ensuring the affordability of renewable energy.

The UN Climate Change Conference (COP29) at Baku, Azerbaijan, concluded on November 22, 2024, on a disappointing note as countries failed to take decisive action to address the escalating climate crisis.

One of the most critical aspects of the conference was the New Collective Quantified Goal target for climate finance, which was to be revised after 15 years. Developing nations had sought a significant increase in climate finance to $1.3 trillion per year. However, the final agreement settled on a paltry $300 billion per year till 2035.

India was quick to reject the new target, calling out developed nations for proposing an abysmally poor amount.

The climate finance target of $100 billion per year, set in 2009, was met for the first time in 2022 (see figure below).

Figure: Climate finance mobilised in recent years

Source: OECD

A closer look at the sources of funds for the target reveals several issues, including lack of transparency, inconsistent reporting, and unclear country contributions. Moreover, the target failed to account for inflation and gross national income growth, which implied that its value had been eroded over time.

Had the target kept pace with inflation and economic growth, the obligation should have been around $150 billion by 2024 and $220 billion by 2035, leaving $80 billion as the actual additional funding required to meet the new target.

Historically, one-third of the target was achieved by simply rebranding and redirecting the existing financial support, rather than providing new or additional funding. In 2022, less than a third of climate finance funding was provided in grants, with the majority consisting of loans, equity, guarantees, export credits, and other financing vehicles, a situation that remains unchanged to date.

In the new agreement, there is lack of emphasis on new funding, which again risks diversion of existing development funding from other critical programmes devoid of climate components.

To be sure, a significant breakthrough was achieved with the issuance of guidelines and standards for the carbon market for bilateral and multilateral trading.

However, several critical issues remain unresolved, including the lack of uniformity in carbon trading frameworks across countries and the unconditional continuation of Clean Development Mechanism credits under the Paris Agreement’s Carbon Market without additional scrutiny.

Also, the issue of ensuring additionality in projects, which is essential to prevent double counting and ensure environmental integrity, was not addressed.

Climate negotiations have fallen into a familiar pattern of discord and compromise, leaving many countries feeling disillusioned and frustrated. Further, the leadership of Trump in the US, a significant emitter, could have a chilling effect on global climate action.

The persistent lack of support for climate finance has undermined the ambition of nations, with India, for instance, warning that its emission reduction plans will be scaled back due to inadequate funding, as it prepares to revise its Nationally Determined Contributions next year.  

The renewable energy (RE) sector has seen the emergence of a hierarchy among players over the years, with those consistently participating in allocations leading the pack. The initial decade of the sector’s growth, therefore, was also a period of stabilisation, establishing the successful players who grew with the sector.

That dynamic has, however, started changing in the almost-commoditised standalone solar vertical. Setting up solar farms with overflowing supply chains has become a quick target for a variety of entities looking to diversify. The established players, on their part, are actively looking to expand into, and are regularly featuring in, new project structures now requiring storage and complex configurations. Such project structures can be set up with storage or without (a solar-wind combination).

Hybrid models without storage saw a limited number of tenders till fiscal 2022, with around 90% of the tenders for such projects allocated in fiscals 2023 and 2024. Hybrids with storage followed a similar trend, with 90% of allocations occurring in the past two fiscals. However, the overall capacity allocated for hybrids with storage was only about a third of that allocated for hybrids without. The added complexity of integrating storage into hybrid projects requires thorough simulations to optimise the system and remain competitive, making it an even more niche market.

Looking at the unique count of players, the highest participation between fiscal 2022 and the first half of fiscal 2025 was in standalone solar, at 53 developers. Wind projects followed with 43 developers and hybrid projects with 30. Hybrid projects with storage saw the lowest participation, with 20 developers, as the project configuration is comparatively complex and capital intensive.

Figure: Projects allocated between FY22 and H1FY25

Source: Bridge to India – CRISIL MI&A ResearchNote: Only the projects allocated by central or state entities through reverse auction are covered; solar does not include KUSUM or agriculture-based projects

New entrants from other industries have diversified into the standalone solar market, such as Refex, which originated in chemicals and pharma, and Kintech Synergy, which transitioned from transmission project development. Energytech Fuels and Essar, both in the petroleum industry, have also entered the space. However, in terms of scale, only 15 developers, including Avaada, Adani Green Energy, ReNew and SJVN, have secured project allocations exceeding 1,000 MW since fiscal 2022 to the first half of fiscal 2025.

The wind segment presents a different picture, with most developers, except for JSW Energy, securing allocations of less than 1,000 MW. Around 60% of the developers, which won allocations under the reverse auction for standalone wind projects, have managed to aggregate cumulative capacity of only up to 50 MW over the period.

The wind engineering, procurement and construction (EPC) and operations landscape has shifted, with original equipment manufacturers no longer dominating the space. Players like Adani Green and ReNew have undertaken these operations and expanded their portfolios. This development is crucial for the growth of the hybrid market as well.

In the hybrid segment, mature players from the solar and wind segments have secured most allocations. However, around one-fourth of the developers, such as Serentica Renewables and BrightNight, are only participating in hybrid bids with or without storage, leveraging their expertise in the market characterized by lower competition and high market demand for flexible RE solutions. While hybrids have seen significant allocations, hybrids with storage are still evolving owing to the complexity of flexible RE configurations resulting in high prices.

Player participation is also a factor of the market environment. Significant price volatility in the solar market in fiscals 2022 and 2023 resulted in project delays and cancellations. Many companies opted out of the competitive bidding process during this period. For instance, Torrent Power, a prominent power sector conglomerate, instead focused on expanding its portfolio through acquisitions. However, with the solar market now stable, Torrent has won projects totalling over 750 MW in 2024 alone, nearly tripling its portfolio.

The renewable energy market, therefore, has not only grown significantly in  the past few years, but has also seen the competitive landscape evolve. Initially, players were competing to achieve scale, but the market is now slowly moving towards expertise and competitive advantages, with higher intensity in commoditised verticals. Higher participation and the increasing focus on expertise are both likely to drive the sector’s development.

The Ministry of Power has proposed amendments to its guidelines for tariff-based competitive bidding with an aim to streamline procurement of power from renewable energy (RE) projects. These include the guidelines for firm and dispatchable power projects with energy storage notified on June 9, 2023, solar projects notified on July 28, 2023, wind projects notified on July 26, 2023, and wind-solar hybrid projects notified on August 21, 2023.

The amendments proposed are as follows:

The tendering agency may specify a substation for the project

Power purchase agreement (PPA) can be of 25 years, or a shorter period of 15 years

Failure to meet minimum supply criteria for three years can result in a default, resulting in lowering availability from the contracted capacity or terminating the PPA

Developers must install and maintain a GPS-enabled automatic weather station (AWS) that meet technical specifications and standards

Distribution licensee/intermediary procurer must approach the Appropriate Commission for the adoption of tariff within 15 days of accepting the letter of award

Insurance Surety Bonds can be used as an alternative to Bank Guarantees for Earnest Money Deposit and Performance Bank Guarantee (PBG)

PBG will be returned to the generator within 45 days of actual supply commencement

Deviations from guidelines require approval from the Appropriate Commission and not government

Of these, the proposal to consider a 15-year PPA tenure can impact tariffs due to the life of assets extending to 25 years.

In fiscal 2024 and the first half of fiscal 2025, the tariffs discovered for solar, wind and solar-wind hybrid averaged at Rs 2.77/kWh, Rs 3.61/kWh and Rs 3.51/kWh, respectively, for a 25-year PPA tenure. Further, hybrids with storage ranged from Rs 4.35 to Rs 4.98/kWh.

On assuming the levelised cost of generation for a RE project with a 25-year tenure to be Rs 3.00/kWh on an average, the tariff can potentially increase by Rs 0.10 to 0.30/kWh if the PPA tenure is reduced to 15 years. This is considering that for the remainder of the project, either an alternative buyer may step in at a reduced tariff rate or the plant operates as a merchant project.

Figure: RE tariff based on PPA tenure, Rs/kWh

Source: Bridge to India – CRISIL MI&A ResearchNotes: Tariff is calculated considering normative assumptions, including capacity utilisation factor of 22%, engineering, procurement and construction cost of Rs 35 million per MW and 75% debt at 9% interest.Additionally, during merchant operation, the revenue realisation is assumed at Rs 1/kWh.

A shorter PPA tenure elevates the offtake and utilisation risk for the asset, reducing investor confidence and increasing the cost of financing.

However, it offers advantage to offtakers as they would be locked into a contract for a shorter period. The shorter tenure allows them to adapt more quickly to evolving market conditions, such as fluctuations in demand or supply and adoption of newer, efficient technologies.

A shorter PPA tenure enables offtakers to reassess their energy procurement strategies and adjust to new market realities faster. The primary objective for offtakers remains a lower tariff as it directly impacts their bottom line. However, this impacts the appetite for supply and raises risk and tariffs in the sector.

Even though the 2023 guidelines permit tendering agencies to lower the PPA tenure from 25 to 20 years, most tenders to date continue to specify 25-year PPAs. Any new implementation of a reduced tenure would be a key monitorable.

Sharper policy focus has placed the rooftop solar segment in a sweet spot as India works towards meeting clean energy targets and bring down power costs.

In February this year, the government enhanced the central subsidy programme and announced a scheme to provide 1 crore households with rooftop solar power support. The scheme seeks to reduce initial capital costs through direct subsidies and easing regulatory hurdles to rooftop solar implementation.

The central drive is being supported by state regulatory authorities experimenting with several innovative structures to further address nuanced challenges of site availability, enhanced generation and group application to rooftop solar.

Several states have introduced innovative business models and metering arrangements for rooftop solar systems to promote growth in the sector. Karnataka and Delhi have introduced peer-to-peer (P2P) trading mechanism. Others, including Andhra Pradesh, Delhi, Madhya Pradesh, Maharashtra and Odisha, have implemented group net metering for all consumers. Delhi, Maharashtra, and Madhya Pradesh are also offering virtual net metering.

Under the P2P mechanism, those who have installed rooftop solar can sell power through a P2P portal, similar to trading green power on an exchange.

In Karnataka, P2P trading is restricted to residential consumers, while Delhi allows all consumers with a sanctioned load of up to 200 kW to participate. A dedicated service provider manages the technology for P2P transactions and charges a transaction fee to consumers. Accordingly, Karnataka levies a fee of Rs 0.14/kWh, which is higher than the fee charged by the Indian Energy Exchange (Rs 0.02/kWh). Consumers are also required to pay open access (OA) charges except when the prosumer and consumer are connected to the same substation.

Moreover, these consumers must submit their power generation schedule in advance, a stipulation that could deter residential consumers due to its complexity and capabilities required to forecast generation. Any deviation from schedule attracts penalties. In case of under-injection, the seller is required to compensate the buyer with difference of mutually agreed price on the P2P portal and grid tariff paid to the distribution company (discom). Buyers who under-draw are required to compensate the seller as per the mutually agreed price on the portal.

The P2P model, though innovative, has its limitations. In Karnataka, residential consumers prefer procuring power from discoms as it is cheaper compared with the P2P portal. In Delhi, consumers may find the model more attractive given high grid tariffs and exemption from OA charges.

It will also make economic sense for rooftop solar installers to sell surplus power through a P2P portal as they will secure better rates compared with what discoms offer for surplus injection (tariff for surplus power in Delhi is Rs 2.92/kWh, Karnataka: Rs 2.60/kWh). Additionally, time-of-day (TOD) tariffs may enhance the financial appeal of P2P for residential consumers. But there are doubts this would generate significant interest. Installers will first prefer offsetting their own expensive grid power with rooftop solar power than engaging in P2P complexities.

Figure: Landed cost of P2P power compared with grid tariffs, Rs/kWh

Source: Bridge to India-CRISIL researchNote: i. One-year average market clearing price discovered on IEX assumed as P2P tariff. ii. Grid charges are calculated for LT consumers.

Group net metering and virtual net metering are more viable alternatives as they address the key challenge of unavailability of suitable rooftop space, which is often a constraint for commercial and industrial (C&I) consumers. Both mechanisms are designed to enable multiple power consumers to benefit from a shared rooftop solar system.

Group net metering lets multiple consumers on the same distribution network to share benefits of a jointly-owned rooftop system by distributing power credits among them. In virtual net metering, consumers receive credits from a remotely located shared system that allows those without suitable onsite conditions to offset their power consumption.

Madhya Pradesh has recently introduced both mechanisms for all consumers with a maximum project capacity of 100 kW. However, the state does not provide any incentives for these mechanisms unlike Andhra Pradesh which provides 100% exemption from transmission and wheeling charges and losses.

Several C&I consumers such as petrol pumps and bus depots that lack proper rooftop space can install a ground mounted solar system in other available spaces. This will allow them to avail benefits of solar power, without getting into complexities of open access, and benefit from the waiver on OA charges. This is attractive for consumers with small or distributed loads. Consumers can avail the benefit of net metering, while discoms get to retain their consumers who might otherwise switch to open access. Additionally, discoms can meet their renewable purchase obligation targets.

While adoption and implementation of these mechanisms are still in early stages, discoms should be lauded for their innovation. Refining these models can unlock the untapped potential of rooftop solar.

The government’s decision to remove the waiver of Inter State Transmission System (ISTS) charges for renewable energy (RE) generation projects will push up the costs for developers and consumers.

The waiver, aimed at promoting RE and reducing the overall cost of these projects, was first implemented in 2018 under the National Tariff Policy and extended to solar and wind power projects commissioned before December 31, 2022. The government later extended the waiver to include projects commissioned by June 30, 2025.

Now, with ISTS waiver being removed in phases for projects commissioned after June 2025, the transmission charges will have to be borne by the developers and, in turn, by consumers as tariffs may rise.

The hike will take RE tariffs closer to conventional energy sources, though still cheaper, thus reducing their price attractiveness a tad. Sans the waiver, RE off-takers must account for additional costs, impacting overall project economics.

While the waiver will be removed for most projects, in cases where project delays have been caused by transmission providers or other justifiable causes, as assessed, an extension of up to two periods of six months each may be granted to developers.

Notably, projects for green hydrogen or green ammonia plants will continue to enjoy the waiver until 2032 and 2030, respectively.

Table: Levy of ISTS charges on solar, wind, hydro PSP and BESS

Source: Ministry of Power; PSP – pumped storage plant; BESS – battery energy storage system

That still leaves most RE developers to contend with higher tariffs, and resultantly, skewed project economics. To address the challenge, developers will need to optimise project locations. While solar resources are widely available across India, wind resources are more concentrated in just six states, which hold ~90% of the country’s wind potential. States with lower renewable resource potential typically rely on ISTS connected projects.

Figure: Landed costs for an open access (third party) RE project with ISTS charges

Source: Grid-India, SERC tariff orders, Bridge to India – CRISIL MI&A ResearchNotes: • Landed tariff is the rate of power paid by the consumer. The calculation includes power purchase cost plus charges applicable to consumers connected at up to 33 kV • Open access charges include state transmission utility charges and losses, wheeling charges and losses, cross-subsidy surcharge and additional surcharge along with ISTS losses • ISTS charges are calculated based on the average of the past 12 months’ transmission charges as published by GRID India. The per-unit charge is determined by dividing the total transmission charges (without waiver) by the energy generated from the RE project at 30% capacity utilisation factor.

On average, ISTS charges, calculated based on the previous 12 months, can lead to an increase of Rs 1.4 to 1.8 per unit in the landed tariff. This amount is equivalent to around half of the base tariff for RE alone, which is Rs 2.6 to 3.6 per unit.

To mitigate the effect of transmission charges, developers should focus on strategies to enhance transmission asset utilisation.

Co-locating RE projects, such as combining solar and wind projects or integrating energy storage systems with renewable energy, can reduce the impact of these charges. For example, by achieving a capacity utilisation factor of 50% through oversizing and integrating energy storage, generators can reduce the impact of transmission charges by 40% on a per-unit basis.

Hence, the reimposition of ISTS charges will have a significant impact on the landed price of RE for open access consumers. The increased cost from ISTS transmission charges will close the gap between renewables and coal assets, and the industry will need to optimise project locations and improve generation efficiency to maintain current levels of attractiveness.

Tendering and allocation of renewable energy (RE) projects have slowed down this fiscal, indicating a possible loss of momentum in commissioning next fiscal. After an impressive show last fiscal, when a total of 101 GW of RE capacity was tendered and 60.2 GW allocated, in the first of this fiscal only 36 GW has been tendered and 3.5 allocated. If the trend continues, it is likely to have a bearing on the RE generation targets set by the government.

The government has set an ambitious target of achieving 500 GW non-fossil fuel capacity by 2030, of which 400 GW is expected to be from variable renewable energy (RE) sources, including solar and wind power. Currently, the installed capacity of solar and wind power combined stands at 136 GW, leaving a gap of more than 260 GW to be tendered by fiscal 2028 to meet the 2030 target.

In a bid to accelerate the transition to RE, the government has designated four Renewable Energy Implementing Agencies (REIAs) — Solar Energy Corporation of India (SECI), NTPC Ltd, NHPC Ltd and SJVN Ltd — to float tenders and identify states for power procurement from the awarded projects. As per the Ministry of New and Renewable Energy’s (MNRE) bidding calendar, 50 GW of RE projects (10 GW of wind capacity and 40 GW of solar, hybrid and round-the-clock etc) are to be annually tendered over fiscals 2024-2028.  

Despite this, RE allocations this fiscal have not yet crossed 50% of the fiscal 2024 level.

Figure: RE capacity tendered and allocated

Source: Bridge to India – CRISIL MI&A ResearchNotes: 1. RE includes solar PV, wind and hybrids of solar and wind, with or without storage. Other RE includes floating solar, canal top solar and offshore wind.2. Capacity allocation is represented based on tender issuance year, not result announcement year.

A closer look at the tendering and allocation data reveals that solar ground-mounted capacity has been the most successful, with a 67% allocation rate last fiscal and 15% in the first half of this fiscal. Hybrid energy configuration, a combination of solar and wind, has also performed well, with a 73% allocation rate last fiscal and 9% in this fiscal first half. Hybrid with storage saw 60% allocation in fiscal 2024 and none in the first half of fiscal 2025. Wind onshore capacity is struggling, with a mere 12% allocation rate last fiscal and no allocation in the first half this fiscal.

The attractiveness of the RE segment hinges on competitiveness of tariffs. Solar, with an average tariff of Rs 2.77/kWh, accounts for the largest share of tendered and allocated capacity. Hybrid energy (excluding storage), with an average tariff of Rs 3.51/kWh, comes second, followed by hybrid with storage, with tariffs between Rs 4.35 and Rs 4.98 per kWh and wind energy with a tariff of Rs 3.61/kWh on average. Thewind segment, however, is more plagued by execution issues.

According to the Central Electricity Authority’s Power Supply Report, energy supplied in fiscal 2024 was 1,622 BU, with renewable energy accounting for 365.6 BU. At the national level, this translates to a RE procurement of 20-22%, after accounting for system losses, which is below the target set by the Union Ministry of Power (MoP) for 28.07% renewable purchase obligation (RPO). By fiscal 2027, when the capacities allocated in fiscals 2024 and 2025 will become operational, the mandate is to have 35.95% of the energy supply from RE sources, accentuating the wide gap that requires to be bridged.

In a concerted effort to establish a facilitative framework for promotion of RE, the MoP has introduced the Uniform Renewable Energy Tariff (URET) mechanism. The innovative approach aims to mitigate the risks associated with price volatility and encourage the procurement of RE to meet the RPO. As part of this, the ministry launched URET pools for solar and solar-wind hybrid projects in February 2024, which will remain open for three years.

Under the URET mechanism, until September these fiscal, intermediary procurers have tendered 5.3 GW of solar capacity (2.9 GW already allocated) and 6.4 GW of solar-wind hybrid capacity (2.8 GW allocated).

Net-net, while India has made significant progress in its RE journey, an urgent ramp-up in momentum is required to meet its targeted goals. This would mean identification of measures to improve allocation rates and speed up execution. 

Regulatory clarity on long-duration power storage augurs well for the sector

India’s rapid transition to renewable energy has made energy storage a crucial component for grid stability and integration of intermittent renewable energy sources into the grid. Pumped hydro storage (PHS) offers a flexible and efficient long-duration energy storage solution, essential for the country’s renewable energy strategy.

The National Electricity Plan 2023 projects India’s energy storage capacity requirement at approximately 74 GW/411 GWh by fiscal 2032, with 27 GW/175 GWh from pumped storage plants (PSPs) and the remaining from battery energy storage systems.

As of April 2024, India’s installed PSP capacity stood at 4.7 GW, with 3.3 GW currently operational. The Central Electricity Authority (CEA) estimates the country’s total potential for PSP capacity at about 134 GW, comprising 60 GW and 74 GW of on-river and off-river PSP projects, respectively.

Plans are underway to add PSP capacity of 1 GW in the northern region and 1.7 GW in the southern region by FY27. Moreover, approximately 60 GW of capacity are currently being surveyed and investigated, with 19.2 GW of that needing to be operationalized by fiscal 2032 in order to meet the CEA plan.

Figure: Region-wise PSP capacity addition plan until fiscal 2032 as per CEA (MW)

Source: CEA; Bridge to India – CRISIL MI&A Research

To facilitate the development of PSPs, the Ministry of Power issued draft guidelines on August 22, 2024, for the procurement of storage capacity or stored energy from PSPs through a competitive bidding process.

The guidelines outline two modes of procurement:

Mode 1 involves procurement from a PSP developed on a site pre-identified by the procurer. The project will be developed on a build-own-operate-transfer (BOOT) basis for a term of 25-40 years. The procurer will form a special purpose vehicle (SPV) to handle pre-feasibility activities, including clearances and land procurement. The indicative timeline for commencement of the storage schedule is 48 months and 66 months for on-river and off-river PSP projects, respectively.

Mode 2 involves procurement from a PSP developed on a bidder-identified site or an existing commissioned PSP. The project will be developed on a fuel-offer-own (FOO) basis for a period of 15-25 years. The bidder will submit the approved detailed project report (DPR) before signing the power purchase agreement (PPA). The timeline for commencement of the storage schedule will be as per the procurer’s requirement.

The guidelines also specify the bidding parameters, including storage charge or tolling tariff, storage charge with a specified pre-viability gap funding (VGF)/annuity support, and composite tariff. The minimum bidding capacity is 50 MW for inter-state transmission system (ISTS)-connected projects. It is 10 MW for intra-state transmission system (InSTS)-connected projects, except those in the north-eastern region (NER) states.

These guidelines come at a time when the tariff framework, specifically for PSPs, is inadequate. States such as West Bengal, Maharashtra and Telangana have their own specific regulations, while others lack a tariff framework that differentiates between hydro and PSP projects.

Key differentiating provisions are needed to distinguish between hydro and PSP projects, including accounting for the cost of pumping energy within the tariff framework and offering incentives for peak shaving over and above normal tariffs.

The draft guidelines for the procurement of storage capacity from PSPs through competitive bidding are a step in the right direction. This allows developers to set tariffs through a fair and established process, consistent with the other clean energy segments.

The guidelines bring much-needed clarity and enable fair compensation, unlike current policy structures that treat PSP capacity on par with normalised hydro supply. That said, policy innovations to also give an option to use PSP as an ancillary service would add another crucial dimension to the tariff framework.

New players, capacity expansion boost market in India

India’s solar glass market is heating up as recent policy changes, aimed at bolstering domestic production, encourage multiple players to enter the fray.

Among the policy measures, the Ministry of Finance has imposed a 10% basic customs duty (BCD) on import of solar glass effective October 1, 2024, citing sufficient domestic manufacturing capacity in progress. To recall, the anti-dumping duty imposed in 2017 by the government on imports of solar glass in a bid to safeguard the domestic industry had expired in 2022.

In fiscal 2024, India’s imports increased by 1.8 times compared with fiscal 2023 to 111 million sqm. China and Vietnam accounted for 98% of the imports. The import price of solar glass from China, too, dropped 22% in fiscal 2024 and 10% in first quarter of fiscal 2025, with prices of Vietnam-origin glass declining 14% and 11% in these periods, respectively.

In response to concerns over unfair pricing, in February 2024, the Directorate General of Trade Remedies initiated an anti-dumping investigation into solar glass imports from China and Vietnam. The probe followed an application submitted by India’s leading player, Borosil Renewables, supported by other domestic manufacturers, which provided prima facie evidence of dumping and the subsequent adverse impact on the domestic solar glass industry.

Figure: Import of solar glass increased by 4.7 times between FY21 and FY24

Source: Department of Commerce, Government of India; Bridge to India – CRISIL MI&A ResearchNotes: 1. Imports of solar glass is assessed for HS code 70071900;2. Pricing data is estimated using import quantum and total value as reported by Department of Commerce

In fiscal 2024, the fall in price of solar glass can be mainly attributed to the substantial 30% decrease in the cost of soda ash, a key input material. However, the cost remained relatively stable in Q1 FY25. Currently, Chinese solar glass amounts to ~RMB 13.5/sqm (INR 160/sqm) for 2mm glass and RMB 22.5/sqm (INR 265/sqm) for 3.5 mm glass, while domestic solar glass costs INR 220-360/sqm. The 10% BCD on imports puts domestic glass in a competitive position.

Figure: Solar glass prices dropped 6% in Q1 FY25 from Q4 FY24

Source: Industry sources, Bridge to India – CRISIL MI&A Research

Table: Solar glass manufacturing capacity in India

Source: Company presentations, media reports, Bridge to India – CRISIL MI&A Research

Borosil Renewables has an operational capacity of 1,000 TPD, which is sufficient for 5-6 GW of solar module production. While the company is planning to further expand the capacity by 1,100 TPD, it is on hold due to uncertainty over solar glass import duties and module price volatility. In addition, small players, such as Gobind Glass and Emerge Glass, can support an additional 2-3 GW of solar module production as on date. However, it is worth noting that India’s current solar module manufacturing capacity has already surpassed 50 GW.

New entrants in the solar glass manufacturing sector represent a mix of established glass manufacturers and companies from adjacent industries. Gold Plus Glass Industries is diversifying its portfolio to meet the rising demand for solar glass, while Vishakha Renewables is integrating backward to secure its supply chain. Chirpal Group and Treveni Glass, with backgrounds in construction and materials, are leveraging their expertise to enter the solar glass market.

The 10% BCD on imports, combined with the ongoing anti-dumping investigation, suggests a policy shift towards self-reliance. Based on the existing and planned capacities, India’s solar glass manufacturing capacity can support 12-15 GW and 20-23 GW of solar module production by the end of 2024 and 2025, respectively. This will reduce dependence on imports and provide a competitive edge to local manufacturers.

Demand for batteries is on the rise due to their widespread application in electronics, electric vehicles, renewable energy integration, data centres and many other sectors. Lithium-ion based batteries dominate the battery energy storage (BES) market due to their high energy density, long cycle life and declining costs. Key components of these batteries include lithium, cobalt, nickel, manganese and graphite.

India has substantial reserves of graphite in Jharkhand, Arunachal Pradesh and Tamil Nadu. Limited quantities of cobalt and nickel, often occurring alongside copper ores, have been found in Odisha and Jharkhand. However, India does not have operational mining leases for lithium and largely depends on imports, though lithium reserves have recently been discovered in Karnataka and Jammu & Kashmir.  

Globally, the ‘Lithium Triangle’ of South America – including Chile, Argentina and Bolivia – has the largest deposits of the mineral.  Australia and China also hold significant reserves. These regions are key to the global lithium supply chain. As per 2024 Statistical Review of World Energy by Energy Institute, the Lithium production has more than doubled over the past three years reaching 198 kt in 2023. Further, International Energy Agency (IEA) estimates the demand to reach 530 kt by 2030.

Volatility in price, however, hinders decisions on new supply investments. As seen in February 2024, when production at Australia’s Greenbushes mine slowed, other producers reviewed their operations. High production costs could further pressure prices, making it difficult to secure long-term supply agreements.

There are geopolitical factors at play as well.

Take cobalt, for instance. The mineral, essential for improving battery life and energy density, is primarily produced in the Democratic Republic of Congo (DRC), which accounts for about 70% of the world’s supply. Australia and Russia also contribute, but the heavy dependence on the DRC poses risks due to political instability in the region. The high concentration of cobalt mining in the DRC and ownership by foreign entities poses supply security risks. Recent disputes between the DRC government and foreign miners, such as the suspension of CMOC’s TFM mine in July 2022, highlight these challenges. The mine resumed operations in April 2023 after a $2 billion settlement. In April 2024, the DRC suspended nine subcontractors at Eurasian Resources Group’s mines, indicating ongoing supply risks due to tensions between the DRC and foreign miners over resource ownership.

Cobalt demand in 2023 was 215 kt with sufficient market supply. Going forward, the IEA estimates an uptick of around 60% in demand, limited only by the shifting market preference towards low-cobalt or cobalt-free cathodes.

Figure: Major producers of critical minerals in 2023 (tonnes)

Source: Energy Institute – 2024 Statistical Review of World Energy

Against this backdrop, India is actively pursuing a strategic approach to secure a stable supply of critical minerals, essential for its burgeoning electric vehicle and renewable energy sectors. The Union Ministry of Mines projects cobalt consumption to increase from 17 tonne in 2025 to 3,878 tonne by 2030. Similarly, lithium consumption is estimated to surge from a mere 58 tonne in 2025 to 13,671 tonne by 2030.

To address these supply chain risks, the government established Khanij Bidesh India Limited (KABIL) in 2019. KABIL is mandated to acquire overseas mineral assets and has already initiated projects in Australia and Argentina. KABIL has secured exploration and exclusivity rights for five lithium brine blocks in Argentina’s Catamarca province, marking India’s first overseas lithium mining venture.

Concurrent with these efforts, industry is exploring alternative battery chemistries to mitigate the risks associated with critical mineral supply chain disruptions. Solid-state and sodium-ion batteries are emerging as potential substitutes for lithium-ion batteries. Furthermore, investing in recycling infrastructure is crucial to recover valuable materials from end-of-life batteries, reducing the demand for primary resources.

Up till the middle of 2023, solar module manufacturers were in a race to expand capacity, buoyed by sunny projections of demand. Then, module prices started declining as four headwinds – excess production, severe competition, technological advancement and falling raw material costs – coalesced, cooking up a perfect storm.

Global module manufacturing capacity stood at 800 GW at the end of 2023, far exceeding the addition of 407 GW in solar generation capacity. And in 2024, global manufacturing capacity is forecast to touch 1,100 GW, while installations are expected to remain below 500 GW, obviating any possibility of a letup in the trend. The excess capacity and expanding inventory will likely keep prices low through this year.

By the second quarter of 2024, the average global price of mono-crystalline modules, the more widely deployed technology, had plummeted 50% to $9.50/watt (W), down from $19.3/W in the corresponding period a year ago. The downward spiral also reflected in domestic module prices, which decreased 38% to $18/W from $29/W over the period.

Also affecting the business prospects of module manufacturers is a sharp fall in the price of polysilicon, a key raw material, which plummeted to a record low of $4.36/kg in July 2024 from $16/kg on average in the second quarter of 2023.

All this has put considerable pressure on the financial health of solar manufacturers and squeezed their profit margins—particularly for Chinese manufacturers, which dominate the global market.

Figure: Most Chinese PV manufacturers facing margin pressure since second quarter of 2023

Source: Company financial statements

Most Chinese manufacturers reported losses in the fourth quarter of 2023, which continued into the first quarter of 2024. And no respite is likely anytime soon. Module prices are expected to continue to trend at these low levels owing to sustained intense competition within China as well as new manufacturing capacity being commissioned in other countries.

To cope with the financial strain, manufacturers are exploring all possible avenues:

Industry consolidation: Low prices, impacting profitability has led to cancellation or suspension of new production capacity aggregating to 59 GW between June 2023 and Feb 2024 alone. To curb overinvestment in the sector, China’s industry ministry issued draft rules in July 2024 increasing the minimum capital ratio for new projects from 20% to 30%.

Technological innovation: Also, solar manufacturers are pursuing technology innovation. Companies are accelerating their transition from passivated emitter and rear contact (PERC) solar cells to tunnel oxide passivated contact (TOPCon) panels, with PERC technology expected to be largely phased out by 2025

Transition to n-type: The industry is seeing largescale shift towards n-type modules as well, with two out of three modules shipped in 2024 expected to be based on this technology. n-type modules, particularly those based on TOPCon technology, are proving more popular owing to their superior performance

It is noteworthy that despite the low prices, Chinese manufacturers aim to continue their dominance with improved technology.

TOPCon is quickly dominating the market, with over 90% of manufacturing capacity located in China. This poses a challenge for manufacturers in Western countries and in India, where most capacity is still based on the soon-to-be-obsolete PERC technology. Therefore, while the sharp fall in solar module prices has led to financial challenges for manufacturers, it has also catalysed significant market adjustments and technological advancements. Leading manufacturers are leveraging scale and innovation to navigate the current turbulence, while smaller players must adapt quickly to survive.

The full Union Budget for this fiscal has provided a much-needed impetus to the clean-energy sector through direct capital support, lower taxation on inputs and policy initiatives for segments that are underperforming, underdeveloped or critical for future power systems. To put this into perspective, the government has allocated Rs 19,100 crore to the Ministry of New and Renewable Energy this fiscal, an increase of 86% from Rs 10,222 crore last fiscal.

Figure: Budget allocation to energy sector vs Ministry of New and Renewable Energy

Source: Ministry of Finance

The solar rooftop segment, which was preventing the government from achieving its target from long, has received a fillip from the PM Surya Ghar Muft Bijli Yojana. Though commercial and industrial consumers drove capacity addition in solar rooftop due to attractive project economics, the much larger but smaller-scale residential segment kept away because of high capital costs and tedious procedures. 

For the energy storage segment, especially batteries, the government has offered direct fiscal support and reduced taxation on critical inputs. While viability gap funding (VGF) would enable only a small quantum of capacity addition, this would contribute to the 25-30 GW needed to manage power systems by 2030.

Through the Interim budget, The government has also increased the allocation for the green energy corridor from Rs 434 crore to Rs 600 crore to ensure grid adequacy for renewables.

Figure: Summary and impact of key announcements for the energy sector

In line with India’s Nationally Determined Contributions, clean energy has always been on the government’s agenda. That said, the government realises that a power-intensive economy such as India will remain dependent on coal in the foreseeable future. Against the backdrop of unprecedented growth in power consumption and record peak demand, the government has announced direct fiscal support for two coal projects. One is to tackle the power deficit in Bihar. The other is to establish the advanced ultra supercritical (AUSC) coal technology across the country for a more efficient coal fleet.

The government is also focusing on the nuclear segment, aiming to increase nuclear capacity from present 8,180 MW to 22,480 MW by 2030. Further, adoption of new technologies such as small modular reactors can help tackle the challenges in the development of large-scale and complex nuclear projects.

To meet India’s growth needs, the budget has looked to strike an optimum balance between renewable energy and fossil fuel, while enabling a smooth transition to renewable energy by providing adequate resources for system integration.