Category: Market Outlook

The renewable energy sector has seen project momentum and grown by leaps and bounds over the past decade. The installed base of renewable energy (excluding hydro) has grown at a CAGR of 15% between 2014-2024.

Taking a deeper view of the project level momentum in space, an analysis on 57.6 GW of commissioned and under construction projects suggests the segment has managed to avoid excessive delays uptil 2022 though of course supported by policy led extensions to SCODs. On average only 16% of the capacity scheduled to commission between 2019 and 2022 saw SCODs spilling over to subsequent years. The average duration of such a spillover was 1.1 years.

However, the narrative has the potential to change from 2023. To provide context, allocations over 2022-H1 2024 jumped 59% over 2019-2021. This has led to rapidly expanding developer portfolios, along with a sudden rise in resources and funding requirements. Of the 28.9 GW capacity scheduled to be commissioned over 2023 and H1 2024, almost 79% remains under construction.

This does have the context of policy support, including multiple extensions given post-Covid to address delays – due to land acquisition, grid infrastructure and connectivity challenges and supply chain disruptions – officially extended SCODs for projects allocated between 2020 – H1 2024.

Further, the reimposition of the ALMM in April 2024 has added complexity, raising compliance and supply chain continuity concerns for developers. Anticipated exemptions did not materialise, resulting in the lowest quarterly capacity additions for Q2 2024 (Apr-Jun). In 2023, utility capacity addition also declined due to below-par tender issuance between 2020 and 2022.

Figure 1: Commissioned and pipeline capacity by SCOD, MW

Source: CRISIL – Bridge to IndiaNote: (i) Data is based on projects SCOD ranging between 2019 and H1 2024, on a sample size of 57,579 MW.(ii) Only solar and wind projects won under competitive biddings were considered.

Figure 2: Commissioned capacity extent of delay against SCOD, GW

Source: CRISIL – Bridge to IndiaNote: Data is based on projects SCOD ranging between 2019 and H1 2024.

Key challenges contributing to the current project delays include high demand for evacuation infrastructure, prolonged land acquisition processes and navigating various stakeholder interests and involvement in litigations and tariff issues, among other case-specific hurdles. Concentration of project location is another issue, leading to congestion with the rapid capacity quantum increase. Since 2019, Rajasthan (10,766 MW), Karnataka (4,201 MW) and Gujarat (3,269 MW) have recorded the highest pipeline capacity.

Environmental restrictions, too, have impacted project progress, particularly with a ban on overhead transmission lines in certain areas of Rajasthan and Gujarat. This measure, aimed at protecting the habitat of the GIB has introduced significant obstacles to power evacuation. However, the recent supreme court order suggests a more balanced, case-by-case approach. According to CEA, 23% of the projects in Rajasthan that were originally planned for completion in 2023 have experienced delays due to GIB issues. In Gujarat, 32% are currently involved in litigation, while 14% in both Gujarat and Andhra Pradesh are facing challenges related to land and connectivity, awaiting regulatory approval. In addition, developer side delays account for 30% of total share.

Figure 3: Pipeline capacity share by key challenges

Source: CEA, CRISIL – Bridge to IndiaNote- (i) Share of projects are based on sample size of 5.3 GW capacity.(ii) The reasons for the remaining pipeline capacity are not known.

In conclusion, naturally with rising scale project momentum has slowed. There are some infrastructural challenges which are also being faced, however, robust planning in terms of grid and maturing expertise of developers provide comfort to outlook on connectivity and land hurdles.

Project developers are adapting to the shifting regulatory landscape, too. In the milieu, consistent government support remains crucial for sustained growth.

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. 

Renewable energy (RE) procurement has advanced from pure solar and wind to hybrids and now Firm and Dispatchable RE (FDRE), which combines solar and wind energy sources with energy storage, enabling procurement in more flexible manner.

The concept has gained momentum with the Ministry of Power issuing guidelines in 2023 for competitive bidding in FDRE projects.

FDRE can be largely classified into two categories:

Peak supply: The generator provides 100% of the contracted RE power during peak hours, which typically last between 2 and 6 hours. The number of peak hours can vary, such as only evening peak or both evening and morning peak. To ensure reliable supply, the installed RE capacity is usually 2.5 to 3 times the contracted capacity.

Load following or round-the-clock (RTC) supply: The generator must meet a specific demand profile set for the entire period of the tie-up, maintaining 75-90% of the proposed demand in every time block. This configuration is more complex and requires a higher level of oversizing, with installed RE capacity up to four times the contracted capacity.

Figure 1: Tariff discovered under FDRE tenders

Source: Bridge to India – CRISIL MI&A ResearchNote: 1. SJVNL, Nov 2023 tendered capacity is inclusive of greenshoe capacity 2. RUVNL, Aug 2023 and SECI, Jul 2024 tenders specify use of only solar and energy storage under the tender

While the FDRE market is evolving, there is significant variation in tariffs discovered under such bids. One of the important factors affecting discovered tariffs in FDRE tenders is the energy storage system itself. Looking at peak supply tariffs, the RUVNL tender concluded in August 2023 required six hours of peak-hour supply daily, a high ask compared with other tenders. In the SECI tender concluded in July 2024, the peak-hour supply was only two hours, resulting in the lowest tariff. Others are required to serve four hours of peak supply.

Storage technologies, especially battery energy storage systems (BESS), come with high capital costs. While these have dropped considerably from the last year, these tariffs are still ~29% higher than the average tariffs discovered for hybrid renewable energy tenders in 2024, thus highlighting the cost premium associated with ESS.

Under load-following tenders, the SECI tender discovered tariffs of Rs 4.98 per unit for load-following projects, only 11% higher than peak supply tenders. Considering the oversizing and nuanced complexities to technical design in the load-following tenders compared with peak supply, the minor increase in tariff reflects on the high competition and aggressive bidding in this category. Just a few months earlier, in March 2024, SECI’s load-following tender had seen a tariff discovery of Rs 5.59 per unit, 12% higher than the recently discovered Rs 4.98 per unit. Power purchase agreements were not signed, possibly due to concerns over the high tariff discovery.

The generation criteria set in the tenders also impacts tariff discovery significantly. Higher capacity utilisation factor requirements lead to increased system oversizing, which drives tariffs even higher. Similarly, in load-following tenders, the demand fulfillment ratio—the ratio of actual supply to demand requirement—plays a crucial role. Initially, SECI required a 90% demand fulfillment ratio for load-following tenders, but this was later reduced to 75% based on feedback from bidders, making the tenders more viable.

Figure 2: Demand profile proposed by SECI in a typical summer and winter month

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

Finally, for load-following tenders, the optimal configuration of all sources depends on demand. Notably, pure solar bids in 2024 (up to September) averaged Rs 2.65/kWh, while pure wind bids averaged Rs 3.56/kWh, a 34% premium. If we consider the typical June demand profile, demand is higher during evening hours, highlighting the need for increased wind capacity. In contrast, in December, demand drops significantly and wind generation tends to be higher, potentially leaving excess energy beyond the offtakers’ demand. Although the tender documents allow supply of excess generation beyond the proposed demand profile to any other party or power exchange, this creates uncertainty in revenue realisation, potentially accentuating that risk in the bids.

The decline in storage costs and evolving tender structures are key factors driving FDRE. However, the complexities of demand fulfilment and system configuration at competitive tariffs continue to be a major challenge. Despite these hurdles, FDRE projects hold immense potential for ensuring a reliable and flexible renewable energy supply.

The draft amendment to the Approved List of Models and Manufacturers (ALMM) Order issued by the Ministry of New and Renewable Energy (MNRE) will help boost domestic manufacturing of solar photovoltaic (PV) cells substantially in years to come.

As per the draft, the government will introduce a List-II of approved solar PV cells. Effective April 1, 2026, all projects will need to source modules from List-I, manufactured using cells sourced from List-II. Indeed, tenders submitted after the final order must use List-II cells, and existing modules on List-I must comply with List-II requirements by April 1, 2026, or risk being delisted.

Currently, India’s domestic cell manufacturing capacity is insufficient to support domestic demand, resulting in heavy dependence on imports. According to recent data, cell imports were up 13% on-quarter in the Q2 2024. Of the imports, China accounted for 94%, followed by Vietnam (3%) and Cambodia (2%). China and Southeast Asia import prices averaged around USD 0.047/W and USD 0.13/W, respectively. The reliance on imports highlights the need for India to develop its domestic cell manufacturing capacity.

Figure: Solar cells – import volume and prices

Source: Bridge to India – CRISIL MI&A ResearchNote: 1. *CIF prices 2. Imports data is based on the sample data that may be subset of the total quantum.

Meanwhile, the technology for solar cells is in a significant transition. In 2023, N-type TOPCon (Tunnel Oxide Passivated Contact) cells accounted for 52% of global shipments, surpassing the PERC (Passivated Emitter and Rear Contact) technology. TOPCon offers higher efficiency (22.3-22.8%), better bifaciality (80% versus 70%), and a better temperature coefficient than PERC. As TOPCon scales up, PERC is expected to be phased out by 2028. The price gap between Chinese PERC and TOPCon modules has narrowed to USD 0.01/Wp, making TOPCon a more attractive option.

Of the 94 listed entities under the ALMM Order List-I, 13 manufacturers offer TOPCon modules and, as on August 28, 2024, over half of these have integrated TOPCon cell manufacturing. Hence, the amendment to the ALMM Order is expected to safeguard domestic investment commitments for solar cell manufacturing. However, given the shift towards TOPCon, more manufacturers need to upgrade from P-Type to N-Type cell manufacturing to ensure that the industry’s technological ask is met.

As of June 2024, India’s domestic cell capacity was 7.5 GW, with an expected 32 GW to be added by the end of fiscal 2026. The module-manufacturing capacity, on the other hand, was much higher at 71 GW as of June 2024. This indicates a transient mismatch between solar cell and module manufacturing capacities until the cell manufacturing base scales up. Having said that, imported cell-based modules will remain lucrative compared with producing from an export perspective.

Domestic mono-crystalline solar modules utilise imported cells and are priced around USD 0.14 per watt – a 50% premium compared with imported modules. Modules that use domestic cells are expected to be even more expensive, with prices at least 50% higher than those using imported cells. Therefore, until sufficient domestic manufacturing capacity is established, the use of domestic modules with domestic cells could lead to a significant increase in domestic tariffs by around INR 0.30 to INR 0.75 per unit.

The government’s mandate for domestically manufactured solar PV cells aims to reduce import dependence and foster local production, while ensuring quality of the cells and reliability of manufacturers. While the transition may pose some challenges, including a potential increase in domestic tariffs, the long-term benefits of a robust domestic industry will outweigh the costs. With significant cell capacity addition expected in the next two years, India’s domestic market will be well-served, while module production using imported cells can continue to cater to the export markets.

Captive power plants (CPPs) are established alternative to the national grid for domestic industries looking to optimise costs and ensure continuous supply.

Between fiscals 2019 and 2023, while India’s electricity requirement grew by 15% from 1,581 terrawatt hours (TWh) to 1,824 TWh, consumption via CPPs rose faster at 25% to 318 TWh.

Between fiscals 2019 and 2023, though, installed captive power capacity increased a modest 4% to 78 GW. A big reason for the poor show by captive power projects is policy ambiguity and stringent regulations. Here are two cases in point:

Gujarat had imposed 100% ownership requirement, which conflicted with Electricity Rules, 2005. It was later aligned with Electricity Rules in 2023

Haryana had restricted banking facilities for projects with less than 100% consumer ownership, but this was overturned by the state regulator in 2022 and aligned with Electricity Rules

Within this space, renewable energy (RE; comprising wind and solar) has made notable progress, with its share more than doubling to 8.9 TWh in fiscal 2023 from 3.9 TWh in fiscal 2019. Still, it accounts for only 4% of the total captive generation.

A large part of the limited uptake could be because of low average capacity utilisation factor of solar and wind in captive generation at only ~12% and ~18%, respectively, in fiscal 2023. These low numbers indicate the need for repowering policies to promote new technologies with enhanced output.

Also, captive power generation is concentrated only in 10 states, with RE’s contribution at 5%, on average, in fiscal 2023. At the state level, Tamil Nadu led in captive RE generation with a 25% share, followed by Rajasthan (7%) and Karnataka (6%).

Figure: 10 states accounted for 87% of captive generation in fiscal 2023

Source: Central Electricity Authority (CEA) Electricity Review, Bridge to India – CRISIL MI&A ResearchNote: The CEA report covered 8,408 industries under the captive category in fiscal 2023. The above data may not include the full captive capacity.

CPPs are mainly set up by energy-intensive industries such as iron and steel, aluminium, cement, sugar, mineral, oil and petroleum, chemicals and textiles. Among these, aluminium, mineral oil and petroleum industries have been able to meet up to 91% of their requirement from captive generation, while the sugar industry generated 1.6 times its requirement. Iron and steel, cement, chemicals and textiles have been able to meet 71%, 61%, 49% and 26% of their power requirements captively, respectively.

Figure: Captive capacity increased 4%, while generation dipped 1%

Source: CEA Electricity Review, Bridge to India – CRISIL MI&A ResearchNote: In fiscal 2019, CEA considered projects above 1 MW under captive, whereas in fiscal 2023, it considered projects above 0.5 MW as captive. The above data may not include full captive capacity.

Policy stimulus in the form of standardised structure for captive and group captive generation can boost the expansion of captive projects. The market is going to further mature with hybrid RE solutions in view of improved generation.

India’s ambitious energy quest risks stumbling on the additional charges being levied by key states on generation of electricity from renewable sources. Rajasthan was the first to impose such a levy, followed by Madhya Pradesh. More recently, Tamil Nadu has announced its own.

All the same, the charges push up the cost of power, to the detriment of other states.

Figure: Majority of interstate transmission projects are in Rajasthan, Madhya Pradesh and Tamil Nadu

Source: Bridge to India – CRISIL MI&A ResearchNote: The analysis is based on all ISTS scheme allocations over 2019 till the first half of 2024. Within that, projects with offtaker entity separate from location of the project comprises ~25 GW, of which 74% of capacity as per data availability is mapped in the chart.

Tamil Nadu recently introduced resource charges of Rs 5 million/MW on wind projects connected to a CTU. This charge is intended to incentivize new wind power projects for STU connectivity, as CTU connected projects do not contribute to the state’s Wind RPO. The charge applies to all future projects and pending applications with CTU connectivity, and is expected to increase wind energy generation costs by ~Rs 0.20/kWh, posing a significant risk, especially to already bid-out projects

In 2019, Rajasthan introduced facilitation charges on solar projects, ranging from Rs 200,000-500,000/MW annually, based on the commissioning year, starting from fiscal 2024 to 2026, on projects supplying power to those other than state distribution companies, though it excluded captive projects within the state. The charges translated into an increase of Rs 0.12-0.30 per unit in cost of generation. However, following industry feedback, Rajasthan revised its policy in 2023, replacing the charges with a land usage fee of Rs 50,000 per hectare per year, or ~Rs 100,000/MW. This change significantly reduced the financial burden on developers and encouraged efficient land use

Madhya Pradesh introduced Harit Urja Vikas Fees of Rs 0.10/kWh under its Renewable Energy Policy 2022 on renewable energy projects selling electricity to entities other than Madhya Pradesh Power Management Company Ltd. This fee affects power sales outside the state as well as open access consumers within the state, increasing the cost burden on commercial and industrial users

Table: Specific state charges imposed on renewable energy projects

Source: Energy Department, Rajasthan; New and Renewable Energy Department, Madhya Pradesh; Tamil Nadu Green Energy Corporation Ltd

While these charges will undoubtedly benefit states that have high renewable energy potential, it will have severe consequences on other states, especially in the case of wind, as 90% of the potential is concentrated in six states, with other states relying on CTU-connected projects to fulfil their wind RPOs. Imposition of additional charges could lead to shortfalls in other states meeting their RPO target, forcing them to pay penalties or purchase RECs. But given the low liquidity in the REC market, restructuring may be necessary to maintain their commercial viability.

Also, the states’ push to redirect renewable energy to STUs may not be a prudent decision, after all.

According to the 20th Electric Power Survey of India, Tamil Nadu’s electricity demand is expected to reach 170 billion units by fiscal 2030. To meet the 3.48% wind RPO target, only 2.2 GW of new wind capacity is needed, assuming 30% capacity utilisation factor. But based on the National Institute of Wind Energy’s assessment, the state accounts for 10% of India’s 695 GW wind potential (at 120 m above ground level), whereas the current installed wind capacity in the state was 10.8 GW as of July 2024.

Hence, imposing of charges solely to fulfil RPO requirements appears overly aggressive and may, in fact, negatively impact wind projects in the state.

The Ministry of Power, in a circular dated October 25, 2023, declared that additional charges on electricity generation imposed by state governments under development fees, taxes or duties are “illegal and unconstitutional”. Despite this, states continue to enforce these charges.

While the intent behind imposing additional charges on renewable energy projects may be to promote state-specific objectives, the broader impact on the sector’s cost structure and viability cannot be overlooked. Thus, balancing state interests with national renewable energy goals is crucial for sustainable growth of the sector.

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.

Supply chain stability helps; infrastructure availability and storage costs the main influencers this fiscal

India’s renewable energy sector has seen remarkable growth, driven by the government’s ambitious net-zero target, supportive policies and declining technology costs. Also, increased competition is driving down the cost of setting up renewable projects.

Within the renewable landscape, players as well as offtakers are weighing the benefits and prospects of pure-play vs hybrid, which combine solar, wind and storage elements. A quick back-of-the-envelope analysis of tariffs reveals that solar is preferred to wind, though hybrid is the clear winner because of better generation and round-the-clock power availability.

Solar tariffs increased from Rs 1.99/kWh in December 2020 to an average of Rs 2.61/kWh in the first half of 2024. Initially driven down by acute competition, tariffs rose because of market volatility following the onset of Covid-19, changes in regulatory policy and higher module prices in 2021 and 2022. Also, in the case of wind, tariffs have been rising. Tariffs, which averaged Rs 2.80/kWh since the start of competitive bidding in 2017 up to fiscal 2023, rose to Rs 3.44/kWh in fiscal 2024, largely owing to supply chain constraints and issues related to available land and grid connectivity.

Figure: Utility scale solar tariffs have been stable of late, while wind tariffs have increased

Notes:(i) Years represent calendar year (ii) Solar capacity includes projects above 200 MW, excludes floating solar, feeder level solar and rooftop solar projects (iii) Hybrid with storage projects excludes hybrid projects blended with conventional or floating solar projectsSource: BRIDGE TO INDIA, CRISIL MI&A Research

Compared with solar, wind turbine generation is more site-sensitive, making site selection crucial. Limited number of turbine manufacturers in India has influenced project costs as well, requiring developers to backward integrate.

Competition in tariff discovery is also linked to the level of developer participation. While solar bids have been regularly oversubscribed, at 121% of bid capacity between 2023 and the first half of 2024, wind bid subscription has been much lower averaging 68%. This is because, while issues in the solar supply chain have stabilised over the past one year, the pricing for wind project supply chain, including EPC services, remains sticky and increases with turbine size.

To be sure, diversified and flexible clean energy generation has already gained traction, with hybrid energy projects comprising 42% of renewable energy project allocations in the first half of 2024.

Figure: Offtakers are shifting towards hybrid configuration from vanilla solar or wind bids

Notes:(i) Years represent calendar year(ii) Solar capacity includes projects above 200 MW, excludes floating solar, feeder level solar and rooftop solar projects(iii) Hybrid with storage projects excludes hybrid projects blended with conventional or floating solar projectsSource: BRIDGE TO INDIA, CRISIL MI&A Research

The benefits of hybrid projects surpass pure-play solar or wind capacities. These offer higher generationcompared with pure-play solar or wind capacities, and hybrid with storage adds flexibility based onrequirement and availability, enabling round-the-clock power supply, as in the case with conventionalpower. Solar-wind hybrid bids are increasingly being favoured by offtakers, with averaging 115%subscription in 2023 and first half of 2024. That is also the case for hybrid with storage, where bidsubscription has averaged 120%. And while the tariffs of solar-wind combination bids averaged Rs3.52/kWh over 2023 and 2024 (till June), and hybrid projects with energy storage for peak power supply,Rs 4.56/kWh, the higher generation and flexibility of hybrid capacities provide an advantage to theofftaker.

While solar-wind combination and hybrid projects with energy storage tender structures have seensuccess, tender issuing agencies are now aiming for more precise supply from these sources by following prescribed load profiles.

For instance, in March 2024, a tender by the Solar Energy Corporation of India for firm and dispatchablerenewable energy power for Punjab led to very high tariff discovery at Rs 5.59/kWh. The power purchaseagreement was not signed as it exceeded the state distribution company’s conventional power rates. Butanother firm and dispatchable renewable energy power bid contracted in July 2024 led to a tariffdiscovery of Rs 4.98/kWh, which was still high but lower than the Punjab tender due to easing in bidconditions, such as serving demand profile on hourly instead of 15-minute basis and reducing theminimum demand fulfillment ratio to 75% from 90%.

For India to stick to the net-zero target it had set at the 26 th United Nations Climate Change Conference(COP26), solar and wind generation will need to increase substantially. The annual ask stands at 45 GWfor achieving an installed base of 500 GW renewable energy by 2030.

For this to be achieved, the wind project supply chain, including EPC services, needs to improve toreduce costs. Also, the turbine size needs to increase for higher generation. To reduce lead times in thedevelopment of wind projects, creation of land banks is required as well. Additionally, setting up thetransmission infrastructure must be expedited as it takes 2-3 years to commission vs 1.0-1.5 years forcommissioning renewable energy projects. The central government’s renewable energy integration planalso needs to be implemented quickly. Addressing these will stabilise domestic tariffs, ensuring a moreresilient green energy sector.

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.

The emergence of merchant projects has added a new dimension to the renewable energy market as these offer developers flexibility in navigating the dynamics without long-term commitment. To be sure, the strategy of placing part of a project’s capacity under merchant operations is not new—it has been practised by thermal power plants for years. And now, it is picking up pace in the renewable energy, too. Indeed, as much as 1 GW of renewable-energy capacity is anticipated to be supplying power to spot market already.  In addition, capacity allocation through competitive bidding and open access is highly competitive, with high entry barriers, due to the presence of established players.

The Indian Energy Exchange’s Green Day-Ahead Market (GDAM) has seen significant activity, driven by surplus energy and merchant projects. GDAM’s traded volume declined 34% from 3,817 Million Units (MU) in fiscal 2023 to 2,499 MU in fiscal 2024, but the share of power sales by private players surged from 25% to 55% during the period. Major states procuring from GDAM in 2024 include Maharashtra, Tamil Nadu, Delhi, and Punjab, with prominent sellers being Adani, Ostra Kannada, Renew, and Continuum.

Developers frequently allocate a portion of their contracted capacity to merchant operations to balance the risk-reward balance in their projects. This strategy provides a stable revenue base, while allowing their projects to capitalise on the market opportunities. The ability to tap into higher spot prices during peak demand can enhance the financial viability of overall contracted capacity.

Between fiscals 2023 and 2024, the average price of RE power trades declined from Rs 5.4 per kWh to Rs 4.5 per kWh during solar hours (typically between 9 am to 4 pm) and from Rs 7.3 per kWh to Rs 6.5 per kWh during non-solar hours in GDAM. These prices are significantly higher than those typically offered under competitive bidding for long-term power-purchase agreements (PPAs), at Rs 2.6 per kWh for solar and Rs 3.4 per kWh for wind projects.

Power exchange dynamics, akin to any other traded community, goes through cycles of volatility, creating hesitancy for a full project based only on a merchant. However, in some cases, the risk is borne by consumer companies, which are eager to further their sustainability initiatives. For example, Amazon in India is signing long term PPAs, ensuring a stable income for the developers. In return, Amazon takes on the risk of utilizing or selling the electricity, managing that risk through power trading to ensure a profitable return.

Figure: Demand and supply in GDAM, Indian Energy Exchange

Source: Bridge to India-CRISIL research

Merchant projects can be strategically positioned to benefit from both short-term and long-term market dynamics. The Ministry of Power’s guidelines for competitive bidding do allow untied capacity to participate in the bidding process of various state and central government issuances forming an opportunity of potential tie-up down the line for merchant projects. But while the market offers multiple options, the bankability of merchant projects depends on market prices.

There is a prevailing belief that daytime power prices in India could fall to Rs 1.00/kWh or lower over the next decade. So, there is a limited window of opportunity to benefit from high prices in the merchant market. The merchant market offers an alternative business model for new developers, allowing them to earn higher revenue on exchanges in initial years of operations. Later, they can secure a long-term PPA at a more competitive tariff, ensuring overall returns for the project’s lifespan.

Given India’s growing energy demand, merchant power projects will be crucial in meeting targets, but developers must stay adaptable in a fast-evolving market. Success in this market requires a careful analysis of market trends and strategic risk management.

Energy storage systems (ESS) are vital for deepening renewable energy integration and enhancing grid stability. This month, a bid of Rs 44.7 lakh per megawatt (MW) per year was discovered for battery energy storage systems (BESS) under the Gujarat Urja Vikas Nigam Ltd’s (GUVNL) Tranche III bid. This marks a 66% reduction from the bid that won the Solar Energy Corporation of India’s (SECI) reverse auction in August 2022 and is 17% lower than the bid that won the GUVNL Tranche II in March this year. These BESS installations are planned for pre-identified Gujarat Energy Transmission Corporation extra high voltage substations. Potential applications include increased power integration in renewable energy-rich areas and energy arbitrage.

Over the past two fiscal years, interest in setting up ESS projects has surged. SECI’s reverse auction two years back had seen eight companies participating and was oversubscribed 5.5 times. The GUVNL Tranche III auction in June saw 13 bidders and an oversubscription of 7.8 times, while Tranche II closed with 8 bidders and was oversubscribed 3.8 times.

The increase in participation has intensified competition and driven down bids. Demand for batteries is also growing because of the steady rise in the sales and usage of electric vehicles and other applications.

Figure: Tariff discovered for energy storage tenders

Note: i. Energy storage tenders are usually tied up on capacity basis; value per unit is calculated for the first year without considering any deration factor ii. Barring PCKL Karnataka (a pumped hydro storage project), the above bids are for battery energy storageSource: Bridge to India-CRISIL Research

In addition to the procurement of energy storage as a service, discoms are investing in ESS to address diverse challenges. For instance, BSES Rajdhani has deployed a lithium-ion-based 510 kilowatt hour (kWh) /1050 kWh distributed BESS across six locations to mitigate overloading. Tata Power Delhi Distribution Ltd, too, has established a 10 MWh BESS to reduce Deviation Settlement Mechanism penalties and frequency regulations.

Given the decreasing cost of BESS, it is also essential to explore its adoption by consumers. In Madhya Pradesh, for example, high-tension commercial and industrial consumers pay a premium of 20% for energy use during peak hours (6 AM-9 AM and 5 PM-10 PM). This leads to an additional charge of Rs 7.50 – 8 per unit on the energy bill.

BESS integrated with renewable energy, meanwhile, can reduce costs considerably if individual consumers install such plants.   Although batteries are often used for short-term energy storage, there are growing opportunities for long-term storage. Looking at the volume traded on ‘Green Day Ahead’ market (which facilitates trade in renewable power on a day-ahead basis) in 2023: around 18% of the transactions closed at Rs 8 per kWh or above, of which the majority occurred between 5 pm and 12 am, and 7 am and 10 am.

Figure: Volume traded on Green Day Ahead market in 2023

Note: Data sourced from IEX, which accounts for 94% of India’s short term transactionsSource: IEX, Bridge to India-CRISIL research

Long-duration ESS is also critical to increasing renewable energy penetration. Battery storage is ideal for short durations due to rapid response and high energy density; however, the current battery technology is less cost-effective for long-duration storage. Pumped hydro storage projects (PSPs), on the other hand, offer longer storage durations and lifespans. Despite their complexity and longer construction times (4-5 years), PSPs are crucial for renewable energy growth. The Central Electricity Authority’s optimal generation mix estimates the need for 19 gigawatt (GW) of PSPs by 2030, of which a capacity of 4.7 GW was operational and 4.1 GW under construction as of April 2024. In addition, about 60 GW of potential PSP capacity is under survey and investigation, necessitating accelerated development to meet future demand.

The adoption of energy storage solutions by discoms and consumers offers a promising avenue to address various challenges and reduce energy costs. As BESS becomes affordable, their adoption by a wider range of consumers can lead to significant savings and expand the renewable energy footprint.

100% waiver of inter-state transmission system (ISTS) charges for full 25 year project life is set to be phased out shortly. The waiver is available to all renewable and storage projects completed by June 2025 with charges expected to be reinstated annually in increments of 25% for projects completed thereafter. Green hydrogen and offshore wind projects have been given longer completion deadlines of December 2030 and 2032 respectively to avail the waiver.

The ISTS charge waiver, worth a saving of about INR 0.40-0.71/ kWh depending on project location, was first proposed by the government in 2020. The objective was to make cheap renewable power accessible to both DISCOMs and corporate consumers particularly in states with scarcity of suitable land and/ or poor renewable resource. The waiver was initially intended for projects completed by June 2023 but was subsequently extended as the government deemed it critical to growth of the renewable sector.

The waiver has been an instrumental policy initiative in supporting growth of both utility scale and open access projects. In the period between November 2020 and June 2023, ISTS-connected projects accounted for 49% of total awarded capacity. Key beneficiaries have been consumers in Gujarat, Rajasthan, Maharashtra, Uttar Pradesh, Telangana, Chattisgarh and Odisha. ISTS-connected projects accounted for 64% of total commissioned capacity between 2021-2023. In 2023, almost 200 applications totalling project capacity of 51 GW were approved for ISTS connectivity mostly in Rajasthan, Gujarat, Andhra Pradesh, Karnataka and Maharashtra.

Figure: ISTS offtaker and project location

Source: BRIDGE TO INDIA researchNote: Project auction data excludes 6 GW capacity for which location is unavailable. Projects located in Gujarat are intended mainly for supply within the state.

For corporate consumers looking to increase renewable power consumption, the ISTS charge waiver is doubly attractive because of low cost of power from resource-rich states and constraints faced in intra-state open access. Five large corporates including ArcelorMittal, Vedanta, Grasim, Reliance and Adani alone have applied for nearly 4 GW GNA capacity.

Although a successful policy initiative, the ISTS charge waiver has not been without its share of problems. Heavy regional concentration of renewable project capacity has put immense pressure on land and transmission network. Scarcity of transmission capacity in crucial states has led to cascading delays in project completion and failure of states to meet RPO targets. Long lead times for development of transmission infrastructure mean that there is unlikely to be any improvement soon. Projects granted connectivity approval in 2023 have been given tentative commissioning dates between 2025-2028. The government has been forced to extend scheduled SCOD and promise ISTS charge waiver irrespective of actual COD to the affected projects. For open access projects, uncertainty of actual connectivity date often leads to bitter commercial disputes between project developers and offtakers due to disagreements over sharing of risk between the parties.

The industry, anxious about the negative impact of ISTS waiver expiry, is lobbying the government for further extension. But we believe that this policy has run course and another extension is unlikely. While the ISTS model is here to stay because it is simply unviable to set up projects in many states, power consumers need to adjust to the reality of paying for ISTS charges or bearing higher cost of power from intra-state projects, where possible.

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.

MNRE’s last ALMM order had exempted projects commissioned by March 2024 from ALMM requirement. The government issued an amendment in February providing further relaxation bowing to project developer concerns around insufficient availability of high efficiency domestic modules. The amendment sought to waive the requirement completely for open access projects and for other projects provided they placed module orders before 31 March 2024. It was, however, inexplicably withdrawn within a week creating a state of confusion and speculation in the industry.

We believe that the proposed amendment was withdrawn for two reasons – it was poorly drafted with many ambiguous provisions and led to a storm of protests from the domestic manufacturers. A new amendment has been widely expected but announcement of dates for the Lok Sabha elections and the Model Code of Conduct makes it highly unlikely now. Our understanding is that in such a scenario, the last applicable order prevails – making ALMM applicable for all projects commissioned from April 2024 onwards.

The uncertainty is highly damaging for the project developers, who have imported 15 GW of modules between November 2023 and February 2024 in anticipation of meeting the ALMM waiver timeline. But only about 4 GWp capacity has been commissioned in the last three months leaving most imports stranded. Projects using imported modules cannot declare commissioning after 31 March unless there is another policy amendment or they get ad hoc exemption from the government, both of which look doubtful for the next three months. There is also the important issue of module procurement for future projects. The project developers were hoping to have a longer time window for imports but domestic procurement seems to be the only option now, particularly for projects with urgent commissioning deadlines.

Our analysis shows that the project developer concerns about domestic module availability are somewhat overblown (see chart below). Total module manufacturing capacity is expected to go up from 61 GW currently to about 76 GW and 89 GW by end of 2024 and 2025 respectively. Discounting these numbers for obsolete (efficiency less than 20% or rating lower than 400 W) and/ or sub-scale capacity (manufacturers with less than 500 MW annual capacity) gives us year end operative capacity of 57 GW and 70 GW respectively. Most of the new manufacturing capacity can produce both mono-PERC and the more efficient TOPCon modules. Assuming an average 70% capacity utilisation and average annual exports of 9 GW over next two years, we expect domestic module availability at about 26 GW and 37 GW in 2024 and 2025 respectively – close to actual demand levels. No further ALMM relief would, however, see prices of domestic modules ticking up relative to cost of imports.

Figure: Estimated domestic module availability, GW

Source: BRIDGE TO INDIA research

On the cell side, the picture is very different because of limited capacity, technical complexity and delays in commissioning of new capacities. India is expected to remain deficit in domestic cell availability for at least three years. But record low prices, lower customs duty and waiver from ALMM requirement for cells provide ample relief on that front.

Although application of ALMM is good news for the domestic manufacturers, the policy flux is unhelpful as they face continued demand uncertainty and a risk to their expansion plans.

India’s buoyant public equity market is eagerly lapping up renewable energy stocks. Alpex Solar, a relatively small module manufacturer with total capacity of only 450 MW per annum, completed an INR 744 million (USD 9 million) IPO in February 2024 with over 300x response to its issue. The stock is now trading at a stupendous 3x offer price and over 200x annual earnings. IREDA’s INR 6.4 billion (USD 77 million) IPO in November 2023 was oversubscribed by 39x and the stock now trades at 4.6x its offer price. Gensol, a listed company offering a mix of solar EPC and related services, recently raised USD 109 million through a convertible warrant issue on the back of an all-time high stock price of INR 1,331. Another Gensol group company, Matrix Gas and Renewables, aiming to offer green hydrogen solutions, has raised USD 40 million in pre-IPO round from institutional investors.

Several companies including NTPC, Waaree, Vikram, Sembcorp, Acme, JSW, Hero Future and Rays Power Infra are considering IPOs to tap into the booming capital markets. But the striking thing about the current market frenzy is that while a range of companies from across the value chain have been able to capitalise on it, there seems little appetite for the project developers. Meanwhile, the private equity space, flush historically with big ticket cheques from overseas pension funds (CPPIB, CDPQ, Omers, OTPP), sovereign wealth funds (GIC, ADIA, Mubadala, Temasek, Norfund) and private equity investors (Actis, Brookfield, Macquarie, Copenhagen Infra, I Squared), is also subdued. The institutional investors have turned cautious as they find the risk-return in India unattractive in comparison to other markets around the world. Return expectations have gone up in response to higher cost of capital and soaring execution challenges on the ground.

The result is scarcity of equity capital for the project developers, a first for the sector. A growing number of IPPs including NTPC, O2, Ayana, Acme, Enel, Sprng, Aditya Birla, Brookfield, Continuum, Vibrant, Fourth Partner and Radiance are in the market for a mix of primary and secondary fund raising. Indeed, some of them have been trying to raise funds for more than a year but as shown in the figure below, closures are proving hard in the face of investor caution and growing valuation gaps.

Figure: Equity investment deal announcements, USD million

Source: News reports, BRIDGE TO INDIA researchNote: The chart shows major primary and secondary equity deal announcements. Data excludes outright acquisitions.

The project developers are coping with the muted investment sentiment in a number of different ways. Some like Acme and ReNew are selling projects piecemeal to keep churning equity and raise funds for future investments. The two developers have now sold a total of 2,704 MW and 943 MW projects respectively in the last three years in 12 different transactions to a range of developers including IndiGrid, Gentari/ Petronas, Bluepine, Ayana, Brookfield, Technique Solaire and Fourth Partner. Many developers have been going slow on new bidding explaining the recent rise in auction tariffs.

We believe that the Indian public equity market is not ready for renewable IPPs because of intense competition, uncertain growth profile and unattractive risk-adjusted returns. Mahindra Susten’s private INVIT floatation seems like an ideal template but that route is likely to be available only to a few high quality developers.

Gujarat has opened a new front against open access projects. As per the recently issued tariff framework guidelines for solar-wind hybrid projects, if such projects want to bank power with the grid, they would need to forego all green attributes in favour of the DISCOMs. The provision is expected to be extended to standalone solar and wind projects in the near future. West Bengal regulations have an even more severe provision – all green attributes for such projects shall be automatically transferred to the DISCOMs unless the consumers need those to fulfil their RPO targets.

Consumers already face a challenge in establishing credible claims to green attributes in other procurement routes including rooftop solar and green tariffs. In most states including Gujarat, Maharashtra, Uttar Pradesh, Rajasthan, Haryana, Tamil Nadu, West Bengal, Chhattisgarh, Odisha and Telangana, green attributes from net- and gross-metered systems are transferred to consumers only to the extent of their RPO requirement and retained by the DISCOMs otherwise. In Maharashtra and Tamil Nadu, the DISCOMs are entitled to green attributes even from behind-the-meter systems, while in Madhya Pradesh and Karnataka, the DISCOMs retain green attributes only to the extent of power banked in the grid.

Table: Availability of green attributes for consumers

Source: BRIDGE TO INDIA research

The green tariff route, currently available in 17 states, is the murkiest of all. In most states including Haryana, Rajasthan, Madhya Pradesh, Maharashtra, Telangana and Chhattisgarh, only RPO-obligated entities can claim green attributes and only up to the extent of the targets. In Uttar Pradesh, Odisha and Andhra Pradesh, there is no transfer of original green attributes to consumers. In Punjab, consumers foregoing attributes shall be given 50% rebate, while other state policies make no mention of green attributes. There is also little clarity on the process for transfer of green attributes to consumers. Even where the green attributes are transferred, the DISCOMs do not offer any traceability to original generation source, location, quantity, output date and GHG emission factor, making it an unacceptable route under RE 100 framework.

Green attributes are essential to establishing a unique and verifiable claim to emission reduction by renewable power consumers. But there is growing conflict in the way the green attributes are issued and claimed under a maze of alternate policies with multiple instruments (RECs, I-RECs, carbon credits, EScerts) and alternative trading frameworks. Lack of clarity on this vital aspect risks undermining corporate decarbonisation efforts besides leading to potential for market abuse and unethical practices like greenwashing.

There has been a surge in project auctions in the last three months. Since November 2023, total capacity of 12,142 MW has been awarded under 13 auctions. Notable auctions include a 1,184 MW peak power award by SJVN, 3,000 MW solar power by NHPC, 750 MW RTC power by REMCL, and three solar-wind hybrid awards by SECI (900 MW), NTPC (1,104) and GUVNL (200). Actual project capacity is expected to be close to 14,658 MW to meet higher CUF requirement in RTC tenders. This is a new record for project awards in a three-month period barring Q1 2020 when 12 GW was allocated under a single manufacturing-linked solar tender.

Despite a lot of talk about the growing need for hybrid power, solar tenders dominated with 64% share of the allocated capacity. Solar-wind hybrid (18%) and peak/ RTC power tenders (16%) together accounted for nearly a third of the share, while pure wind tenders had a miniscule 2% share. It is worth noting that none of the ‘firm’ power tenders have been awarded yet. Also, interestingly, there were no auctions by states other than Gujarat even though many states have been prolific issuers of new tenders in recent years.  

Bidding interest remains high – there were 28 unique participants across all auctions. But there is also evidence of more restraint in the market than in the past. The top five winners were all Indian corporates or PE-backed platforms – Avaada (1,974 MW), NTPC (1,400), ReNew (1,084), Acme (950) and Juniper (870). Notable absentees were Adani, Azure, Ayana and Greenko. International developers like Shell (Sprng), Sembcorp, Engie and Apraava again chose to bid conservatively winning 19% of total awarded capacity.

Figure: Project auctions completed in November 2023-January 2024, MW

Source: BRIDGE TO INDIA research

Tariffs were mostly stable and range-bound around INR 2.58, 3.25 and 4.36/ kWh for solar, solar-wind-hybrid and peak/ RTC power projects respectively.

Six of the 12 auctions were undersubscribed by 21-67%. More notably, all GUVNL pan India tenders were heavily undersubscribed. Even in fully subscribed tenders, subscription rate was much lower at 1.2-2x than in the past. We believe that the low interest is mainly due to lack of visibility around evacuation capacity, across the country, specially for wind sites. Second, many large developers are sitting on huge pipelines – 38,242 MW between Adani (11,770 MW), NTPC (9,415), ReNew (8,344), Azure (4,979) and Tata (3,645). For many of these developers, execution and fund raising are the main priorities.  

2023 was a bumper year for both new tender issuance (65,920 MW) and auctions (24,164 MW). The government is keen to drive more activity but DISCOM demand and execution barriers are expected to keep progress in check.

The Indian government has unveiled a highly ambitious new scheme with a target of installing 10 million residential rooftop solar systems. Few details are available yet, but the government seems to be planning to develop these systems in RESCO mode with the help of DISCOMs (demand aggregation) and central PSUs like NTPC, NHPC, EESL, SECI and SJVN (execution). The scheme is likely to be earmarked for smaller consumers with a maximum installation size of 3 kW and enhanced capital subsidy of up to 60%. REC, appointed as nodal agency, is expected to lend bulk of the residual system cost. As per the recent budget announcement, the households would be “enabled” to obtain up to 300 kWh free electricity every month.

The scheme announcement is motivated by the desire to prime a market performing far below potential and government targets. Total installed rooftop solar capacity is estimated at 12.8 GW as against government target of 40 GW by 2022. The residential market has underperformed even further with total installations of only 2.7 GW. Accounting for the fact that 74% of this capacity is located in Gujarat, progress in other states is miniscule. Less than 1% of total households in the country are estimated to have installed a rooftop solar system.

The government is frustrated with poor progress. MNRE’s phase II residential rooftop solar scheme, with a target of installing 4 GW capacity by 2022, had to be extended to 2026 due to poor progress. Several other announcements have been made recently to rally the market – MNRE has revised central government subsidy rates from INR 14,588/ kW to INR 18,000/ kW for systems up to 3 kW and from INR 7,294/ kW to INR 9,000/ kW for systems up to 10 kW; subsidy disbursement mechanism has been reformed to provide direct and timely funding to consumers; approval process for installing rooftop solar systems has been simplified; DISCOMs have been directed to ensure sufficient availability of smart meters to avoid delays in installations; and consumers have been given complete freedom in vendor selection.

The new scheme is a radical gambit. Assuming an average system size of 2.5 kW, the target amounts to a total capacity of 25,000 MW with an estimated outlay of INR 1.5 trillion (USD 18.8 billion) at current costs. The potential subsidy bill is estimated at a staggering INR 900 billion (USD 11.3 billion). Delivery of 300 kWh power on a monthly basis requires a 3 kW system costing about INR 180,000 including GST. The government is hoping that surplus power output from these systems can be sold to DISCOMs to recoup remaining capital and operating costs, but there is no prospect of surplus output if households are promised free power up to 300 kWh every month. The numbers do not add up.

Figure: New rooftop solar installations by consumer category, MW

Source: BRIDGE TO INDIA research

While we await more scheme details, it is clear that bulk of the responsibility for financing, installation and operations has been allocated to the public sector, which normally tends to be a recipe for sub-optimal deployment of resources, poor quality installations and process inefficiencies – familiar problems plaguing several earlier government schemes. Ideally, the government should carve out a greater role for the private sector and develop a vibrant market, driven more by innovation in technologies, financing structures and business models, and less by subsidies.

SECI has announced winners for the first subsidy scheme for green hydrogen production. Ten companies have been awarded a total subsidy of INR 31 billion (USD 373 million) for aggregate capacity of 412,000 MT per annum against total budget of INR 54 billion (USD 659 million) for 450,000 MT capacity. Reliance, Greenko and ACME have won the highest permissible capacity of 90,000 MT per bidder with three-year average subsidy bids of INR 18.90, 30.00 and 30.00/ kg respectively. Hygenco, a start-up, has won the second largest capacity of 75,000 MT with an average subsidy bid of 25.04/ kg. Welspun, Torrent Power and JSW have won 20,000, 18,000 and 6,500 MT capacities with subsidy bids of INR 20.00, 28.29 and 34.66/ kg respectively. The big surprise was UPL and CESC bidding zero subsidy to win 10,000 and 10,500 MT capacity respectively.

The technology agnostic bucket (total available capacity of 410,000 MT) was oversubscribed by 1.34x. Unsuccessful bidders include Avaada, Sembcorp and GH4 India, a joint-venture of Indian Oil, ReNew and L&T. The biomass-based bucket (40,000 MT) was, however, undersubscribed by 0.95x with a sole 2,000 MT bid by BPCL.

Figure: Green hydrogen production bid winners

Source: BRIDGE TO INDIA research

It is worth noting that the bidders need to find green hydrogen offtake on their own and commence production in three years. Considering these factors and the cost disadvantage of green hydrogen, the enthusiastic response (average bid of INR 22/ kg against incentive budget of INR 40/kg) is quite unexpected. We understand that six of the winning bidders – Reliance, Torrent Power, UPL, CESC, JSW and BPCL with substantial presence in carbon intensive sectors like oil refining, steel, power generation and chemicals – are aiming to use the entire output in-house. The relatively low bid capacities in relation to their business size mitigates both offtake and price risk.  

For the four pure play project developers including Greenko, ACME, Hygenco and Welspun, securing long-term bankable offtake shall be a major challenge. They have signed multiple MOUs with various domestic and international counterparties but given serious concerns about technology, financial viability and reluctance of consumers to commit, the low bids are still hard to explain. Indeed, few projects internationally have taken off the ground so far and IEA has recently revised its growth projections downwards. 

Meanwhile, the government has announced two further subsidy schemes – for 200,000 MT green hydrogen and 550,000 MT green ammonia capacity. The new green hydrogen scheme is similar to the first scheme with a crucial difference – 100% offtake shall be tied up with domestic oil refining companies at a fixed price in advance. The government should be lauded for its serious commitment and multi-pronged approach to this nascent sector.

Best wishes for a hale and hearty new year to all our readers!

2023 ended on a limp note defying all hopes of strong growth and sector revival. Excluding open access, which saw a record capacity addition of 5.1 GW, the utility scale business registered a decline of 50% with total capacity addition of only 5 GW, the lowest in last three years. Total ground-mounted solar and wind capacity addition is estimated at 6.5 GW and 3.6 GW respectively. The resounding theme of the year was weird ALMM policy manoeuvres wherein the project developers kept delaying projects to take advantage of falling module prices, which touched an incredible low of USD 0.12/W by the end of the year.

As a result, 2024 is shaping up to be a bumper year. As evidenced by soaring module imports in Q4 2023, we expect a huge jump in total capacity addition to about 22-25 GW including rooftop solar. Return of the current government in general elections around April-May, as widely expected, would mean business-as-usual and continuity of policy direction.

Here are our major themes for the year.

The government will extend ALMM, the government will notThe year begins with uncertainty all around about the ALMM policy. As things stand, ALMM would apply to all projects commissioned from 1 April 2024 onwards. Both project developers and module manufacturers are lobbying the government, which we expect to refrain from any further relief except possibly for open access and rooftop solar projects.

Domestic module manufacturing to take deep rootsThe year has started with inauguration of First Solar’s fully integrated 3.3 GW plant in Tamil Nadu. More cell-module capacity is expected to come onstream by Waaree (5.4 GW), Reliance (5 GW), Tata (4 GW), ReNew (4 GW), Goldi (2.5 GW) and others (3 GW). The manufacturing landscape would be transformed as a result with supply nearly matching demand by the end of the year. No further ALMM relief would be a big boost for the manufacturers and could pave the way for some successful IPOs.

Module prices to stay near record lowsAt current module prices, the whole value chain is hurting in China and smaller/ non-integrated players are especially feeling the pinch. There are some upside risks but we expect prices to hover around current levels given the large supply glut. However, India-made module prices should maintain a  premium of up to about 50% due to ALMM and BCD protection.

Equity to remain scarce for project developersEquity availability remains tight resulting in higher return expectations in the project development business. Consequently, bidding for new projects is expected to remain conservative as we saw through the end of last year. If tariff and equipment prices stay near current levels, it would be a golden time for the project development business.

Rooftop solar to see fresh growth spurtBarring a few regional pockets in the residential segment, the rooftop solar market has been subdued over the last three years. This year should see a revival with low module prices, improved domestic module supply, higher subsidies for the residential market and a more supportive policy.

Incremental progress in new technology sectorsLack of domestic technology capability, high execution risk and costs are expected to keep posing challenges for battery storage, offshore wind, agri-solar and green hydrogen.

After severe disappointments of last few years, there are lots of hopes riding on 2024, which looks promising for both manufacturers and project developers. Key developments to watch out for during the year:

Lok Sabha elections

ALMM policy announcement

Auction of ‘firm’ power tenders

Offshore wind tender

Waaree IPO

Announcement of a new PLI scheme for BESS

Implementation of tariff pooling mechanism

Implementation of new carbon market

At the start of this year, we had expressed a hope that 2023 would mark a turnaround for the renewable sector. Having being hit hard by supply chain disruption, cost spikes, BCD and ALMM over previous two years, the sector badly needed some relief and fresh impetus for growth. But the year was mixed at best with weak progress on capacity addition front and new initiatives. The biggest positive was the dramatic fall in module prices in China, a salve for the entire market. Here, we look at key developments that have shaped the sector during the year.

Key positive developments

Modules fell and fell furtherChina module prices crashed to touch USD 0.12/ W by end of the year, a 50% YOY decline. Massive investments in new capacity have resulted in a supply glut across the supply chain despite 38% increase in global demand. The fall in prices has mitigated financial pressures on project developers and improved viability of projects struggling earlier with low tariffs.

Bright OA outlookThe Green Open Access Rules, while still in early stages of implementation, have managed to align policy landscape across states. The Rules have already been adopted by most of the frontline states. Along with the ISTS waiver, notified by CERC in August 2023, and improving corporate demand, the OA market is experiencing strong growth – adding new capacity of 3,126 MW in Jan-Sep 2023, 16% YOY growth.

ALMM waiverAfter a lot of jitters about limited supply of domestic modules, MNRE announced ALMM waiver for projects commissioned by March 2024. But the waiver meant that most project construction was deferred to take advantage of falling module prices (see figure). Module imports have been picking up steadily since July 2022 (439 MW imported in October alone) and a surge in capacity addition is expected over next four months.

Rising module exportsHelped by US aversion to Chinese imports, the Indian module manufacturers rushed to grab the highly attractive export opportunity. 9M 2023 export volumes grew 655% YOY to 4,439 MW at an average price of USD 0.35/Wp, about 40% premium over domestic prices. Big beneficiaries were Waaree, Adani and Vikram Solar. Three Indian companies have also announced plans to set up manufacturing plants in the US, while many others are gearing up for higher exports in future.

Strong lending appetiteDomestic lenders including government-owned financial institutions and commercial banks rediscovered their lending appetite for the sector mainly due to improving DISCOM finances and IPP credit profile. The conditions were benign even for manufacturing and corporate renewable businesses, previously struggling to access project debt.

Key negative developments

Disappointing capacity additionOnly 7.7 GW of new capacity was added until October 2023, 49% decline over 2022 and far below government targets. While solar slowdown could be attributed to deliberate delays by project developers to take advantage of falling module prices, poor progress in the wind sector is particularly disappointing.

Figure: Capacity addition in 2023, MW

Source: MNRE, BRIDGE TO INDIA research

Slow progress on storageThere was a lot of talk but little concrete progress on hybrid tenders. Twelve new RTC/ peak/ firm power tenders totaling 15 GW capacity have been issued in the year so far but auctions have been completed for only 4 GW. The latest design for firm power remains yet to be tested because of market concerns. Karnataka completed the only standalone storage auction for 1,000 MW/ 8,000 MWh in the year. Slow adoption of storage technologies and new tender designs does not augur well for market growth.

Stagnant rooftop solar marketThe rooftop solar market, affected by policy uncertainty and limited supply of domestic modules, continued to stagnate with estimated capacity addition of 2,337 MW between Jan-Oct 2023.

Sluggish momentum in new technologiesSeveral initiatives related to battery storage, offshore wind and carbon markets remained tentative as concrete details related to techno-commercial viability, supply chain security and market mechanisms are still missing in most instances.

Tight equity marketsEquity funding scenario flipped during the year because of combined effect of increase in international interest rates and more attractive risk-adjusted returns in the US and Europe as compared to India. International investors have turned cautious making fund raising more difficult.

India’s oil & gas companies seem to be getting interested in the renewable energy sector all over again. Several ambitious announcements entailing huge investments have been made to this effect recently. Indian Oil has set up a new subsidiary for the business with plans to provide solutions across renewable, biofuel, green hydrogen, carbon offset and carbon capture markets. The company plans to build a 3 GW renewable portfolio by 2025 and scale it up to 31 GW by 2030 across solar, wind, hydro and pumped hydro projects. Hindustan Petroleum Corporation Limited (HPCL) is also looking to set up a new subsidiary for the business with plans to invest INR 438 billion (USD 5.3 billion) by 2028. ONGC has acquired a 289 MW wind portfolio with further plans to invest INR 1 trillion (USD 12 billion) to build 10 GW portfolio by 2030. GAIL has established a strategic collaboration with BHEL and is also eyeing opportunities in solar PV manufacturing space.

The renewed interest comes after many years of dithering. Many similar announcements were made by the oil & gas companies about 5-7 years ago but only token progress has been made so far. Reasons include low scalability, uncertain return outlook and severe execution challenges. Indian Oil’s current renewable capacity stands at 238 MW, whereas HPCL portfolio stands at only 184 MW mainly in the form of small captive projects and rooftop solar installations. ONGC, Oil India, GAIL and BPCL have operational renewable capacity of only 348 MW, 188 MW, 132 MW and 48 MW respectively.  There have also been some isolated examples of participation in primary and secondary project auctions but no concerted attempt to grow this business.

A look at forays by global oil & gas companies in the renewable sector makes for a mixed reading. The charge has been led by European giants like Shell, British Petroleum, and Total Energies in an attempt to diversify away from their conventional business, decarbonise operations and achieve climate neutrality. All three companies have made significant renewable investments over more than 10 years now. In 2022, BP, Shell and Total allocated significant sums – USD 4.9 billion, USD 4.3 billion and USD 4 billion respectively towards renewables and other low carbon solutions.

But last year was a turning point for many of these companies with windfall profits in their core businesses. Dissuaded by poor returns from renewable projects, they are now backing off from their renewable plans. BP, with one of the most aggressive energy transition strategy, has slashed its climate pledges and adjusted its planned reduction in oil & gas production from initially target of 40% to 25% by 2030. It has subsequently announced a 17% reduction in its planned renewables spending by 2030. Shell is also having a rethink – the company has scrapped the role of global head of renewables and exited from offshore wind projects in Ireland and France. It is also exploring sale of a stake in Sprng Energy, acquired last year, to reduce debt and free up capital for greater investment in fossil fuels. Notably, the US-based companies like Chevron and Exxon have completely stayed away from renewables.

Figure: 2022 capital expenditure split for oil & gas majors

Source: Reclaim Finance Analysis

The turnaround in sentiment of the Indian oil & gas majors has come about because of growing renewable sector scale and more climate pressure. But they are certainly not going to find it easy this time either. The sector continues to be heavily crowded and intensely competitive with depressing returns outlook. We believe that the most likely route for these companies remains meeting captive needs particularly in allied areas like green hydrogen, bio-fuels, carbon capture and EV charging. Given their traditional corporate skill sets and preferences, they should find it more attractive to outsource the mainstream renewable business to third parties.

The Maharashtra electricity regulator has made several market-friendly amendments to its open access (OA) and net metering regulations. Unlike in the past, OA consumers shall now be eligible for net metering connectivity for their rooftop solar installations and vice-versa. The OA regulation has been largely aligned with the Green Open Access Rules – reduction in minimum contract demand to 100 kW, monthly banking of power, REC issuance for unutilised power and 100% AS waiver. Additionally, there is no cap on quantum of banked power and standby charges, equivalent to about INR 0.20/ kWh, have been completely waived. All possible connectivity options including net metering, group net metering, net billing, gross metering and behind-the-meter are permitted for rooftop solar systems up to contract demand without any size caps. The only exception is an absolute cap of 5 MW, much more generous than in other states, for net metered systems. Existing behind-the-meter systems would be allowed to convert to net metering. Rooftop solar systems would also benefit from a relaxation on imposition of grid support charges, which would be waived completely until total installed capacity in the state reaches 5 GW, revised upwards from 2 MW (current installed capacity – 1,716 MW). There is even a penalty of INR 500/ day on the DISCOMs in case of delays in grid connectivity.

The main negative change relates to retention of green attributes associated with net metered, net billing and behind-the-meter systems by the DISCOMs, unless the consumer is an obligated entity. Also, unlike in the Green Open Access Rules, there is no cap on cross-subsidy surcharge.

The catalyst for these changes, in a state historically resistant to the growth of private markets, seems pressure from MNRE, which has been urging states to implement its directives on the Green Open Access Rules and RPOs. The new distributed RPO target of 4.5% by FY 2030 is a definite trigger. Unfortunately, the biggest OA pain point in the state remains unaddressed – an arbitrary limit of 1.4x contract demand as specified in the grid code – a big constraint for users seeking to push RE adoption beyond about 40-50%. The regulator has refused to heed to market concerns on this crucial issue.

Notwithstanding retention of green attributes from distributed systems by the DISCOMs, rooftop solar is a big winner. Consumers should find free net metering up to 5 MW, with cost saving potential of 50-70%, still highly attractive. Allowing consumers to avail both OA and net metering options, and conversion of behind-the-meter systems to net metering are extremely positive for the market.

The regulator’s focus now should be on effective implementation of the new regulations. It has disregarded most operational concerns of the MSEDCL about inadequacy of distribution and billing infrastructure. But if MSEDCL uses ad-hoc measures like denial of approvals and levy of extra charges, as seen in the past, the reforms may not amount to much.

Figure: Total corporate power consumption and direct renewable penetration, FY 2022

Source: BRIDGE TO INDIA research

As this figure shows, Maharashtra’s historically negative policy stance has impeded growth of the corporate renewable market with one of the lowest penetration rates in the country. The state enjoys huge growth potential due to its large market size, high grid tariffs and abundant solar and wind resources. A more conducive regulatory environment is needed to unleash this potential.