Category: Uncategorized

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.

Module prices crater as supply eclipses demand

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.

SECI recently completed the first ever auction for a “firm and dispatchable renewable energy” (FDRE) tender. The 1,500 MW tender was undersubscribed with only 600 MW of bids received and 480 MW awarded to JSW (180 MW), Hero (120), Serentica (100) and ReNew (80) at tariffs of INR 5.59-5.60/ kWh. Two other so-called FDRE auctions by NTPC (3,000 MW) and NHPC (1,500 MW) were also completed in the last month but they were both actually peak power tenders in disguise.

There are many unique provisions relating to power supply obligation in the SECI tender. It specifies a time-block wise power output profile on a monthly basis (see figure), unchanged for the 25-year PPA life. The projects developers are required to supply a minimum 90% of the time-block wise requirement on a monthly basis. Penalty for generation shortfall is steep at 150% of PPA tariff. Offtake obligation under the tender is capped at the specified time-block requirement but SECI has retained the first right of refusal for purchasing surplus power up to contracted capacity at 50% PPA tariff. The only flexibility afforded to the project developers is that they may procure up to 5% of annual power requirement from third parties and change storage size/ technology at any time.

Figure: Hourly demand profile in the SECI FDRE tender, MW

Source: BRIDGE TO INDIA research

As the figure shows, the specified output profile, dictated by the two offtaking states Punjab and Madhya Pradesh, is extremely peculiar. Punjab has specified a predominantly non-solar profile from April to September – 100% contracted capacity at all times except during solar hours in April, May, June and September, when the demand falls to as low as 450 MW. On the other hand, Madhya Pradesh has specified a flat 650 MW requirement (43% of contracted capacity) for the six winter months from October to March.

Low subscription plus relatively high tariffs in the tender can be explained by the peculiar demand profile and stringent provisions for shortfall/ surplus generation. The demand profile suggests a wind-heavy project configuration with total renewable project capacity at about 3.5x contracted capacity coupled with minimal storage capacity. We estimate that surplus power output is likely to be about 50% of total power output. For the winning bidders, finessing the project configuration (sizing, location, timing of storage capacity addition) and assumption for sale price of surplus power in the open market would be the most crucial aspects.

The tariffs are cost competitive with new thermal power plants particularly considering that they remain fixed for 25 years and the DISCOMs can use this power to meet RPO targets (no need to buy RECs). However, given the changing nature of overall demand profile and ongoing improvements in storage technology, we do not believe that it is right for the DISCOMs to lock into a specific demand profile for 25 years. It remains to be seen if Punjab and Madhya Pradesh accept the winning bids. Given the unique and split nature of demand between the two states, both states would need to sign up for the projects to go ahead.

India’s national power sector regulator, CERC, has made a series of amendments to the national REC market framework over the last couple of years. After introduction of bilateral trading, removal of price bands and extending instrument validity forever from December 2022 onwards, it made RECs technology agnostic from October 2023 onwards. Buyers on exchanges can no longer trace RECs to the underlying projects, technology or vintage. Since October 2023, trading frequency has also been increased from once a month to once every fortnight.

The intent of all these changes is to remove all market distortions and improve liquidity. But frequent regulatory changes, legal disputes and suspension of trading (twice between May 2017-March 2018 and July 2020-October 2021) have greatly impacted market confidence. Despite the government giving statutory effect to RPO policy with a renewed focus on enforcement, trading volumes remain relatively low. Although issuance and trading numbers have been increasing progressively over last three years, only 42% of total RECs issued in 2023 – equivalent to 3% of total renewable power output and less than 1% of conventional power output in the year – were traded. Stock of unsold RECs has shot up to a record number of 30 million resulting in prices collapsing to all-time low of INR 270/ MWh (USD 3.24/ MWh) in the latest trading round.

It is also instructive to look at trading data for RECs in relation to I-RECs. Between 2020 and 2023, project developers in India registered a total 6.8 GW capacity, net of hydro projects, under I-RECs compared to only 2.2 GW capacity, net of hydro projects, under the REC scheme. As a result, total capacity registered under the I-REC scheme has reached 9.6 GW (solar 3.6 GW, wind 3.3 GW and hydro 2.7 GW) as compared to only 6.1 GW under the REC scheme (solar 1.5 GW, wind 3.0 GW and hydro and others 1.7 GW). As the following chart shows, REC issuance and trading volumes are about 2-2.5x higher in comparison to I-RECs but that is attributable mainly to their special status as a policy tool – DISCOMs and corporates failing to meet their RPO targets have no other option but to buy RECs. About 60% of total REC demand is estimated to come from DISCOMs.

Figure: REC trading volumes and prices

Source: REC Registry, IEX, I-REC Standard, BRIDGE TO INDIA researchNote: Indian REC and I-REC trading data is shown until March 2024 and February 2024 respectively.

It is also instructive to look at trading data for RECs in relation to I-RECs. Between 2020 and 2023, project developers in India registered a total 6.8 GW capacity, net of hydro projects, under I-RECs compared to only 2.2 GW capacity, net of hydro projects, under the REC scheme. As a result, total capacity registered under the I-REC scheme has reached 9.6 GW (solar 3.6 GW, wind 3.3 GW and hydro 2.7 GW) as compared to only 6.1 GW under the REC scheme (solar 1.5 GW, wind 3.0 GW and hydro and others 1.7 GW). As the following chart shows, REC issuance and trading volumes are about 2-2.5x higher in comparison to I-RECs but that is attributable mainly to their special status as a policy tool – DISCOMs and corporates failing to meet their RPO targets have no other option but to buy RECs. About 60% of total REC demand is estimated to come from DISCOMs.

GUVNL has concluded an auction for a 250 MW/ 500 MWh standalone battery storage tender. The batteries will be deployed at a state transmission sub-station for providing energy arbitrage, load shifting and other applications. Bidders were required to quote a flat capacity charge for providing two operational cycles per day over twelve years. Gensol and Indigrid have won 70 MW and 180 MW capacities with bids of INR 4.48 and 4.49 million/ MW/ month respectively. JSW, Hero, NTPC, ACME, SJVN and EDF were the other bidders with bids ranging between INR 4.49-9.95 million/ MW/ month. This was the second standalone battery storage auction in India after SECI’s 500 MW/ 1,000 MWh auction in August 2022, where JSW was the sole winner with a tariff bid of INR 10.83 million/ MW/ month.

The biggest contributor to the 59% fall in tariff in just 18 months is the sharp decline in lithium-ion battery cell prices. Total battery pack prices fell 14% YOY in 2023 and have collapsed in the last few months with current year-end estimates of about USD 87/ kWh on account of falling raw material costs, increase in production capacity and weak demand.

Figure: Average lithium-ion battery prices, USD/ kWh

Source: BNEF, BRIDGE TO INDIA research

Also, there are two key positive provisions in the GUVNL tender:

100% offtake commitmentGUVNL tender includes 100% offtake commitment as against only 60% commitment in the SECI tender resulting in lower price risk for the project developers.

BOO project structureAs against the SECI tender, which requires the project ownership to be transferred to it at the end of concession life for free, GUVNL tender envisages BOO project – a benefit estimated to be worth up to about 10% of capital cost in salvage value.

Accounting for the lower BESS cost and these contractual differences, bids in the two tenders seem comparatively even. However, SECI’s relatively lax contractual process and delay in finding offtakers – PSA for 50% capacity was signed 18 months after auction date – provides more timeline flexibility to the project developer with an opportunity to derive substantial benefit from falling costs.

We estimate GUVNL tender LCOS at INR 5.30/ kWh making it cost competitive with pumped storage projects as seen in the NTPC 500 MW/ 3,000 MWh and Karnataka 1,000 MW/ 8,000 MWh auctions. It marks a key milestone for BESS with two significant implications. First, with the cost of renewables plus 2-hour storage now falling to around INR 5.00-5.50/ kWh levels, consumer acceptance should go up significantly. The roadmap for cost competitiveness of 4-5 hours of battery storage is also becoming visible with ongoing improvements in technology and production cost. It even raises the possibility that government’s proposed VGF support for BESS may not be needed at all, as happened with the solar VGF scheme prematurely.

Second, assuming prices stay low, BESS should become the most preferred storage technology because of its crucial operational advantages over pumped storage projects – higher efficiency, minimal land requirement, flexibility in project siting, quicker response time, modular configuration and significantly shorter gestation period/ lower construction risk. Companies like Greenko, Adani, Tata Power and JSW, amongst others, aiming to develop pumped storage projects would now be forced to revisit their 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.

First Solar has become the first company, awarded capacity in the module manufacturing PLI scheme, to announce full commercial operations ahead of time. The company’s 3.3 GW integrated thin-film module manufacturing plant commenced production in January 2024. It has already tied up bulk of its first year output with buyers in India and the US. Tata is the only other scheme winner expecting to commission its 4 GW cell-module awarded capacity ahead of time. The company’s 4.3 GW mono-PERC line, upgradable to TOPCon technology, is expected to commence production by Q4 this year. Reliance, awarded 10 GW polysilicon-module capacity, is due to commission a 5 GW HJT cell-module line in Q3 this year with another 5 GW cell-module line expected by late next year. But the timelines for its polysilicon and ukkwafer plants are still unclear.

Most other PLI winners are lagging completion deadlines. Waaree, winner of 6 GW wafer-module capacity, is expected to commission 1.4 GW mono-PERC cell-module capacity and 4.0 GW TOPCon cell-module capacity by end of this year. ReNew, winner of 4.8 GW wafer-module capacity, has already commissioned a 4 GW module assembly line and expects to commission 2 GW TOPCon cell-module capacity by middle of this year. Grew and Ampin (in partnership with Jupiter) are expected to commission their 2.8 GW and 1.3 GW cell-module plants respectively by end of this year. But there is little progress on wafer manufacturing plans of these companies.

Shirdi Sai, Avaada and Vikram are further behind with high degree of uncertainty about their plans. Shirdi Sai seems to have made almost no progress while JSW has put the entire project on hold citing unviability of the business in light of record low module prices.

Source: BRIDGE TO INDIA research

While most players would be able to complete their module assembly plants broadly on time, significant deficit is foreseen in the technology-critical upstream capacity. Total cell manufacturing capacity is expected to fall shy of 30 GW by the final deadline date, indicating an over 40% shortfall. Corresponding shortfall in wafer and polysilicon capacities is expected at about 60% and 50% respectively assuming Reliance completes its entire 10 GW capacity on time.  

We understand that the affected companies are approaching the government for timeline relaxations under various pretexts. The slow progress can be attributed mainly to two factors – poor financial prospects and a high degree of policy/ market uncertainty. Low prices across the value chain have hurt financial viability of the business making it difficult to raise capital. That combined with ALMM policy uncertainty and ensuing lack of demand visibility – the government recently proposed to provide further relaxations before withdrawing the amendment – has upset plans of most companies. It is worth noting total solar capacity addition in India in 2023 is estimated at only 8,847 MW, down 32% YOY. Investors are simply unwilling to commit capital in the face of such high price, demand and policy uncertainty.

China’s quest to dominate the international solar supply chain by investing aggressively and driving prices ever lower seems to be working so far. Prospects of upstream module manufacturing appear bleak not just in India, but also in Europe and the US, where many companies are forced to discard their investment plans despite strong government support. India is likely to remain dependent on Chinese technology and equipment imports for the foreseeable future with all the ensuing uncertainty regarding availability of modules, cost and government policy.

Suzlon and Inox Wind, the two biggest Indian wind turbine manufacturers, have announced much improved financial results for Q4 2023. Suzlon reported revenues of INR 43 billion in 9M FY 2024 largely in line with the previous year but EBITDA was up to INR 6.8 billion from INR 6.1 billion, while PAT witnessed 43x growth YOY to INR 4.3 billion. The company turned to net cash position of INR 7 billion as of December 2023 from net debt of INR 11.8 billion in the previous year. Similarly, Inox Wind has reported revenue rising to INR 12 billion in 9M 2024 from INR 5.6 billion last year, EBITDA of INR 2 billion against a loss of INR 2.2 billion and net loss down to only INR 0.9 billion from INR 5.5 billion. The company is expected to become debt free in the next few months.

The turnaround in financial performance comes after an extended torrid time when both Suzlon and Inox Wind suffered cumulative losses of INR 48 billion and INR 19.4 billion respectively over five years in the wake of the sector downturn. The two companies have restructured their balance sheets, shut down unviable capacity, raised prices, restructured contracts and invested in new technologies. Suzlon raised INR 20 billion from institutional investors in a private placement in August 2023. Inox Wind spun off its O&M subsidiary, Inox Green, in November 2022 through an IPO to raise INR 7.4 billion. It has raised a further INR 8 billion from global investors and INR 18 billion in interest-free debt from its sponsors. The company has also divested a 50 MW project on its books for a total consideration of INR 2.9 billion.

Figure: Financial results, INR billion

Source: Company presentations, BRIDGE TO INDIA research

On the technology front, Suzlon has unveiled a new turbine with a rated capacity of 3.15 MW and energy output up to 49% higher than other products. Inox Wind, having already added a 3.3 MW wind turbine to its portfolio, is working with Wind To Energy, a German company on a 4X MW turbine designed especially for low wind speeds. Both companies have bagged a series of orders in the last few months with order books now standing at a very healthy 3.1 GW and 2.6 GW respectively. Share prices of both companies have almost trebled in the last year.

Figure: Relative stock prices for Suzlon and Inox Wind

Source: NSE, BRIDGE TO INDIA research

There is an urgent need for augmenting wind capacity, average of just 1.8 GW per annum over last five years, to balance solar output profile and accelerate overall growth of the renewable sector. Suzlon and Inox wind have an annual manufacturing capacity of 4.5 GW and 1.6 GW respectively. Together with the emergence of Envision, as a prominent turbine OEM with annual production capacity of 4 GW and order book of 4.7 GW, the improving operational and financial health of Suzlon and Inox Wind augurs well for the sector. We expect these three companies to account for over 80% of total wind capacity addition in the next few years.

Another round of COP discussions concluded in December 2023 marked by limited progress and overall disappointment. It included the first ever Global Stocktake to assess progress against the Paris Climate Change Agreement targets. The conclusion is glaringly obvious – the world is falling behind climate goals with global warming close to breaching the 1.5 oC threshold. Indeed, based on current emissions trajectory, the planet is set to warm up by 2.5 oC. Despite seriousness of the task at hand, the member states once again eventually failed to agree on any meaningful time-bound action.

A lot of time was spent on trying to reach a consensus on phasing out fossil fuels, but the draft was successively toned down from “phase out” to “rapidly phase down” to ultimately “transition away from fossil fuels.” 118 countries signed up to a facile declaration to triple their renewable capacity by 2030 but India (alongside China, Russia and Indonesia) refused to sign up to this. India’s primary bone of contention was the challenging target of doubling energy efficiency. India also skipped signing the COP 28 Declaration on Climate and Health, which requires countries to reduce use of greenhouse gases for cooling in healthcare deeming it a compromise on national healthcare system.

One symbolic achievement was the eventual creation of Loss and Damage Fund, first mooted in 2009, with total commitments of USD 725 million from the EU, UK and UAE. The fund would be managed by the World Bank and would be available to developing countries. But it is grossly insufficient to fund the estimated USD 400 billion climate related loss and damage in vulnerable countries by 2030 and also minuscule against the original target of raising USD 100 billion each year by 2020. There are several disagreements related to guidelines on usage and reporting.

Relatively more progress was made in the voluntary carbon market, where a coalition of organisations responsible for setting standards for corporate decarbonisation – SBTi, GHG Protocol, Voluntary Carbon Markets Initiative, We Mean Business Coalition and Integrity Council for the Voluntary Market – has been formed to devise a framework for using carbon credits. However, timelines for operationalising the carbon markets and bilateral transfer within countries are yet to be framed.

In conclusion, COP 28 was another year of missed opportunity, lots of talk and little meaningful action. It is clear that we need urgent and decisive action, not incremental progress. The failure to find a common ground between different countries is hurtling the planet to an environmental disaster. For its part, the Indian government rightly wants western countries, responsible for most of historic emissions, to assume responsibility for the remedial actions. But its reluctance to step up on climate action is hard to justify. It is prioritising economic development over environmental action as exemplified by recent measures to add 80 GW of new thermal capacity. As one of the largest countries with growing emissions and facing severe environmental crises of its own, it should take a leadership role in international forums and commit to more forceful measures for the good of its own people.

India’s power demand grew by a healthy 9% in Jan-Nov 2023 in comparison to 2022. To ensure adequate power supply, the government has mandated all imported coal-fired plants to operate at maximum capacity and imported coal blending with domestic coal. It has further scaled up thermal capacity addition plans to 80 GW new capacity by 2030, a sharp jump from an earlier estimate of 27 GW, in anticipation of sustained increase in demand. The government has been categorical that supply would be boosted to accommodate economic growth but disappointingly, there has been no new impetus or increase in renewable power demand from DISCOMs. The muted demand for renewable power, together with the government’s standout reluctance to commit to tripling renewable capacity at COP28, is a disturbing sign for the sector.

A quick look at data shows that alongside increase in absolute quantum of power demand, the consumption profile is getting more volatile and peaky. In Madhya Pradesh, the ratio of maximum demand in 2022 to minimum demand in the year was 88%, compared to only 35% in 2019. Similarly, in Tamil Nadu, the ratio was 98% in 2022 against only 52% in 2019, while in Maharashtra, the respective figures were 41% and 28%.

Figure: Hourly demand profile on peak demand day, MW

Source: Niti Ayog, BRIDGE TO INDIA research

We believe that renewable power’s variability risk and, in turn, low demand is now the single biggest challenge facing the sector. Various initiatives over the years to address this risk have made scant progress due to complacency on part of the policy makers.

Weak progress on adding storage capacityThere is a distinct lack of enthusiasm towards storage because of high cost and supply side concerns. Despite innovation in tender designs (standalone storage, peak, RTC and firm power solutions) and boom in tender issuance (25 GW of storage-based tenders so far), only 6.3 GW capacity has been allocated. To make matters worse, a significate share of this capacity faces execution uncertainty.

Flexible coal-based power plantsThe regulation to retrofit all coal based thermal plants to make them more flexible has been stuck owing to several technical, financial and contractual challenges. IEEFA estimates capital cost of converting a coal plant to a flexible asset shall be around INR 0.4-1.0 million/MW.

Reviving gas based plantsGas plants can play the effective role of peakers but most of the gas-fired 25 GW capacity is either stranded or operating at minimal levels due to insufficient/ costly gas. Discussions to revive gas-based plants have never reached implementation stage.

Demand side managementA small beginning has been made on TOD tariffs from FY 2024 onwards – grid tariffs shall be at least 10-20% higher during peak hours and 20% lower during off-peak hours. Some states have also notified demand side regulations, while others are trying to shift agricultural load to daytime hours. But more needs to be done with innovative pricing structures and incentives to influence power consumption patterns.

Ancillary servicesThe ancillary services market remains in its infancy following issuance of Ancillary Services Regulations In early 2022. A market for tertiary services was introduced in June 2023 but launch of secondary and primary services is still pending.

It is hard to understand why these measures are not receiving more urgent attention. The policy ambivalence and emphasis on thermal power are sending confusing signals to the market and causing a serious damage to growth prospects of the renewable sector.

We wish all our readers a joyous festive season and a very happy new year! Next edition of the India Renewable Weekly shall be issued, after a three-week break, in the week commencing 8 January 2024.

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.