Category: Market Outlook

The Directorate General of Trade Remedies (DGTR), Ministry of Commerce, has initiated an anti-dumping probe into import of solar aluminium frames originating from China. The investigation period will cover FY 2023, while injury duration period will cover four years from FY 2019-2023. A petition for the probe was filed by Vishakha Metals, a company jointly promoted by the Adani Group. The petitioner has claimed to be the sole manufacturer of solar module aluminium frames in India and has claimed injury from increased imports, price undercutting and price suppression by Chinese suppliers.

In response, some module manufacturers have already called for termination of the investigation. They have claimed that as the targeted foreign suppliers supply a vast range of aluminum products to multiple industries, it is not possible to establish their direct use in module manufacturing.

Prior to this, similar anti-dumping investigations have been completed for several solar module components. Two petitions were successfully filed by RenewSys in 2022 and 2019 challenging import of backsheets and EVA sheets respectively, resulting in duties of USD 762-908/ MT on imports from China and USD 537-1,559/ MT on imports from multiple countries respectively. Borosil filed similar petitions covering solar glass imports in 2017 and 2019 which resulted in 5-year levy of anti-dumping duties of USD 52-136/ MT and USD 115/ MT on Chinese and Malaysian imports. The company subsequently applied for an extension of duty on Chinese imports, which was approved by DGTR but rejected by the Ministry of Finance after protestations from the module manufacturers.

Table: Anti-dumping duty on solar module components

Source: DGTR, BRIDGE TO INDIA researchNote: Dumping margin refers to anti-dumping duty as a percentage of dumped product price in India.

Despite such considerable duty protection, ancillary component manufacturing has failed to match pace of module manufacturing growth. Module manufacturers complain of limited capacity, poor quality and high cost. There are only a handful of specialised players in India for each product – EVA sheets and backsheets are made by RenewSys and Vishakha Renewables (total capacity 6 GW and 7 GW capacity respectively), while solar glass is made primarily by Borosil with an equivalent capacity of only 5-6 GW of solar modules (about 70% of current demand levels). More capacities are in the pipeline particularly by Reliance and Adani, both aiming to be fully integrated manufacturers, but shortages seem likely to continue.

With the levy of BCD and upcoming growth in downstream module manufacturing, the battle lines for trade barriers have now shifted to upstream manufacturing. It is plausible that there will be similar duty petitions from polysilicon and wafer manufacturers in future. Each duty petition will mean more uncertainty for both manufacturers and consumers, and a further increase in the cost of domestic production.

SECI has issued a first-of-its-kind tender for procuring 500 MW ‘firm and dispatchable’ renewable power. The tender specifies a fixed hourly demand profile across the year, unchanged during the 25-year PPA term (see figure). Project developers must meet at least 90% of total hourly demand on a monthly basis. Penalty for any further shortfall is stipulated at 1.5x PPA tariff. They may use any combination or type of solar, wind and storage technologies. Entire power output up to specified demand profile shall be bought by SECI for supply to Punjab DISCOMs. Projects are required to be completed within 24 months of the agreement date. The tender is still in draft stage and some provisions are likely to undergo changes following market consultation.

Project developers have been given some freedom to offset the technology and execution risks. They may source up to 5% of specified annual demand from external sources without any penalty. They can also vary the type and sizing of storage technology, which may also be procured from third parties – ideal for using pumped storage capacity, which has a longer gestation period and is limited to a few suppliers. Moreover, different project components can be split across different locations. Excess power may be sold to any third party but SECI has reserved the right to buy surplus output up to contracted capacity at 50% of PPA tariff.

The specified demand profile, with prominent morning and evening peaks, seems to favour deployment of more wind capacity. Base, peak and average load stand at 33%, 100% and 69% respectively.

Figure: Hourly demand profile for every 1 MW of contracted capacity, MW

Source: SECI, BRIDGE TO INDIA research

Project developers face a bewildering array of design possibilities – sizing of different components, location, timing – and associated risks. Possible configurations range from an extreme of 4-5x solar capacity combined with up to 100% pumped storage capacity (limited market exposure) to wind heavy designs with about 10-20% storage capacity and more market exposure. The latter designs will be more commercially competitive subject to assumptions about market exposure for sale of surplus output. Limited visibility on long-term market pricing of renewable power will be one of the key challenges for bidders. It is worth noting that intra-day deviations are not allowed for exchange-based transactions leading to the risk of high deviation penalties.

There is a lot of anticipation in the market particularly as SECI seems keen to push more such tenders in the near future. However, we expect competition to be limited with ReNew, Ayana, Hero and NTPC among likely participants.

Firm renewable power supply is a holy grail for the renewable power sector. We are not aware of any such tender design anywhere in the world and SECI should be commended for testing innovative solutions, having previously tried alternate designs including ‘peak’ power and ‘round-the-clock’ power. The new design follows more than a year of consultation with DISCOMs, who have been reluctant to buy more renewable power because of intermittency and variability concerns. But the merit of locking into a fixed 25-year procurement profile, without any flexibility when technology and demand patterns are changing rapidly, is debatable. And to the extent that the design promotes oversizing of project capacity, it restricts overall system flexibility. A bid to provide ‘firm’ power to one utility may end up in dumping unwanted power on others skewing market behaviour.

MNRE has issued details of an INR 44 billion (USD 537 million) subsidy scheme for domestic electrolyser manufacturing. The scheme will be operational from FY 2026 to FY 2030. In the first tranche, 50% of subsidy funds shall be allocated to a manufacturing capacity of 1.5 GW. Domestically produced electrolysers shall receive a fixed subsidy based on year of production – INR 4,440/ kW (USD 54) in year 1 tapering down to INR 1,480/ kW (USD 18) in year 5. Bidders will be selected through a competitive bidding process based on local value addition (LVA) and specific energy consumption quoted by them over the first 5 years of operations. Conditions include a minimum life of 60,000 hours and minimum 50% of annual sales in India. 20% of subsidy funds are reserved for bidders using indigenous technology.

Each bidder will be assigned an annual score for LVA and specific energy consumption quoted in its bid (see figure below). The scores have been calibrated for different technologies based on their maturity. Final selection will be based on the highest sum of product of annual LVA and energy scores. There are strict penalties for failure to meet the quoted LVA and specific energy consumption norms. In case the actual LVA is less than 95% of quoted value, or specific energy consumption is higher by up to 2 kWh/ kg in any year, the bidder will be paid no subsidy that year.

Figure: Scores for annually quoted performance parameters

Source: MNRE, BRIDGE TO INDIA research

SECI, nodal agency for the scheme, has already issued a tender for selection of manufacturers for setting up 1.5 GW of capacity under tranche 1. The manufacturing facilities must be set up within 24 months of receiving LOA.

Assuming specific energy consumption at 50 kWh/ kg and LVA factor at 0.8, total incentive payout is expected to offset only 8% of the capital cost of electrolysers. The two most important questions to ask at this stage are – Does this subsidy make a meaningful reduction in cost of green hydrogen and contribute to greater demand? And does it make India-made electrolysers cost competitive vis-à-vis imports? The answer to both these questions is unfortunately No. We estimate the net reduction in final cost of green hydrogen at only USD 0.05/ kWh, accounting for only 3% of the cost disadvantage over grey hydrogen. This is too small an amount to make any material difference to green hydrogen demand, the most critical challenge facing this sector. There is a lesson to learn from the US, which is finding that despite extremely generous subsidies on offer, there are no willing offtakers for green hydrogen. The country is being forced to consider demand side measures to spur the market. In fact, electrolysers manufacturers around the globe are facing financial uncertainty due to weak demand.

As for all clean energy technologies, Indian electrolyser manufacturers are expected to face stiffest competition from China. It is worth noting that the green hydrogen production scheme does not mandate use of domestically produced equipment. Taken together with 7.5% basic customs duty as applicable at present, the proposed subsidy provides protection for up to 16% cost differential, which seems insufficient for the nascent business. Domestic manufacturers are likely to ask for more.

MNRE has released details of first tranche of the subsidy scheme for green hydrogen production. Total funding support of up to INR 54 billion (USD 659 million) will be offered to annual production capacity of 450,000 metric tonnes (MT), 9% of 2030 target. Subsidy will be capped at INR 50, 40 and 30/ kg in first, second and third year of production respectively and offered to producers quoting the lowest three-year average requirement in a competitive bidding process. In case of a tie, the subsidy will be offered to the bidder with higher project capacity. There is no specific sale restriction on successful bidders, who will be required to tie offtake on their own. A further subsidy budget of INR 76.5 billion (USD 933 million) has been set aside for the second tranche, for which demand will be aggregated by the government. SECI has been appointed as nodal agency for the scheme.

The scheme is silent on use of technology or sourcing of electrolysers. In the absence of sufficient domestic electrolyser manufacturing capacity, most of the equipment is expected to be imported. Up to 40,000 MT of production capacity is reserved for green hydrogen produced by using biomass-based power. Remaining capacity may use any other source of renewable power subject to complying with the National Green Hydrogen Standard, to be notified by MNRE shortly.

Table: Capacity allocation under green hydrogen subsidy scheme

Source: MNRE, BRIDGE TO INDIA research

Assuming 10 year project life, average subsidy works out to a maximum of USD 0.15/ kg, a fraction of incentive available in the US, EU and Canada. The US is offering fixed incentive of USD 3.00/ kg for 10 years plus 30% investment tax credit and further adders for underlying renewable power projects. Taken together, all these incentives mean that cost of green hydrogen in the US may fall close to zero. The EU is also offering a generous subsidy of up to USD 4.34/ kg over a 10-year period.

The government has separately extended 25-year ISTS waiver benefit to green hydrogen projects commissioned by December 2030 besides waiving Additional Surcharge on renewable open access. Accounting for these benefits, we expect cost of green hydrogen to fall to USD 3.70/ kg, still 66% above the cost of grey hydrogen. Additional subsidy benefit for manufacturing electrolysers is too small to make any material difference to this number. Some states including Uttar Pradesh, Gujarat and Andhra Pradesh have proposed additional incentives for green hydrogen but the total quantum is relatively insignificant.

Figure: Green hydrogen production cost, USD/ kg

Source: BRIDGE TO INDIA research

With such a high cost differential, it is difficult to envision any material demand arising unless consumers have a regulatory compulsion to switch to green hydrogen. The export market is also unlikely to take off at these prices. The government will need to offer more policy support for improvement in green hydrogen prospects.

This video presents a summary of major sector developments including tender issuance and auctions in May 2023.

Final tariff orders issued by state regulators for FY 2024 show an upward trend in transmission and wheeling charges. Transmission charges increased by 20%, 14% and 14% in Maharashtra, Rajasthan and Haryana respectively. Transmission loss increased by 18% in Rajasthan, while wheeling charge increased by more than 50% in Andhra Pradesh. In some states including Madhya Pradesh, Karnataka and Uttar Pradesh, wheeling losses reduced by 18%, 10% and 9% respectively. As a result of all these changes, total open access (OA) charges payable by captive solar projects in Rajasthan, Andhra Pradesh and Maharashtra increased annually by 11%, 10% and 9% respectively.

A look at five-year trend in individual components of OA charges shows that transmission charges and losses have been mostly stable across states. There is relatively more volatility in wheeling charges. As expected, Additional Surcharge (AS) and Cross Subsidy Surcharge (CSS) are the most volatile components, but these charges are waived for captive projects.

Figure 1: Trends in individual OA charges in select states, INR/ kWh

Source: Tariff orders, BRIDGE TO INDIA researchNote: Charges are shown for industrial consumers connected at 33 kV.

As Figure 2 shows, total OA charges have increased appreciably across most key states over the last five years. The biggest increase has been seen in Gujarat, Maharashtra, Tamil Nadu and Andhra Pradesh. OA charges in Maharashtra, Tamil Nadu and Gujarat (INR 2.10-2.82/ kWh) are the highest in the country. The bulk of the increase in Gujarat has come from levy of a flat banking charge of INR 1.50/ kWh on entire power output. The increase in charges, combined with unfavourable changes in grid tariff structure, dilutes financial attractiveness of solar OA projects particularly in Gujarat, Tamil Nadu, Andhra Pradesh and Maharashtra, where OA savings have been reduced to less than 25% of variable grid tariff. Mandated introduction of TOD tariffs from April 2024 with day-time discount of 20% for corporate consumers, would almost completely wipe out all savings.

Figure 2: Long-term intra-state OA charges for captive solar projects for industrial consumers, INR/ kWh

Source: Tariff orders, BRIDGE TO INDIA researchNote: OA charges are shown for industrial consumers connected at 33 kV. Charges exclude CSS, AS, electricity duty, short-term exemptions and any proposals in draft stages. 15% of total power output is assumed to be banked.

There is more financial burden coming for OA consumers. Telangana and Karnataka have proposed additional grid support charges of INR 0.13-3.01/ kWh, while Madhya Pradesh wants to levy an energy development fee of INR 0.10/ kWh on captive projects. Rajasthan and Karnataka have introduced a captive power generation tax of INR 0.20-0.40/ kWh. Rajasthan DISCOMs have even proposed taking 10% of power output free of cost from ISTS OA projects.

The Green OA Rules issued by the Ministry of Power aim to provide visibility on OA charges and put an end to imposition of arbitrary charges. States have been required to use a common methodology for determination of charges and levy only transmission charge, wheeling charge, CSS and standby charge on OA projects. States are beginning to adopt the Green OA Rules but deviations persist. As an example, Telangana has omitted the AS exemption. Lack of visibility in OA charges continues to be a major risk for the OA market.

Concerned by poor progress in the wind power sector, the government has made a series of announcements to stimulate capacity addition. It has notified a specific wind tender issuance sub-target of 10 GW annually until FY 2028 on top of hybrid and RTC tenders. It has also set a separate incremental wind RPO target of 6.94%, within the 43.33% RPO target by March 2030, to be met only by projects commissioned after FY 2022. That equates to new wind capacity addition of 70 GW over eight years. Other measures include replacement of reverse auctions by a single stage bidding process to tone down aggressive bidding behaviour, a move to issue state specific tenders to ease land and evacuation infrastructure availability, and levy of severe penalties on developers failing to complete projects on time.

Wind sector has been slowing down since transition to reverse auction in 2017. While tender issuance and auction activity has been relatively healthy, project execution has been marred by delays in land acquisition, spiralling costs and unviable bids. Capacity addition has averaged a mere 1.8 GW per annum over the last five years. In contrast, CEA has estimated need for 82 GW new wind capacity by FY 2032 as part of the recently announced National Electricity Plan.

Figure: Wind sector progress, GW

Source: BRIDGE TO INDIA research

Meanwhile, the industry has been taking action to correct course. Turbine makers have invested in more efficient technology, cut costs, raised prices and passed on execution risk to developers. After several years of reporting losses, Suzlon, a leading Indian turbine manufacturer, reported a net profit of INR 29 billion in FY 2023 as against a net loss of INR 2.6 billion in FY 2022. Inox Wind and Senvion have restructured operations and are seeing a revival in profitability. Envision has rapidly expanded manufacturing capacity to 3 GW and already built an order pipeline of almost 4 GW. The project developers have also turned more cautious. Tariffs in the latest SECI auction in June 2023 came in the INR 3.18-3.47/ kWh range, up 14% since the previous SECI auction in Dec 2022 and up 37% from the all-time lows of 2017. Bidding interest has also waned significantly.

But the most critical support for wind power is coming from the growing need to balance solar power’s high intermittency. Because of wind power’s complementary output profile, power utilities and corporate consumers are looking mainly to procure hybrid power with a willingness to pay a premium over cost of standalone solar power. In the auctions completed so far, wind’s share of total project capacity under wind-solar hybrid and wind-solar-storage hybrid tenders is about 25% and 70% respectively.

While the rationale for some of the government moves including push for more tenders and move away from reverse auctions is debatable, better technology, more commercial prudence and greater market demand are all strong drivers. We expect sharp jump in market activity with total estimated wind capacity addition of 30 GW over the next five years.

The Ministry of Power has again relaxed green open access (OA) rules. OA will now be available to groups of consumers, connected to a single DISCOM, with combined sanctioned load of 100 kW or more instead of being restricted to individual consumers with a minimum sanctioned load of 100 kW. This ‘group OA’ concept is conceptually a huge change from restriction of OA to consumers with minimum sanctioned load of 1 MW, as is the practice even today in most states.

The relaxation is significant because it opens OA to small and mid-size commercial users, who not only pay the highest grid tariffs, but also have limited alternate avenues for renewable power procurement. Most such consumers do not have access to physical space for deployment of on-site solar systems. REC and green tariff routes are both unattractive as they are grid cost plus. While OA may not be viable for many small, standalone consumers because of its regulatory and procedural complexity, large corporates with distributed operations in the form of say, regional offices, bank branches, retail stores, petrol pumps, telecom towers etc should find it attractive. The relaxation also potentially opens up the market to SME businesses under pressure to decarbonise from their corporate customers.

OA solar power, ideally suited to most commercial consumers based on their hourly consumption requirements, is expected to be financially attractive despite higher PPA tariffs and grid charges.

Figure: Landed cost of OA solar power for LT commercial consumers, INR/ kWh

Source: BRIDGE TO INDIA researchNote: Landed cost of OA power includes PPA tariff plus all applicable grid charges and taxes. Variable grid power cost includes energy charge, fuel adjustment charge, surcharges, taxes and duties

The new provisions will inevitably face some enormous challenges, not least from DISCOMs refusing to let go of their most lucrative consumers. A massive operational effort would be required to make ‘group OA’ work in practice – process OA approval for each individual consumer, execute multiple wheeling and banking agreements, and upgrade billing infrastructure. Virtual net metering, a somewhat similar concept, has been around in rooftop solar sector for some time without any meaningful progress. Even though, Chhattisgarh, Delhi, Goa and all other Union Territories have already adopted it formally in the regulatory regime, implementation has not moved beyond some pilot installations.

MOP’s recent reprimand to states on their reluctance to enforce green OA rules is a good start to improve enforcement. It has asked state regulators to “…implement the Green Open Access Rules notified by the Central Government and align Open Access Regulations in accordance with the notified Rules, at the earliest.” It has further instructed them to report compliance status of green OA rules and warned them of punitive action in case of any contravention.

The other practical problem with ‘group OA’ is that most target users are based in leased premises with grid connections in the names of their lessors. In such cases, the lessors will need to apply for OA and execute tri-party agreements with lessees and power generators, both potentially tricky steps.

There are bound to be lots of teething troubles and implementation delays along the way. Nonetheless, making OA available to more consumers is a significant reform of the power sector. MOP should be lauded for both giving more choice to consumers and putting pressure on states to reform the distribution business.

China is expected to add a record 125 GWp solar capacity this year, 5x the next biggest player (US) and up 44% over capacity addition in 2022, which itself was up 64% over the previous year. Total solar capacity is expected to cross 500 GWp by the end of this year, ahead of national target. The country has become a giant on the international solar scene with some staggering statistics:

In December 2022 alone, it added 21 GWp solar capacity, more than what any other country added in the whole year and 1.3x India’s capacity addition in 2022.

Distributed solar, comprising rooftop and small ground-mounted projects, contributed a massive 63% share (55 GWp) in new capacity addition in 2022.

It produced 827,000 MT polysilicon (up 64% YOY), 357 GW wafers (57%), 318 GW cells (61%) and 289 GW modules (59%) last year accounting for about 80-95% of global production.

Total solar exports comprising 154 GW modules (up 42% YOY), 24 GW cells (220%) and 41 GW wafers (41%) touched a record high of USD 52 billion in 2022.

Figure: Solar capacity addition and module production in China, GW

Source: PVTime, BRIDGE TO INDIA research

Back in 2009, China identified solar as one of ten emerging industrial sectors where it wanted to achieve global leadership. The country has strategically marshalled resources, implemented policies across different arms of the government and ploughed massive capital in R&D and new industrial bases. The national government sets growth targets through five year plans, wherein the current plan envisages increasing share of renewables (ex-hydro) in consumption from 11.4% in 2020 to 18% by 2025. The targets are considered sacrosanct and often realised ahead of time.

The government has brought in key policy changes to overcome emerging constraints in the sector.  Capacity addition was historically incentivised with attractive feed-in-tariffs but an accumulation of unpaid subsidies drove a move to market determined prices in August 2021. When meeting enormous land and transmission infrastructure requirements of the sector became a problem, the government took initiatives like locating projects in desert areas and pivot to distributed renewables. Under the Whole County Rooftop Solar scheme, large developers are allocated whole counties with targets to cover a certain percentage of rooftops within a set timeline. Another initiative involves aggregation of demand by regional players and sale of bulk project development rights to large developers, typically state-owned enterprises.

The government has played a critical role in developing domestic technology expertise by subsidising R&D and offering incentives to both manufacturers and project developers. The hugely successful Top Runner programme with tariff subsidies for higher efficiency modules is credited with accelerated shift from multi-crystalline PV to mono-PERC. Now, many provincial governments have mandated use of storage in new projects to address solar’s intermittency concerns.

It helps that China has an absolutist government style that can cut through bureaucracy and override public opinion. No other country can match it on speed of decision making, execution or huge size of the domestic market – share of solar in total power generation capacity and total power generation is still only 15% (16% in India) and 3% (5%) respectively. Despite emphatic efforts and willingness to bear a heavy financial burden, other countries are struggling to reduce their dependence on Chinese manufacturing. But China’s long-term vision and extensive use of state support with special focus on scale and technology still offer useful lessons for Indian policy makers.

Last four months have seen a flurry of activity in the agri-solar market with 23 new tenders totalling 7.3 GW capacity under KUSUM (components A, C-II) and state schemes. Since January 2020, a total of 73 tenders aggregating 25 GW capacity have been issued so far under these schemes. Maharashtra and Madhya Pradesh have tendered maximum capacity of 14.4 GW and 4.8 GW respectively, followed by Karnataka (1.3 GW) and Gujarat (1.1 GW).

Figure: Agri-solar tender issuance and project allocation since Jan-2020, MW

Source: BRIDGE TO INDIA research

While tender issuance is booming, subsequent progress is disappointing. Most tenders are heavily undersubscribed and/ or indefinitely delayed due to poor response. Only 1.25 GW capacity is believed to have been allocated so far, while total installed capacity across all schemes stands at only 653 MW. Main problem relates to intensive effort required for land acquisition and execution for a portfolio of small projects spread across vast regions. Project developers expect a tariff of circa INR 4.00/ kWh (USD 0.05), a premium of about 50% over utility scale projects, to make up for the extra cost and higher risk. But most tenders come with ceiling tariffs of about INR 3.30/ kWh or lower. A further complication is requirement to match L1 prices. With eligibility thresholds being kept intentionally low to encourage higher participation from farmers and other developers, stray low bids spoil prospects for other bidders.

Table: Agri-solar tender specifications

Source: BRIDGE TO INDIA research

The KUSUM scheme was announced in 2019 with a target of adding 17 GW solar capacity (excluding solar pumps) by 2022. The target was later revised upwards to 20.75 GW. In view of poor performance, the scheme deadline was extended to 2026. The government has tinkered with many scheme provisions including removing bank guarantees, relaxing project size limit and eligibility criteria but with little success.

The concept of agri-solar is too important to be allowed to fail. Distributed solar projects alleviate pressure on land and transmission grid, provide supplemental income to farmers and potentially improve farm yields. The government must find a way to reform the scheme to make it attractive for both farmers and solar project developers. New concepts like agri-voltaics, combining agriculture with solar power generation, should also be explored.

As summer hits India, power demand is rising again leading to fears of shortages and blackouts. On 18 April 2023, demand hit this year’s high of 216 GW and crossed last year’s peak demand. Over the next two months, peak demand is expected to touch an all-time high of 229 GW, up 8% over last year. The government is going all out to avert a power crunch. It has directed all thermal plants using imported coal to ensure 100% capacity utilisation from March 16 onwards. Domestic coal fired plants have been mandated to use 6% imported coal to ensure adequate fuel availability. Gas-fired stations are being revived – NTPC is operating 5,000 MW gas-fired capacity, while its trading subsidiary NVVN has floated a tender to procure 4,000 MW gas-fired power. GAIL has been asked to ensure sufficient supply of fuel during this period.

The government has also introduced a special trading window on the exchanges with a higher ceiling price of INR 20/ kWh for gas and imported coal-based plants. Alongside these short-term measures, support is also building up for adding new coal-fired capacity. 21 projects totalling 28,210 MW capacity are under construction by various central and state-government owned PSUs. NTPC also has more than 10,000 MW capacity under different stages of development.

This cycle of high temperatures, followed by surge in power demand and focus back on thermal power repeats every year. And it brings barely any mention of renewable power, which reflects an outdated mindset that this power always comes with an intermittent output profile. This approach is not only slowing energy transition and growth of renewables, but also proving extremely costly and risky in today’s geo-political environment. The flawed approach is being helped by a skewed set of incentives. Coal attracts customs duty and GST of only 2.5% and 5% as compared to respective rates of 20-40% and 12% for solar power equipment. It is extraordinary that the DISCOMs are seemingly happy to pay up to INR 10-11/ kWh and up to INR 7-8/ kWh for short-term and long -term thermal power respectively but refuse to buy storage-based renewable power at prices of around INR 4-6/ kWh. 

Figure: Cost of RE-storage hybrid and marginal thermal power, INR/ kWh

Source: Merit India, BRIDGE TO INDIA research

It is worth noting the various perils of greater reliance on coal, which besides being the dirtiest power source, needs huge investments in mining and transportation infrastructure. Production cost is constantly edging upwards due to inflation besides being exposed to high volatility in coal prices. Coal imports increased by almost 70% in March 2023 as compared to last year. Somewhere between 50-90% of coal-fired plants are almost always operating with critically low coal stock presenting a great supply side risk. Moreover, setting up new coal-fired plants requires minimum lead time of 5 years as against 2.5 years for new renewable projects.

The government needs to shed its ambivalence towards renewable power and show more commitment to the sector. Instead of offering subsidies and other support to thermal power, resources should be diverted towards developing indigenous technology and manufacturing capability in green technologies across the spectrum.

MNRE has prescribed an annual bidding trajectory of 50 GW renewable capacity until FY 2028. It has further mandated that at least 10 GW per annum of this capacity should be reserved for wind projects. For the current financial year, the government wants tender issuance of at least 15 GW capacity each in the first two quarters and 10 GW each in the subsequent two quarters. These targets shall be split amongst various government agencies like SECI, NTPC, NHPC, SJVN and state PSUs.

The new bidding trajectory comes mainly as the government is keen to accelerate progress towards meeting the 500 GW renewable capacity target for March 2030. Annual capacity addition remains stuck in the 12-15 GW region as against a target of over 45 GW. Outlook for the next two years appears flat. The industry has also been pressing the government for a visible tender trajectory to enable more efficient planning and supply chain management.

This is the second time the government has issued a bidding trajectory – the first one, announced in 2018, had a target of 80 GW new tenders in three years. However, the result of the government trying to push new tenders was far from encouraging. Many tenders were undersubscribed and/ or cancelled owing to poor design, low ceiling tariffs, unrealistic commissioning deadlines, and/ or challenges in obtaining land and transmission connectivity. Even when auctions were successfully completed, DISCOMs refused to come forward to contract purchases or project construction got stuck because of high execution risks, policy uncertainty and low margins.

As the following figure shows, gap between tender issuance, auction and project commissioning has become progressively bigger over time.

Figure: Progress on renewable tenders, MW

Source: BRIDGE TO INDIA researchNotes: Capacity numbers are shown on a cumulative basis from 2016 to YTD 2023. Commissioned capacity excludes open access projects.

The intention behind issuing a bidding trajectory is laudable, but issuing more tenders without fixing underlying problems will only add to uncertainty in the sector. Instead, the government needs to focus on creating demand by using a carrot and stick approach with DISCOMs and other bulk consumers. Investments in new thermal projects, sending a confusing signal to all stakeholders, need to be avoided. Second, various supply side constraints like land, transmission, equipment and financing need to be addressed by creating a stable policy framework. Finally, the competitive bidding process needs to be tightened to ensure that all sides stick to their commitments.

India added 3,761 MW corporate renewable capacity in first nine months of the year, 61% more than in whole of 2021. The numbers are especially pleasing because of a series of recent adverse developments including increase in construction costs, imposition of BCD and ALMM, and high policy uncertainty. The jump has come mainly from spurt in solar open access (OA) capacity addition of 2,608 MW in the first nine months. In comparison, both OA wind and rooftop solar have been struggling with total capacity addition of only 1,153 MW.

Figure 1: Corporate renewable capacity addition, MW

Source: BRIDGE TO INDIA research

OA growth has been led by Tamil Nadu (750 MW) and Karnataka (643 MW) together accounting for 49% of capacity addition in the 9 months to September 2022. These two states have been mainstay of the business for a few years. The major positive is emergence of other bigger states like Maharashtra (386 MW), Gujarat (336 MW) and Rajasthan (203 MW) as growth engines.

OA market resilience can be attributed to two developments. There is a paradigm shift in consumer behaviour with larger corporates driven more by decarbonisation push rather than cost savings. That has made a big difference at a time when costs and tariffs have been inching up. Adoption of net zero and other such pledges like RE100 is leading to pressure to increase renewable penetration as evident from recent deals by Vedanta, Amazon, ArcelorMittal, Adani and Reliance. We understand that Reliance alone plans to install 20 GW captive solar generation capacity by around 2027.

Figure 2: Major renewable OA project announcements

The corporate push, in turn, is giving way to a more favourable policy environment. The central government has taken the lead with new green OA rules, new RPO trajectory until FY 2030, ISTS waiver and relaxation of transmission connectivity procedure. The recently launched green open access portal has already seen 2,210 project applications being approved. Even state governments and DISCOMs, historically resistant to the market, are beginning to bow to consumer demand – Gujarat and Maharashtra being prime examples in that regard. Karnataka, Madhya Pradesh, West Bengal and Punjab have already issued draft policies consistent with green OA rules. Five states including Haryana, Madhya Pradesh, Chhattisgarh, Himachal Pradesh and Punjab have proposed to accept revised national RPO trajectory.

BCD, ALMM and shortage of high efficiency modules domestically still pose considerable short-term hurdles. But to compensate, we expect CERC to effect ISTS waiver for OA projects in the coming few months. That, together with module supply situation easing from H2 2023 onwards, should provide a further boost to the market. We expect the OA market to grow at a CAGR of 25% plus in the next five years.

2022 was an exceptional year in terms of project auctions. There was a double whammy for project developers as they were hit by weak demand from DISCOMs and escalating costs. Total auctioned capacity fell by 47% over previous year to just 9,855 MW, a five year low. There were only 3 auctions over 100 MW between all central government entities aggregating 3,500 MW, down 71% YOY. Slowdown in auctions understandably led to an increase in bid subscription rates and competitive intensity. The three main SECI auctions were over-subscribed by 2.5x, 3.3 and 3.7x. Tariffs inched up only marginally in response despite both solar and wind EPC costs shooting up by a further 25% and 27% YOY respectively.

SECI spent most of 2022 trying to clear backlog of unsigned PPAs, now down to an estimated 7 GW as against 19 GW in early 2021. As a result, ratio of auctions with state offtake increased to 64%, a six year high, due mainly to Maharashtra (3,675 MW) and Gujarat (2,250 MW) filling up the void.

Figure 1: Capacity allocation split by technology and offtake, MW

Source: BRIDGE TO INDIA researchNote: Data excludes cancelled projects.

The impact of weak auction activity was felt immediately in bid tariffs. The trend is best summarised by tariff trends for auctions by Gujarat, which has been a more consistent issuer in terms of tender design and frequency in comparison to SECI and other states. While solar EPC cost increased by 43% between Q4 2020 and Q2 2022, GUVNL auction tariffs increased only by 25% from INR 1.99 to 2.49/ kWh in the same period. Weighted average solar tariff for auctions more than 100 MW increased by 8% in the year over tariffs a year ago. Tata Power (1,674 MW), SJVN (1,133 MW), NTPC (1,076 MW), Fortum (800 MW) and Ayana (740 MW) were the leading project winners.

Figure 2: Weighted average tariffs and EPC cost

Source: BRIDGE TO INDIA researchNote: Data excludes cancelled projects, projects under agricultural schemes and tenders smaller than 100 MW capacity. EPC cost excludes land and transmission connectivity.

It has been a year of learning for the industry. New risks have materialised on every possible front – land acquisition, transmission, equipment cost and availability, interest rates, exchange rates and policy uncertainty. As a result, the relentless optimism of earlier years has given way to a bit more caution and discipline. As we look to the new year, prospects are brightening up on power demand and input costs. Pent up demand is expected to lead to substantial uptick in auctions. And costs have already started trending down. For project developers prepared to be patient and prudent, there could be some attractive bidding opportunities in near future.

Amongst all the travails including land, transmission, cost pressures, delays in equipment supply and policy uncertainty, financing continued to be somewhat of a bright spot for the renewable sector in 2022. The year saw as many as 18 equity investment deals totalling at least USD 3,873 million, up 79% over 2021. In addition, there were 16 M&A announcements with enterprise value exceeding USD 4,539 million, down 17% YOY and 7 offshore debt funding deals totalling USD 2,170 million, down 68% YOY.

We can glean a few noticeable trends by looking at the list of key transactions. Most of the financing activity was focused on power generation assets but manufacturing also attracted some interest. Waaree, Jupiter and Premier raised money successfully for their cell and module plant expansion plans. C&I business continued to attract major interest as shown by recent investments by KKR (Serentica, USD 400 million) and Partner’s Group (Sunsure, USD 300 million). There was even a first-of-its-kind USD 25 million investment by Neev Fund in in Hygenco, a hydrogen venture. Investment interest came mainly from overseas financial investors – including a mix of pension funds, PE funds, sovereign funds and infrastructure funds from across the globe – again proving strong appeal of India’s renewable sector for international investors. But M&A activity was counter-intuitively led by strategic investors including Shell, JSW, Sembcorp and Torrent Power. 

Table: Key financing transactions in 2022

Source: BRIDGE TO INDIA research Note: For M&A deals, amount shown represents estimated enterprise value except for Apraava, Solar Arise and Inox Wind transactions. Some of the announced transactions may not have been completed yet.

The year was particularly noticeable for poor appetite of the public markets. Inox Green, a wind turbine O&M company belonging to the Inox group, was the only company to successfully complete an IPO worth INR 7.4 billion (USD 90 million). But the IPO just about sailed through and the shares are currently trading below issue price. Waaree abandoned its IPO plans after investors expressed concerns about heavy reliance on government incentives. Vikram’s proposed IPO seems to be stuck for similar reasons. Meanwhile, other listed stocks including ReNew, Azure and Sterling & Wilson also had a poor showing, all trading well below their issue prices as well as relevant indices.

On the debt financing front, things were again mixed. Greenko, ReNew and Continuum raised a total of USD 1.5 billion through overseas green bond issues in early 2022. Avaada and Virescent also raised a total of USD 274 million in domestic bond market but as the year progressed, tightening monetary conditions and greater risk aversion turned markets bearish.

To sum up, it was a year of busy deal making. Strong investment interest is a major positive for the sector. However, there are some worrying signs too. There is an unease because of acute challenges and unviable projects. Some international investors have curtailed their India business, while others have exited the business altogether, leading example: Softbank.

In a recent note, we identified land, transmission and technology as the most acute supply side challenges for the renewable sector. Dependence on overseas technology is a key risk specifically for the Indian renewable sector. However, technology receives little attention in the discourse on sector dynamics.

It is well known that about 90% of modules used in India’s solar sector have been imported historically. But the country’s technology dependence on external parties goes far beyond this. The entire inverter supply comes from outside India although some of these suppliers now assemble products in India. It is the same story for other key solar project components like trackers and robotic cleaning. For wind turbines, Indian suppliers together account for about 50% market share but all technology is sourced internationally. In any case, most critical turbine components are still imported. Global battery manufacturing capacity has grown rapidly to cross 1,000 GWh, whereas India is just entering the race. There are billions of R&D dollars being deployed in clean energy technologies but again India’s share is negligible.

Figure: Leading suppliers for projects commissioned between 2017-2021

Source: BRIDGE TO INDIA research Notes: Capacity figures are stated for grid-connected projects in MW AC. Data excludes rooftop solar and other distributed renewable systems.

The Make in India thrust should help but it does not sufficiently address the core question of technology dependence. All fundamental technology know-how and even manufacturing lines and installation personnel for new PV cell and module lines, being set up currently, are coming from overseas suppliers. The downside of such heavy technology dependence is vulnerability in times of trade wars, geo-political disturbances and material shortages. We have already witnessed that when polysilicon capacity became constrained recently, module supplies to India were terminated and shipments were diverted to other countries willing to pay higher prices. Boom in clean energy demand worldwide is creating increasing fragility in international supply chains. Other countries are entering into a competitive race to attract investments and technology.

There is another dimension to dependence on global technology. Most technology R&D is focused on developing products for a specific use case, ambient conditions and financial capacity typically for customers in rich western countries or perhaps China. As we have seen in multiple sectors including electronics, automobiles, healthcare amongst others, India’s demand is of an altogether different nature. Germany may need high powered 4-W EVs with large batteries performing ideally in cold temperatures, whereas India mostly needs smaller vehicles travelling shorter distances in a hotter, dustier environment. Dependence on other countries often means overpaying for sub-optimal technology from an Indian viewpoint.

By various estimates, India is going to invest over USD 300 billion in this decade on clean energy. Consulting firm McKinsey estimates the country’s total spend on decarbonisation by 2050 at between USD 7-12 trillion. It cannot afford to spend all this money being completely beholden to foreign technology. The government needs to take the lead by developing domestic research capability, providing R&D grants, signing international technology transfer agreements, incentivising use of new technologies and making technology a key focal point of all policies. As an example, power procurement framework needs to evolve from simply choosing the lowest tariff to paying a premium for more efficient technology that uses less land and water resources, and more locally available, eco-friendly materials.

The central government has issued a total of 139 renewable sector related policies and related amendments in the last five years. That number could be multiplied by about 25x to account for multiplicity of bodies including state governments, regulators, nodal agencies and DISCOMs to understand magnitude of policy overload in the sector. It seems that the policy makers have been too busy in constantly formulating and tinkering with the policy framework.

While there is no doubting good intent of the government, such frequent changes are causing anxiety in the market place. The framework is failing in too many respects – shifting and often conflicting priorities, poor design, disjointedness between different arms of the government and disregard for practical considerations. The resulting policy confusion has disastrous consequences as we have seen with increasing frequency in recent times – unviable investments, supply bottlenecks and underperformance over targets.

The following graphic illustrates some case studies showing how key areas of the sector have suffered due to frequent changes on the policy front. Multiple schemes and legislative measures focused at improving DISCOM financial condition have failed to provide any durable relief to investors. The Make in India push has created infinite confusion and constrained supply of equipment. Self-sufficiency in even basic technologies remains a distant dream. On key matters like RPOs, solar parks, open access rules and rooftop solar, the central government has failed to get state governments on board. Policies concerning Renewable Energy Certificates (RECs) and quality standards have been designed and tweaked far too frequently in an ad hoc manner.

Figure: Examples of frequent and ad hoc policy changes

Source: BRIDGE TO INDIA research

The importance of government policy in shaping growth of the renewable sector cannot be overstated. Large land and transmission infrastructure requirement, intermittent power output, rapidly changing technology landscape, new business models and, a need for self-sufficiency in an era of trade wars and geopolitical concerns warrant a deft manoeuvring act on the policy front. And the ask is bound to multiply several fold over time as renewable energy penetration increases and new market mechanisms like carbon markets are developed. It is a herculean task but the government needs to provide policy stability and visibility to counter these uncertainties.

There is little time to lose. The government has set ambitious growth targets but global competition for capital, skills and commodities is intensifying. There is an urgent need to improve quality of policy making. The answer lies in augmenting resources, developing technical expertise and ensuring strong inter-departmental and regional coordination.

Note: Policy is defined in this piece to include regulations.

As we approach end of the year, we will spend the next few weeks reviewing overall progress of the renewable sector and prospects for the next phase. We estimate total renewable capacity (ex-large hydro) to touch 122 GW by December against Government of India’s 2022 target of 175 GW – a deficit of 30%. Solar and wind capacity shortfall is expected to be 34% and 30% respectively. Wind deficit is actually much higher at 52% when measured against capacity expected to be installed between 2015-2022.

The following figure shows annual growth in installed capacity alongside key policy milestones. Wind capacity growth has suffered badly since transition to competitive auctions in 2017. In contrast, solar capacity has grown more consistently but at a much lower than the required rate of about 15 GW per annum.

Figure 1: Growth of renewable sector and key milestones

Source: BRIDGE TO INDIA research

There are five key reasons for such significant underperformance.

Insufficient demand from states25 of the 30 states had FY 2022 RPO targets lower than the central government target of 21.18%. Even the low targets have been rarely enforced by state regulators because of poor financial condition of DISCOMs, intermittency concerns, lack of renewable resource and/ or land at reasonable cost. Amongst the larger states, main laggards are Uttar Pradesh, Haryana and West Bengal.

Figure 2: State RPO targets and compliance for FY 2022

Source: BRIDGE TO INDIA research

Land and transmission bottlenecksInitiatives such as solar park scheme, green energy corridors and renewable energy zones have faced extensive delays and cost overruns. Almost every single utility scale project faces acute land and transmission challenges delaying execution.

‘Make in India’ rush The government’s sudden policy pivot to ‘Make in India’ in 2019-20 with implementation of measures like BCD and ALMM, when there was insufficient domestic capacity, led to large chunks of project pipeline becoming unviable and facing risk of abandonment.

Poor integrity of bidding processExcessive policy focus on reducing cost of renewable power instead of, for example, addressing renewable power’s intermittency issue or facilitating timely completion, has been a major detraction. The overly loose bidding framework has allowed both offtakers and project developers to wriggle out of their commitments with little untoward consequences.

Policy uncertainty in corporate renewable marketImmense growth potential of corporate renewable market has been frustrated by DISCOMs and state regulators with ad hoc policy measures unnerving both consumers and investors.

In absence of policy stability, better coordination at central and state levels, and proactive long-term planning, the sector has been muddling along. But these challenges are going to get more acute over time. A further slowdown is expected in 2023 as MNRE has granted 12 month extension to solar projects facing module availability and price constraints. Urgent lessons need to be learnt to ensure smoother progress going forward.

Module prices have finally started softening. After shooting up by 65% over two years to USD 0.30/ W, international prices have eased off to USD 0.26 on CIF basis for delivery in Q2 2023. The price decline has come, as expected, due to massive capacity expansion across the value chain in China. Global polysilicon capacity, a key constraint, has already increased from about 290 GW equivalent in Q1 2022 to about 350 GW and is further set to cross 536 GW by end of the year and 700 GW by end of 2024. Similarly, global wafer, cell and module capacities are estimated to grow by 50-70% to 800 GW, 750 GW and 800 GW respectively by end of 2023. More than 90% of all these capacities are based in China.

The Chinese solar manufacturing industry is in a boil. After many small players exited the business, new players like Shangji, Shuangliang and Lihao have entered the fray with mega plans. Meanwhile, existing players have been rapidly expanding as well as integrating forward and backwards. And all of them are spending heavily on R&D and investing in new, more efficient n-type technologies. It has become normal for companies to set up new plants with capacities in tens of GW. Example: Jinko, planning to ship 42 GW modules this year, has increased its 2022 wafer/ cell/ module capacity estimates from 40/ 40/ 50 GW to 65/ 55/ 70 GW respectively in just 12 months besides investing in two upstream polysilicon ventures. On the other end of the value chain, Tongwei, a leading polysilicon manufacturer is aiming to grow its capacity over four-fold by 2025 and is also entering module manufacturing business with 25 GW lines.

With such large-scale new capacities coming online, prices have started moving downward. The trend is expected to accelerate next year. Infolink, a Chinese consulting company, expects mono-grade polysilicon prices to halve to USD 20/ kg by end 2023. However, decline in cell and module prices is expected to be more modest for multiple reasons. Downstream manufacturers, under financial pressure for some time now because of shrinking margins (high polysilicon costs) and large capex needs, are hoping to use this period to shore up their profitability. Moreover, they are intent on pushing out new n-type products at higher prices (and margins) and it is likely that a significant portion of spare p-type capacity would be phased out restoring some sort of balance on demand-supply front. There are also still concerns about COVID cases potentially disrupting supply and pullback of preferential electricity tariffs in Inner Mongolia province after Yunan and Xinjiang earlier this year.

Figure: P-type mono-crystalline module and polysilicon prices

Source: BRIDGE TO INDIA research, Infolink

We expect China module prices to decline to about USD 0.22/ W by end 2023. Cell prices are likely to be stickier in comparison. For the Indian market, relief would be even more gradual because of BCD and inadequate manufacturing capacity. Domestic module prices should maintain their 25-30% premium over imported modules falling to about USD 0.28/ W over the same time period.

After more than a decade of exceptionally benign macro-economic environment, the global financial markets are facing greater disturbance and volatility. With natural steady state of the economy shaken first by COVID and now the Ukraine war, a domino effect is in play affecting inflation, cost of capital and exchange rates across countries. Inflation has soared to recent highs due to a combination of factors including increase in oil & gas and other commodity prices, trade wars and supply side disruptions. Monetary tightening by central banks has led to interest rates spiking up around the world. The 10-year Indian gilt yield has widened to 7.4% since touching a low of 5.9% last year. The Rupee has been falling sharply against USD, now down 11.5% since January 2022 and an annual average of 4.6% over last ten years. Yields on USD-denominated green bonds, the mainstay of debt financing for larger project developers, have more than doubled in last six months to 10-11% levels.

The last decade was unprecedented in macro-economic terms – extremely low inflation and interest rates on account of ample monetary easing by central banks and shift in manufacturing to China. But now that the economy has turned, the investors are in a state of panic. There are concerns about mounting deficit and leverage at both sovereign and corporate levels. There is greater risk aversion and migration of capital to safe havens further compounding volatility in asset prices and risk premia.

Figure 1: Exchange rate and bond yields

Figure 2: Annual changes in inflation indices, %

Source: S&P Global, RBI, BRIDGE TO INDIA research

For the renewable sector, timing of these developments coming on top of increase in equipment costs, supply side blockages, BCD on solar cells and modules, ALMM, transmission line stay order in Gujarat and Rajasthan besides the usual policy uncertainty in open access and rooftop solar markets is far from favourable. Project financial models have long done away with any contingency for macro-economic parameters. On the contrary, project developers have been building overly optimistic assumptions on inflation (5% or less), interest (8% for Rupee debt) and exchange rates (limited hedging, 3% annual depreciation). We estimate combined effect of adverse movements in macro-economic parameters at around 15-20% of project value.

Table:  Impact of recent macro-economic developments on renewable project values

Note: Inflation impact excludes increase in price of core products like solar modules and wind turbines.

The macro-economic tide has added to the aggravation caused by sector specific issues. There are some signs of commodity price easing but it seems fair to assume that overall geo-political and economic volatility is here to stay for some time. The industry needs to re-calibrate its approach to macro-economic risks and build sufficient buffers to guard itself.

Finally, we wish all our subscribers a joyous Diwali with lots of happiness and good health!

The Delhi High Court has rejected a petition filed by the Distributed Solar Power Association, an association of C&I market focused project developers and EPC contractors, to delay ALMM implementation for open access and net-metered rooftop solar projects beyond 1 October 2022. Separately, MNRE has clarified that ALMM would apply only to open access and net-metered rooftop solar projects submitting their first application for project approval from 1 October 2022 onwards. Bizarrely, however, it has exempted behind-the-meter systems from ALMM requirement. The ruling makes ALMM applicable to more than 98% of solar sector spanning all government tendered projects (bid submission after 9 April 2021), open access and net metered rooftop solar projects (submitting initial project approval application from October 2022 onwards).

Total ALMM approved module manufacturing capacity has more than doubled to 20.2 GW across 66 companies in the last 12 months. Leading approved names include Waaree (4.8 GW), Vikram (2.0 GW), Adani (1.7 GW), Goldi (1.5 GW), Renewsys (1.2 GW), Premier (1.2 GW) and Emmvee (1.0 GW). But a quick scan of the approved list shows that a significant portion of the approved capacity is sub-scale and/ or technologically obsolete:

48 of the approved companies have manufacturing capacity of less than 200 MW each and totalling 3 GW.

13 companies with total manufacturing capacity of 3.8 GW make only modules rated at less than 400 W when the latest international models are rated at 700 W plus.

20 companies with total manufacturing capacity of 1.4 GW make only multi-crystalline modules. Only 7 companies make bifacial modules – Vikram, Premier, Adani, Waaree, Renewsys, Goldi and Emmvee.

No cell manufacturing capacity has been approved as yet.

Figure: ALMM approved manufacturing capacity

Source: MNRE, BRIDGE TO INDIA researchNote: The figure shows only select companies with new approved capacity of more than 200 MW.

Despite the increase in approved capacity, there are not enough modules available in the market. Actual domestic production in the 12 months to June was estimated at only 5,644 MW. There is a dearth of high quality products and the manufacturers are calling the shots. MNRE has so far refused to grant ALMM approvals to overseas manufacturers although that policy is seemingly under review following concerns about high prices and limited availability of domestic modules (USD 0.38-0.40 cents/ W). Even if MNRE reconsiders its stance, the international manufacturers face another practical problem. The entire process of BIS and ALMM certification usually takes more than 12 months. By the time they are likely to get ALMM approvals, respective models would have been outdated because of rapid advancements in technology.

ALMM is an ill-conceived policy, helping neither the domestic manufacturers, who already enjoy formidable protection from imports because of 25-40% BCD, nor the project developers and consumers. The policy has ended up creating needless bureaucratic red tape for no benefit. It needs to be binned immediately.

BRIDGE TO INDIA estimates that the country added 2,520 MW rooftop solar capacity in the 12-month period to June 2022, up 44% YOY. Based on the latest data compilation exercise, total rooftop solar capacity is estimated to have reached 10,221 MW, 17% of total solar capacity in the country. But growth was uneven across consumer segments – residential and commercial segments registered marked slowdown in the face of sharp cost rises while the industrial segment saw a boost as companies rushed to beat BCD and ALMM implementation deadlines.

(Micro) industrial segment leads the way

Installation costs jumped sharply in Q2 2022 due to BCD levy and increase in component and execution costs across the board. We estimate current costs at INR 52/ W and 73/ W for industrial and residential systems respectively, up by about 30% in comparison to levels a year back. Inevitably, there was a negative impact on the market as contractors passed cost increase to consumers, who deferred purchase decisions. But industrial consumers and installers took advantage of the duty-free window up to March 2022 to bring forward purchase decisions. Most of the growth seems to have come from smaller industrial installations, typically less than 500 kW in size and somewhat unaffected by net metering policy uncertainty. Q1 is also a typically busy period for such consumers keen to claim depreciation benefit by the end of the financial year.

Figure 1: New installations by consumer segment, MW

Source: BRIDGE TO INDIA research

Further slowdown in OPEX model

The OPEX model continues to lag rest of the market, a direct consequence of shift towards relatively smaller industrial and residential consumers. OPEX share of C&I activity fell to only 13% in H1 2022, a six year low. Part of the reason for this slowdown is that some historic leaders like CleanMax, Cleantech and AMP are creating a market void by consciously prioritising open access business over rooftop solar in push for higher volume and faster growth.

Figure 2: C&I installations by business model, MW

Source: BRIDGE TO INDIA research

Tata Power racing ahead

Perhaps the most glaring trend in the market is aggressive growth of Tata Power, who is capitalising on booming demand and weak competition. The company is a rare example of a big brand corporate showing clear commitment to rooftop solar with systematic investments in distribution and logistics infrastructure. It has also benefitted from relatively easier availability of modules owing to its presence in the manufacturing business. The company has consistently gained share over the last five years in an otherwise highly fragmented market – growing to 15.7% in EPC business and 16.9% in OPEX business. A late entrant in the OPEX business, it is now ranked third behind only Amplus and Fourth Partner.

The latest numbers again point to rooftop solar market resilience and strong growth potential notwithstanding mounting policy pushback and commercial pressure. MNRE has refused to consider extension in ALMM requirement beyond September 2022 for net metered installations but extended phase-II residential subsidy scheme until March 2026. Looking ahead, we expect weakness in the next 6-12 months before there is relief from inflationary pressures and improvement in module supply.

Corrigendum: Module PLI 2 to benefit fully integrated manufacturers

MNRE has finally released details of module manufacturing PLI tranche 2 worth INR 195 billion (USD 2.4 billion). The budget has been split into three categories based on backward integration by the bidders. Separate PLI rate, completion time and local value addition requirements have been specified for the three categories.

Table: Different bid categories

Note: Actual PLI rate would be derived from a grid comprising a range of module efficiency and thermal coefficient parameters.

Companies shall be selected on the basis of a bidding process based on three criteria in decreasing order of importance: module efficiency, local value addition and manufacturing capacity. Minimum module efficiency is specified as 20.50%. SECI is expected to issue a detailed RFS document outlining details of bidding process shortly. Minimum bid size is 1 GW, while the maximum is 10 GW including capacity awarded in tranche 1. Like in tranche 1, PLI shall be paid annually for actual production volume up to 50% of awarded capacity for first five scheduled years of operations. Actual payment amount shall be weighted by local value addition factor of 0.73-1.00 plus another tapering factor of 1.4, 1.2, 1.0, 0.8 and 0.6 over five years respectively.

There are some notable changes from tranche 1 scheme. The PLI rate has been cut sharply from INR 2.25-3.75/ W to a maximum of INR 2.20/ W. Successful bidders will need to set up separate facilities for recycling of solar waste although any details are missing in this regard. They will also need to source at least 20% of their power requirement from renewable energy sources. If they fail to adhere to quoted efficiency and local value addition parameters but still meet the minimum scheme requirements, the PLI amount would be reduced by 25% for the respective year.

Our calculations suggest that tranche 2 can support about 52,000 MW of manufacturing capacity – 24,000 MW fully integrated, 16,000 MW wafers-modules and 12,000 MW cells-modules.

Reliance and Adani are expected to be the biggest beneficiaries. Both companies are already in advanced stages of finalising plans for upwards of 10,000 MW polysilicon-module capacity. First Solar should also be placed well in the first category. It is possible, however, that the first two categories would be undersubscribed, while the third category would be oversubscribed with interest from Tata Power, Vikram, Waaree, Premier, Emmvee, ReNew, Jakson and Avaada.

We estimate effective subsidy amount at only about 2.5-5.0% of expected revenues, which seems insignificant in the context of strict bidding requirements and associated risk of penalties. On the other hand, it is unclear why any subsidy is necessary when there is a massive tariff barrier against all imports. Such incentive schemes restrict competition and potentially delay adoption of new technologies. This money could be deployed far more productively in domestic R&D efforts, speeding up storage deployment and expanding the transmission system.

Amazon has announced its first foray in utility scale renewables in India with an innovative deal structure. The company, running a large data centre in Telangana, has signed three long-term solar PPAs for a total capacity of 420 MW with ReNew (210 MW), Brookfield (110 MW) and AMP (100 MW). The projects would be built in Rajasthan, connected to the inter-state transmission grid and registered with the International Renewable Energy Certificate (I-REC) registry. Amazon would retain I-RECs for its own use to help achieve its goal of reaching RE 100 by 2025 but sell entire ‘brown’ power’ output on the exchange.

Telangana has been refusing to grant open access connectivity for past few years and VPPA structures are still not viable as CFD instruments are not permitted in India. These constraints forced Amazon to turn to a modified VPPA structure, which allows it to get assured bulk supply of I-RECs while complying with the principle of ‘additionality.’ We understand that the PPA price is around INR 2.85/ kWh. To achieve a net I-REC cost of INR 0.30/ kWh (USD 4 per REC), consistent with recent trading trend, the company would need to realise average power sale price of INR 2.55/kWh. This is a bold call in view of the solar power output profile.

The Amazon deal comes around the same time as many other project developers have expressed willingness to develop projects on a ‘merchant’ basis. At least three developers including ReNew, NTPC, NHPC are already setting up merchant power plants. Serentica, a newly incorporated project development platform by Sterlite Power, is also keen on the idea.

Merchant power became a dirty word in India about ten years ago after about 40,000 MW thermal capacity, developed without PPAs, became financially distressed (no coal linkage, no buying interest from DISCOMs, low prices on the exchange). The turnaround in sentiment has now come about for two main reasons. Most importantly, investment appetite is soaring again even as the DISCOMs remain reluctant to sign PPAs. The extremely competitive nature of auctions has forced developers to consider other options. On the other hand, recent power demand growth has surprised on the upside. Constrained supply has led to exchange prices shooting up – average conventional Day Ahead Market prices have recently doubled to about INR 6.00/ kWh, a near 100% increase over prices during 2017-2020.

Figure 1: Average conventional Day Ahead Market prices, INR/ kWh

Source: Indian Energy Exchange, BRIDGE TO INDIA research

Development of merchant capacity is conceptually beneficial for the sector leading to an increase in transparent, exchange-based trading of power. However, the timing is not favourable with capital costs at near 5-year highs. Projects developed at current capex levels would not be competitive in the long run. There are significant additional risks for investors. Most lenders, having burnt their hands in the past with merchant thermal projects, are not comfortable taking market risk. We therefore expect only the largest, most well capitalised developers with strong banking relationships to venture down this path. An even bigger potential risk is uncertainty in intra-day demand and prices. As solar penetration increases (India’s FY 2030 solar target is 280 GW against average expected demand of about 250 GW), daytime prices are likely to trade ever lower. The widening divide in hourly prices is illustrated in the following figure.

Figure 2: Average hourly prices on conventional day ahead market, INR/ kWh

Source: Indian Energy Exchange, BRIDGE TO INDIA research