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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.

Prompt implementation of the Resource Adequacy Framework guidelines issued by the Ministry of Power in 2023 by all states is crucial for improving planning and resource management in the power sector. That would ensure a coordinated response to demand variations and enhance the reliability of power supply in the context of estimates that India’s peak power demand could surpass 400 GW by fiscal 2032. Demand hit an all-time high of 250 GW in May 2024, up substantially from 224 GW recorded in summer months (April to June) of 2023, led by soaring summer temperatures and the country’s rapidly growing energy needs. The estimates are significantly above the forecasts of the Central Electricity Authority (CEA), notified in 2023 in the National Electricity Plan for generation up to fiscals 2032, that project peak demand will touch 277 GW by fiscal 2027 and 366 GW by fiscal 2032, compared with the peak of 203 GW logged in fiscal 2022.

As demand surges, power distribution companies (discoms) are increasingly struggling to maintain stable power supply amid power deficits and often relying on expensive spot power purchases or enforcing power cuts. Some states have even asked consumers to voluntarily reduce power consumption during peak hours. For instance, Rajasthan recently announced intermittent power cuts in industrial areas between 8 PM and 3 AM, urging industries that operate around the clock to limit their load to 50%. Similarly, in 2023, Karnataka invoked Section 11 of the Electricity Act that mandates private generators to supply power exclusively to state discoms to manage its power deficit.

While such measures enable states to address their power crisis in the short term, prolonged implementation of these measures could have adverse economic implications, potentially affecting industrial productivity. The increasing integration of renewable energy, especially solar power, has intensified the challenges for discoms. While solar energy contributes significantly during daytime, the usual peak demand occurs in morning and evening hours. Providing round-the-clock supply is crucial for discoms, but consumer affordability is also key. Therefore, discoms rely minimally on the expensive spot market and impose time-of-day tariffs to encourage consumers to shift their consumption to time periods when sufficient and affordable power is available. In 2024, peak demand in April, May and June shifted more to daytime at the national level, especially in the northern region. The western and southern regions also saw an increase in daytime peak demand compared with 2019, whereas the eastern region continued to experience nighttime peaks.

Figure: Peak power demand and time in summer months of 2019 vs 2024

Source: GRID-INDIA, Bridge to India-CRISIL research

To meet India’s rising electricity demand, the CEA issued guidelines in 2023 for a Resource Adequacy Framework that would improve planning and resource management in the power sector. The framework mandates regular demand assessment at the discom level and preparation of 10-year rolling plans for achieving an optimal generation mix. Accurate forecasting is key to the framework’s success and discoms must invest in robust mechanisms to enhance the precision of long-term demand projections. To ensure reliable power supply, the CEA sets a planning reserve margin (PRM) that acts as a buffer during unexpected demand surges or generation shortfalls. Resource adequacy is evaluated based on two criteria: the frequency and magnitude of outages within the generation mix.

The CEA requires timely inputs from all discoms and state load dispatch centres to formulate a precise long-term national plan. While the framework enables state regulators to impose penalties for non-compliance, many states are yet to notify the necessary regulations. As of June 2024, only Madhya Pradesh and Maharashtra had notified the regulations for implementing the framework, with the regulations in the draft stage in Karnataka, Tamil Nadu, Odisha, and Jharkhand. In the milieu, only a coordinated implementation of the framework by all states can help meet demand variations and enhance the reliability of power supply especially during peak hours.

The issue of the Green Energy Open Access (GEOA) rules by the central government in fiscal 2022 marked a watershed moment from a policy perspective for open access (OA) consumers. However, as of June 2024, only 13 states have fully adopted the rules, two states have partially adopted the rules, and one state has issued draft regulations. A key aspect of the policy, the banking provision, has seen the most deviation at the state level when compared with the central policy.

The policy mandated distribution companies (DISCOMs) to provide banking services on a monthly basis, subject to appropriate charges. [NG1] The Forum of Regulators (FoR) was mandated to determine an appropriate banking charge while ensuring that the interests of both open access consumers and DISCOMs were protected. FoR proposed an in-kind charge of 8% but without a quantitative methodology.  Though several states have aligned to the proposed charge, the state regulators have not provided any methodology or rationale. As a result, it remains unclear whether the proposed 8% charge accurately reflects the actual cost of banking with DISCOMs. Karnataka, based on its own study from 2022, has found that the cost of banking, on a monthly basis, ranges from 16.1% to 19.3% of the wheeled energy, equivalent to Rs 0.51–0.61 per unit for the state. The Gujarat regulator is also conducting a study to devise a proper methodology, and charges (currently Rs 1.50/ kWh) will be revised accordingly from October 1, 2024.

Source: Source: BRIDGE TO INDIA- CRISIL research

A similar dissonance can be seen in the threshold defined for the quantum of power that can be banked and the use of banked power depending on the time of day. The rules state that the permitted quantum of banked energy by the OA consumer shall be at least 30% of the total monthly electricity consumption from the DISCOMs. However, the lack of an upper limit creates planning challenges for DISCOMs, as the quantum of banked energy remains uncertain, potentially leading to disputes if DISCOMs restrict banked energy above certain thresholds. Delhi, Gujarat, Jharkhand, Madhya Pradesh, Telangana, and Uttarakhand require at least 30% of power consumption from the DISCOM. In contrast, Andhra Pradesh, Haryana, and Punjab allow up to 30% of consumption from the DISCOMs. On the other hand, Karnataka, Uttar Pradesh, Maharashtra and Tamil Nadu permit banking of up to 100% of generation.

While the GEOA does not impose any restriction on the use of banked power, most states have only allowed settlement of banked power in off-peak hours in the same slot.

Table: Permissible drawl of banked energy with respect to the time of surplus injection

*Allowed upon payment of additional charge over and above the usual banking chargesSource: BRIDGE TO INDIA- CRISIL research

Despite significant advancements in the energy banking framework, further refinement is needed to ensure the objective of eliminating disparities in state policies is achieved. Developing a methodology that accurately captures the cost of banking and takes into account the intermittent nature of renewable energy generation and time-of-day consumption is crucial. This approach will promote the adoption of renewable energy and ensure the financial viability of DISCOMs. However, in the long run, consumers would need to increase the adoption of round-the-clock RE solutions coupled with energy storage to reduce the dependency on DISCOMs for banking services.      

Retail tariff orders issued by state electricity regulators for this fiscal versus increasing power purchase cost is the big conundrum before distribution companies (discoms). Tariff orders are issued on a yearly or multi-year basis to determine the revenue requirements of discoms. The tariff estimation process typically involves review of past performance, estimation of power demand, cost of power purchases and other expenses related to power supply. While some states have maintained stable energy and fixed charges, the dynamics of power purchase costs and fuel surcharges have varied significantly across India.

The states that issued tariff orders for this fiscal are Haryana, Gujarat, Karnataka, Uttarakhand, Andhra Pradesh, Madhya Pradesh and Odisha. For consumers of Haryana, Madhya Pradesh, Andhra Pradesh, Gujarat and Odisha, there is no change in the variable or fixed energy charges. Uttarakhand has increased the tariff 6% for the residential category and 8% for the commercial and industrial (C&I) on-year. The cost of power purchase, meanwhile, increased 3% on-year. Maharashtra, through a multi-year tariff order, has raised around 3% on-year. Karnataka discom went the other way, reducing tariff by up to 14% for corporate consumers, while implementing a marginal increase for residential consumers. This is despite a 7% increase in cost of power purchase. The reduction in tariff for C&I consumers in the state has been achieved by reducing the cross subsidy to around 15%, aligning with the threshold of 20% of cost to serve, recommended in the Tariff Policy of 2016. This helps the discoms in the state recover the entire cost of cross subsidisation, even if the consumer shifts to open access. Further, lowering the cross subsidy will cut cross subsidy surcharge on open access consumers.

Figure: Retail supply tariff vis-a-vis power purchase cost (INR/kWh)

Notes: The tariff represent only the variable charges applicable to the consumer category; fixed charges, fuel surcharge and other charges are not included; charges are shown for HT industrial consumers connected at 33 kV level.Source: Retail Supply Tariff Orders; CRISIL-BRIDGE TO INDIA research

While many states have kept their tariffs unchanged, discoms recoup costs via fuel surcharge if fuel prices increase considerably, or if they had to purchase from the open market. For instance, the energy and fixed charges in Madhya Pradesh this fiscal remain unchanged on-year, despite an 8% increase in power purchase cost. However, consumers were subject to a fuel surcharge of 5.24% and 3.92% in April and May, respectively. This surcharge is applicable on entire fixed and variable cost bill of the consumers. Similarly, for Gujarat the power purchase cost increased 3% on-year. While there is no increase in energy charges, the regulator has approved an increase of 5% in the base rate of fuel surcharge to Rs 2.77 per kWh. Haryana, on the other hand, has seen a significant 20% on-year increase in the power purchase cost this fiscal. But no tariff increase has been proposed.

The diverse approaches taken by state regulators in issuing retail supply tariff orders highlight the complexity of balancing consumer affordability with the financial health of discoms. Rising costs can drive consumers towards open access, worsening discoms’ revenue losses. To counter this, they are exploring various strategies, including tariff cuts and green tariffs. While 17 states have implemented green tariffs, the uptake by consumers has been limited. This is because green power supplied by discoms comes at a premium, while consumers have the option to choose cheaper renewable energy sources through open access.

To remain competitive and retain consumers, discoms must reassess their approach to green power supply. While short-term tariff reductions can attract consumers, long-term strategies should focus on improving operational efficiency to reduce the cost of supply and restructuring of tariffs to ensure cost recovery. Moreover, creating a commercially attractive framework for green tariffs is critical for discoms to sustain their business while supporting the transition to cleaner energy.

India’s solar capacity addition in Q1 2024 grew 341% y-o-y to a record high of 7,918 MW, marking the highest ever capacity addition in a single quarter. Utility scale and open access (OA) projects accounted for 56% and 31% of new capacity addition respectively, followed by rooftop solar with 10% and the off-grid segment with 3%.

The surge in capacity addition was fuelled mainly by the rush to complete projects before reinstatement of the Approved List of Models & Manufacturers (ALMM) from April 1, 2024, coupled with record low module costs with Chinese and domestic mono-PERC module prices falling 50% and 43% y-o-y, respectively. Growth in the quarter was further spurted by delayed execution of projects that received multiple deadline extensions by the government.

Figure 1: Quarterly solar capacity addition by project type, MW

Note: Total solar addition in the first quarter of 2024 was based on a project sample of 6,918 MW, which forms 87% of the total additions in the quarter.Source: CRISIL-BRIDGE TO INDIA research

Gujarat (2,347 MW), Rajasthan (2,092 MW), Madhya Pradesh (745 MW) and Tamil Nadu (395 MW) were the leading states in terms of capacity addition. OA capacity grew 874 MW in Rajasthan, driven by inter-state projects set up for power supply to corporate consumers in other states, along with a 200 MW merchant project. Intra-state OA capacity addition is also expected to increase in the next few quarters as the state has begun providing approvals in recent months having resisted group captive projects historically.

Figure 2: State-wise split of ground-mounted projects in Q1 2024, MW

Source: CRISIL-BRIDGE TO INDIA research

We expect solar capacity addition of 11.2 GW over the next two quarters, driven in part by assured module supply, as developers stockpiled modules in anticipation of another ALMM waiver beyond March 2024. From October 2023 to March 2024, developers imported ~21.4 GW of modules, with Adani being the largest importer at 3,461 MW, followed by Tata Power (1,986 MW) and NTPC (1,607 MW) [estimated based on the sample size of import data]. The Ministry of New & Renewable Energy (MNRE) is expected to permit project commissioning with imported modules for projects awarded on or before April 10, 2021, or OA projects that applied for grid connectivity before October 1, 2022, provided the modules reached the site before March 31, 2024, and developer was unable to commission the project on account of unavoidable reasons.

Over the past two years, the biggest theme in the sector has been project delays due to module supply constraints. However, these constraints are likely to ease as domestic module manufacturing capacity is expected to increase from 61-63 GW at end-2023 to 76 GW by end-2024. Even after overlooking obsolete capacity and annual exports of 9 GW on average, domestic module availability, estimated at 26 GW in 2024, is expected to be sufficient to meet local demand.

Overall, the sector seems well placed for strong growth in the coming years. The biggest challenge now remains timely addressal of land and transmission issues. In this regard, the supreme court’s latest decision reversing its initial blanket ban on overhead transmission lines in Great Indian Bustard (GIB) habitat in Rajasthan and Gujarat, has come as a big relief to the sector.

The Central Electricity Regulatory Commission (CERC) fully operationalised the General Network Access (GNA) and Inter-State Transmission System (ISTS) Connectivity regulations in October 2022, ushering in a new era for India’s power sector. Given that sufficient time has passed since the inception of these regulations, we take a close look to evaluate the progress made so far.

Heralded as a transformative reform in India’s renewable energy sector, the regulations were designed to streamline the process for consumers to offtake power from the ISTS network and were widely expected to catalyse the ISTS open access (OA) market. The regulations govern ISTS connectivity for power projects and offer consumers non-discriminatory access to the network.

As per the portal launched by the Central Transmission Utility (CTUIL) in April 2023, the market is witnessing a strong surge in ISTS connectivity and GNA applications. As of April 2024, connectivity applications by renewable (RE) project developers exclusively focused on the OA market stood at around 14,932 MW with Serentica (3,750 MW), Amplus (1,925 MW) and AM Green (1,289 MW) accounting for the highest quantum.

On the consumer front, GNA RE applications cumulatively accounted for around 10,790 MW with AM Green Ammonia (2,360 MW), ArcelorMittal Nippon Steel (1,788 MW) and Reliance (1,647 MW) taking the top spots.

Figure: ISTS connectivity and GNA RE applications

Source: CTUIL, CRISIL-BRIDGE TO INDIA researchNotes: 1. The pie chart on the left is a subset of the total ISTS connectivity application quantum. The ISTS connectivity applications data has been selected for entities focused largely on the OA market.2. The pie chart on the right is a subset of the total GNA/GNA RE application quantum. The data has been selected on the basis of applicant profile and nature of application.

The heightened interest in the ISTS OA market can mainly be attributed to improved regulatory fundamentals, resulting from refinements made in two key areas:

Greater flexibility: Consumers are now allowed to procure power for different durations (short, medium and long-term) through a single approval. This is in contrast to the previous regime wherein consumers required separate transmission access grants depending on the duration of transactions.

Safeguards to prevent idle capacity accumulation: To minimise accumulation of idle transmission capacity, several safeguards have been implemented to ensure completion of projects—connectivity is contingent on submission of multiple bank guarantees, land ownership, financial closure and equity expenditure proofs by project developers. The ability to use a single GNA grant across procurement routes coupled with minimal idle capacity would lead to higher ISTS network utilisation and thus, reduce ISTS charges at a system level in the medium-to-long term.

On the procurement side, consumers are now required to obtain permission from CTUIL in the form of GNA approval (known as Long-term Access under the previous regime) prior to procuring power from the ISTS network. In the wake of ISTS waiver on RE power projects, the CTUIL is offering two GNA variants: i) GNA RE for procurement exclusively from renewable sources and ii) GNA for procurement from all sources.

Consumers are not allowed to avail of GNA and GNA RE simultaneously. While there is no upper limit on seeking GNA/GNA RE quantum for consumers, full ISTS waiver is only applicable subject to meeting respective minimum procurement requirements. Since GNA(RE) allows procurement only from renewable sources, minimum monthly average procurement requirement has been set at only 30% as opposed to 75% for GNA (see table below).

Figure: ISTS waiver calculation for each GNA variant

Source: CERC, CRISIL-BRIDGE TO INDIA research

Despite the catalysing impact of regulatory reforms on the ISTS OA market, capacity addition is expected to move in line with buildout of transmission capacity. While pan-India ISTS sub-station capacity for evacuation of power exclusively from renewable sources is expected to reach over 180 GW by June 2027, majority capacity is planned to be allocated to utility-scale projects.

We expect a total of 15-20 GW ISTS OA renewable capacity addition over the next five years. Despite phasing out of ISTS waiver in a graded manner (25% annually), capacity addition is expected to pick up gradually over the medium term owing to concerns around delays in sub-station capacity buildout.

The impact of application of ISTS charges on capacity addition will be monitorable – ISTS charges (INR 0.39-0.71/ kWh in 2023) are already on the lower side. This and the concentration of renewable sources in select states in the country will further drive demand.

On April 24, 2024, the American Alliance for Solar Manufacturing Trade Committee filed a petition with the US International Trade Commission and Department of Commerce, requesting imposition of anti-dumping and countervailing duties on solar cell imports from four Southeast Asian countries — Vietnam, Cambodia, Indonesia and Thailand (hereon referred to as SEA). All solar cell imports from SEA, including modules with cells sourced from the region, would come under the purview of this investigation.

The petitioner, along with signatories — seven major module manufacturers: Meyer Burger, First Solar, REC Silicon, Qcells, Convalt Energy, Mission Solar and Swift Solar — has alleged that cell and module supplies from SEA are injuring the domestic market and posing a risk to US indigenous manufacturing efforts. While the investigation is still in preliminary stages and duty rates are uncertain, the petitioners have reported dumping margins (delta between import and domestic US prices expressed as a percentage of import price) as high as 271.45%. This will serve as a reference point for establishing duty rates.

This intervention signals a significant shift in the dynamics of the global solar market.

This imposition of barriers to imports from SEA would prompt the US to seek alternative supply sources, especially as its domestic manufacturing capabilities are still scaling up. Total capacity as of end-2023 was just ~16 GW. US module imports reached 54 GW in 2023, up 82% on-year, with SEA accounting for around 84% of the total supply. However, a major portion of the manufacturing capacity in SEA is tied to suppliers from China, raising concerns about the continued high dependence on imports from China. Previously, the implementation of the Uyghur Forced Labor Prevention Act effectively barred all imports produced by forced labour (including upstream components that may be assembled elsewhere) from the Xinjiang Uyghur Autonomous Region in China (home to over 90% of China’s polysilicon capacity).

These developments present a significant window of opportunity for Indian manufacturers to capitalise on. While India does have substantial manufacturing capacity, a thorough analysis is needed to determine the extent to which it can meet additional demand from the US. We estimate India’s module export appetite at 9-10 GW per year over the next 2-3 years. In the first quarter of 2024, the US was buying modules at USD 0.30-0.32/W (expected to rise following the imposition of trade barriers), representing a premium of over 50% relative to modules sourced from India. Therefore, the anticipated higher prices and limited competition in the US market are expected to create a potentially lucrative export opportunity for Indian manufacturers.

Figure: US module import and price trends

Source: US Energy Information Administration, S&P Global, CRISIL-BRIDGE TO INDIA research

This shining opportunity comes with a challenge, though: Since a large proportion of India-made modules use cells sourced from SEA and China, it raises the risk of facing regulatory scrutiny or duties when exported to the US. In 2023, due to nascent domestic cell manufacturing capacity, India’s module production volume outpaced cell production volume by over 5x. The remaining demand for cells was met through imports, primarily from China (67%) and SEA (33%). Given this heavy reliance, India faces a looming risk of being added to the anti-dumping duty list in the future.

Additionally, the timeframe for this opportunity is inherently limited as domestic US capacity will inevitably ramp up, gradually narrowing the window for lucrative exports to the US market. We estimate this window could last 2-3 years before domestic US production reaches a level that significantly reduces the need for imports. While India remains a preferred alternative in major international markets, it is not immune to the imposition of trade barriers on its exports — the US Department of Commerce recently concluded a preliminary investigation into aluminium extrusion imports (used for solar mounting structures and trackers) from India, reporting dumping margins of up to 39%. In essence, the extent to which Indian manufacturers can seize this export opportunity will be influenced by three major factors: the pace at which US module makers scale up production, India’s exclusion from export barriers and ramp-up of India’s cell manufacturing capabilities.

In calendar year 2023, the residential market continued to show signs of healthy growth with estimated capacity addition up almost 50% y-o-y at 1,085 MW. Total rooftop solar capacity addition, though, was up only 8% y-o-y at 2,856 MW. addition in the corporate segment was down 7% y-o-y at 1,770 MW as many consumers deferred project implementation amid uncertainty in the module market and falling prices. Total installed rooftop solar capacity is estimated to have grown to 14,484 MW, with the share of industrial, commercial and residential segments at 53%, 22% and 25%, respectively.

Figure 1: New installations by consumer segment (LHS) and total capacity as of December 2023 (RHS), MW

Source: CRISIL ResearchNote: Years denote calendar years.

The capital expenditure (CAPEX) model continued to be the preferred route with 90% share in total capacity addition, while the share of the operating expenses (OPEX) model fell for the third straight year to 10% in 2023 compared with 27% in 2020. Loss of appetite from both demand and supply sides has hurt the OPEX market due to the absence of large-scale innovative business models targeting small and medium enterprises (SME).

The corporate market, historically plagued by policy flux, saw a turnaround in some states with multiple positive developments. Corporate rooftop solar capacity addition in Karnataka, estimated at 723 MW in 2023, rose 103% y-o-y due to a higher system size limit of 2 MW for net metered systems and smooth policy implementation. The state has proposed several consumer-friendly provisions including removal of the 2 MW project size limit under net metering, effectively increasing the limit up to sanctioned load and permitted net metering for OPEX systems and Open Access (OA) consumers. Capacity addition in Maharashtra slowed down during the year but is expected to pick up sharply over the next one to two years due to recent positive changes in rooftop solar regulations. Uttar Pradesh is also showing signs of steady growth, with corporate capacity addition up 133% in the year, aided mainly by a shift from gross metering to net billing over the past two years.

On the other hand, the Rajasthan market slowed down further due to imposition of grid charges on behind-the-meter (BTM) systems. The market is also held back in other states due to ad-hoc restrictions imposed on BTM systems. Despite the resistance of state DISCOMs, BTM is expected to become the default route for large corporates due to exemption from Approved List of Models and Manufacturers (ALMM) requirements.

Source: CRISIL ResearchNote: Years denote calendar years.

Growth in the residential market was again led by Gujarat (644 MW), Kerala and Maharashtra (119 MW each). The market has constantly been growing since 2020, led by increased consumer awareness and affordability as MNRE ensured greater access to the capital subsidy scheme.  

Market prospects are set to improve further, led by the launch of a new residential rooftop solar scheme with a target to add 30 GW capacity by FY 2027 supported by falling module costs and increasing domestic module manufacturing capacity. EPC costs for residential systems, currently estimated at 48/Wp, fell 25% y-o-y in 2023, improving the market outlook significantly. We expect the residential market to grow over four times to reach a scale of 4 GW annually by 2026. But progress is still expected to fall short of government targets due to limited availability of domestically produced cells over the next few years and a host of other challenges.  

In the corporate rooftop solar market, positive policy developments in Karnataka, Maharashtra and Uttar Pradesh are encouraging. More states should ideally follow suit and liberalise rooftop solar regulations, especially given exacerbating land and transmission challenges in the OA market. 

The Science Based Targets initiative (SBTi) recently permitted use of carbon credits for abating Scope 3 emissions, concluding a six-month long stakeholder consultation on evaluating the use of environmental certificates as a tool for supply chain decarbonisation. As per the decision, a third-party agency will be responsible for validating the quality of carbon credits. Rules and standards for effective use of offsets will be issued by SBTi before July 2024.

Scope 3 emissions encompass all indirect emissions that occur in a company’s supply chain and, depending on the sector, account for 30-90% of companies’ total emissions, as per the World Economic Forum (WEF). Corporates and sustainability frameworks have been taking a more lenient approach towards this category as these emissions are more challenging to quantify and control compared with Scope 1 and 2. Notably, in April 2023, SBTi classified 16 Indian companies, including Flipkart, Adani Energy, Welspun and Godrej & Boyce, in the ‘commitment removed’ category as they failed to achieve their targets on time. One of the main stumbling blocks identified by these companies was Scope 3 emissions, which also became the key driving factor behind SBTi allowing offsets. Among Indian companies participating in the Climate Disclosure Project, only 31% report Scope 3 emissions and only 22% have net zero goals encompassing Scope 3 emissions, as per WEF.

Under the Business Responsibility and Sustainability Reporting framework developed by the Securities and Exchange Board of India, it is mandatory for companies to report their Scope 1 and 2 emissions, whereas disclosure of Scope 3 emissions is voluntary. Furthermore, SBTi only defines Scope 1 and 2 targets and is still working on Scope 3 target-setting criteria.

The carbon credit market is likely to benefit from this additional avenue of demand, particularly after facing a setback last year when questions regarding quality and integrity of credits arose and prices plummeted for all types of carbon credits. As per S&P Global Platts, renewable energy credit, mostly from India and China, shed 41% of its value to USD 1.80/ MTCO2e in December 2023 from USD 3.05/ MTCO2e in January. Nature-based avoidance credit, household credit (improved cookstoves) and land use-based credit plummeted by 70%, 41% and 96%, respectively. That said, carbon credits related to renewables, cooking stoves and avoided deforestation are strongly opposed by SBTi and are not expected be permitted.

Figure: Price of carbon credits in 2023 (USD/ MTCO2e)

Source: S&P Global Commodity Insights

Meanwhile, India is developing its own carbon offset scheme and will allow non-obligated entities to register projects for issuance of carbon credits. But it is still being evaluated if high-quality credits from Verra and Gold Standard will be allowed. In recent years, the effectiveness and integrity of carbon offsets have come under scrutiny. A recent example is Verra’s, Verified Carbon Standard rainforest project, which attracted controversy due to the use of unreliable methodology, resulting in over-issuance of credits and overstated claims.

In the milieu, use of carbon credits should be allowed only if stringent standards and guardrails are established to ensure the use of high-quality offsets. Further, use of offsets must be considered a short-term solution, and not as a substitute for emission reduction initiatives.

Alpex Solar, a small domestic module manufacturer with annual production capacity of 848 MW, successfully completed an INR 750 million IPO in February 2024. The IPO was oversubscribed by 300 times due to strong investor demand. The stock listed at 1.9x issue price and has since soared to 4.3x issue price trading at a fantastic P/E ratio of 323. Several other manufacturers are lining up with IPO plans to take advantage of market interest. Waaree Energies is planning to raise INR 30 billion (USD 360 million) for its 6 GW ingot, wafer, cell and module manufacturing facility. Premier has filed preliminary papers for an INR 15 billion (USD 180 billion) IPO to build a 4 GW TOPCon cell and module manufacturing plant in Hyderabad. Vikram is in the process of raising INR 7 billion (USD 84 million) capital in a pre-IPO round to be followed up by an INR 15 billion (USD 180 million) IPO to set up a 2 GW cell and module manufacturing plant. Saatvik is also planning a public market offering shortly.

Bullish growth forecasts backed by strong government protection against imports (BCD, ALMM) and incentives (PLI, reduced corporate tax rate) for local manufacturing are fuelling an unprecedented market frenzy for module manufacturing companies. Rapidly rising exports helped by US moves to block Chinese imports, likely to be followed by the EU, have provided an additional kicker to the business.

Ahead of the proposed IPOs, the stocks are being heavily sought after in the unlisted market. Waaree Energies shares are trading at around INR 2,000, up nearly 10x in less than 2 years, at a historic P/E ratio of 93x. Similarly, Vikram shares are trading at an estimated 100x P/E ratio. Most companies are reporting eye-watering growth in revenues and order books. As an example, Waaree Energies revenues and PAT have grown at a CAGR of 89% and 206% respectively over last three years. As of November 2023, the company’s order book stood at an enormous 20.2 GW.

Figure: Key financial parameters for module manufacturers, INR million

Source: CRISIL researchNote: FY 2024 data is unavailable for Vikram and Saatvik. Numbers have been annualised for Premier and Waaree Energies based on their 9 month and 3 month results respectively.

While there are multiple reasons to be optimistic about growth prospects, we believe that the market is getting overly frothy. As seen in the chart, profit margins are low in a capital-intensive business with high risk of technology obsolescence. Most companies are highly levered as they fund new capital expenditure with up to 75% debt. Heavy reliance on China for imports of upstream components and even the most basic know-how poses a geopolitical risk. Government policy, a key driver of the optimistic outlook, can waver as evidenced by multiple changes in import duty and ALMM regimes in the past. It is also likely that once the US builds up a reasonable indigenous base over next 2-3 years, it may impose curbs on imports from India shutting down a lucrative part of the business. Moreover, domestic competition is expected to intensify in the next 1-2 years with overcapacity projected from 2026 onwards. Majors like Adani, Reliance and Tata with integrated capacities at scale have better odds of long-term success against their smaller counterparts.

Maharashtra has allocated a remarkable 9,000 MW agri-solar project capacity across 95 project developers. The state agency, MSEB Solar Agro Power Limited (MSAPL), had issued a flurry of tenders in the last three months for setting up distributed solar capacity in chunks of about 10-15 MW each for injection at individual substation level. There were two different kinds of tenders – for individual projects and for aggregated district level (about 200 MW each) – totaling 5,000 MW and 3,650 MW respectively. MSAPL finally awarded 4,484 MW and 3,299 MW capacity respectively at tariffs ranging between INR 2.90-3.10/ kWh. MSEDCL, the government-owned DISCOM, awarded an additional 1,217 MW in the same tariff range. The process was rushed through as MNRE’s waiver of domestic content requirement for cells was running out by 31March 2024.

In the individual substation project tenders, two PSUs including SJVN (1,352 MW) and MAHAGENCO (1,079 MW) were the big winners followed by NACOF (990 MW), a farmers’ association. In the district level tenders, winners were mostly private companies including Megha (1,880 MW), Avaada (1,132 MW), Torrent Power (306 MW) and Reliance (79 MW).

Figure: Allocated capacity and winning  tariffs

Source: BRIDGE TO INDIA research

Maharashtra’s mega award comes after a series of agri-solar disappointments across the country. In 2022 and 2023, 38 agri-solar tenders aggregating 12,250 MW capacity were issued but only 958 MW capacity was awarded. Tenders have been routinely undersubscribed to the extent of 95-98% because of physical challenges in installing and maintaining distributed capacity, low grid availability and unviable ceiling tariffs.

The state revamped its agri-solar scheme in 2023 after an extensive industry consultation and introduced several new measures to incentivise investment. MSAPL completed substantial project preparatory work in advance of issuing the tenders. Land parcels with sufficient evacuation capacity were identified and most projects clearances were obtained before tender issuance. Together with demand aggregation across 16 districts, this drastically cut down project development effort and cost. To tackle concerns about low grid availability, the project developers have been offered full compensation in the event of availability falling below 98% on a monthly basis and also provided an incentive of INR 0.25/ kWh in the first three years of operations subject to commissioning at least 75% of project capacity on time. A revolving fund of INR 7 billion has been created to assure timely payment to the project developers.

For the project winners, it is an attractive opportunity as they would also be eligible for KUSUM scheme subsidy of 30% capital subsidy up to INR 10 million/ MW subject to meeting the eligibility criteria. We understand that around 75% of all projects are eligible for this subsidy.

For Maharashtra, a relative laggard in the renewable sector, the enormous capacity award is a big win in many respects. It would feed solar power to more than 50% of agricultural feeders in the state, meet growing power demand as well as achieve compliance with the distributed RPO target (ramping up to 4.50% by FY 2030). The state government should be lauded for determinedly pursuing the agri-solar opportunity with a design that alleviates pressure on scarce land and transmission resources.