Open access for all


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.

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China’s impressive solar story and lessons for India


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.

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Agri-solar too important to be allowed to fail


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.

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Why no renewable power for meeting peak demand?


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.

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Sense of déjà vu as MNRE issues new bidding trajectory


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.

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2022 review | Corporate renewable market coming of age


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.

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2022 review | The worst is over on the bidding front


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.

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2022 review | Financing a bright spark


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.

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2022 review | Lack of home-grown technology a gaping vulnerability


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.

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2022 review | Policy stability and visibility crucial for growth


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.

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2022 review | 30% target shortfall offers lessons for future


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.

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Finally, some respite in module prices


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.

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Macro-economic tide turns away


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!

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ALMM policy a fine royal mess


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.

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Tata Power surges ahead in rooftop solar


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

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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.

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Merchant project structures in play


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

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Viability crisis in the solar sector


National Solar Energy Federation of India (NSEFI), a solar industry association, has warned that about 25 GW of solar projects are facing risk of abandonment due to severe cost hikes over last two years. According to NSEFI, tariff for these projects needs to go up by about INR 0.50-0.80/ kWh for them to become viable. The industry is lobbying with the government for various relaxations including BCD waiver, ALMM deferral and extension in scheduled COD. Given the seriousness of the issue and its potential impact on the sector, MNRE seems sympathetic to the requests and is considering appropriate relief to be granted.

The core problem, of course, is the relentless increase in module prices and other capital costs since July 2020. Even excluding BCD, total EPC cost (ex-land, transmission and soft costs) has shot up by 20% and 49% over last 1 and 2 years respectively. Module prices are staying firm at about USD cents 27/ W. While freight rates and some commodity prices have eased from their highs of about six months ago, the fall has been negated by 8% depreciation of INR against the USD. The sharp fall in module costs as predicted by most analysts has not materialised because of continuing supply side disruption and increasing power cost in China plus surge in global demand. We expect costs to stay elevated for another 3-6 months before improvement in upstream supply side leads to gradual softening next year.

Two interesting facts – minimum tariff for all projects commissioned since January 2021 other than for two projects commissioned by Enel and Avaada is INR 2.48; and minimum tariff for a project commissioned with state offtake other than Gujarat is INR 2.73 in the same period. A simple modelling exercise shows that if module prices fall by 25% ceteris paribus, tariff of about INR 2.50 is barely acceptable for projects with AAA offtake (central PSUs and Gujarat).

Therefore, simplistically assuming INR 2.50 and 3.00 as tariff viability thresholds for projects with AAA offtake and other offtake respectively, 24,739 MW of pipeline is deemed unviable. The chart below shows that Adani, Azure, ReNew, NTPC and Acme have the biggest pipelines of such projects.

Figure: Solar BOO project pipeline

Source: BRIDGE TO INDIA researchNote: Figures exclude hybrid projects.

So what should MNRE do? We believe that it should provide partial relief on BCD and ALMM but hold firm on scheduled COD. The Ministry of Finance has already ruled out grandfathering protection from BCD. But instead of letting projects rely on change-in-law compensation, which is inadequate and likely to be resisted by the DISCOMs, equivalent relief should be provided either in the form of budgetary support to projects auctioned before 9 March 2021. Such relief would be consistent with the policy and address the biggest financial risk to pipeline projects. The government should also waive requirement to comply with ALMM by two years although this measure is unlikely to make any material difference. ALMM is a flawed policy made worse by shoddy implementation and the domestic manufacturing capacity needs time to ramp up adequately.

Any relaxation on scheduled COD front, however, would be contentious and undesirable in our view. It would be contrary to the spirit of competitive bidding guidelines and detract from future bidding discipline. The government has already granted multiple time extensions owing to COVID, supply chain disruption and the Supreme Court order on transmission lines. Taken together, these measures are expected to revive about 10-12 GW of projects.

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Module costs staying firm


Against all industry expectations, module prices continue to move up and show no sign of cooling down. Mono-PERC cell and module prices are currently reported at USD cents 16/ Wp and 29/ Wp, up 18% and 16% YOY respectively. There is relentless cost pressure from the upstream cycle – polysilicon prices have moved to USD 34/ kg, up 33% YOY. Cost of various ancillaries such as aluminium frames, EVA, silver and aluminium paste is also buoyant as EVA, aluminium, copper and silver prices have increased by 200%, 11%, 10%, 9% YOY respectively. The only exception is PV glass, down 42% YOY.

Source: BRIDGE TO INDIA researchNote: Cell and module prices are shown on CIF basis.

Despite excess manufacturing capacity across most of the solar supply chain and rapid ongoing capacity expansion by Chinese majors, supply chains across the country are choked due to Covid-induced lockdowns and curbs on power consumption. Price inflation is also helped by a sharp uptick in global demand subsequent to the Ukraine war and jump in oil & gas prices. Global module demand this year is expected to reach 220-225 GW, an increase of almost 25% over last year. China, already a leader by big margin, wants to upscale solar capacity addition from about 50 GW to 80 GW per annum in a bid to cut emissions. The European Union wants to more than double solar capacity addition to over 50 GW per annum as it seeks to reduce dependence on Russian gas. Similar order of increase is expected in the US, UK, Australia, LATAM and India.

There are also some fundamental structural changes underway in the solar manufacturing industry explaining part of the price increase. China, the dominant supplier, is beginning to keep a central oversight of manufacturing activity in a bid to cut emissions and avoid overcapacity. Provincial governments are withdrawing power tariff incentives to manufacturers. Majors like LONGi, Jinko, Trina and Risen are integrating backwards, accelerating investment in n-type technologies and consolidating their grip on the industry – top 5 companies now account for two-third of production volume. Moreover, they seem willing to cut production rather than drop prices to maintain profit margins.

Prices are widely expected to soften in early 2023 as polysilicon capacity more than doubles over the next 12 months and some supply chain constraints ease off. Some Indian developers believe that module prices could even crash to as low as USD 18 cents. We believe, however, that the fall would be much more gradual and lower, perhaps to around 22-24 cents, for the reasons stated above.

In India, about 18-20 GW of new cell-module capacity is expected to come onstream by end 2023 between Reliance, Adani, Tata Power, ReNew, Premier, Avaada and a few other players. But most of this capacity is expected to be set aside for captive consumption. In any case, India made modules, expected to be priced at a premium of about 15-20% over imported modules, are unlikely to ease pricing pressure.

Overall, the news is not great for project developers. Module prices are not only staying up for longer but also becoming more volatile. The project developers need to get used to the new market reality.

Note: In view of accelerating pace of changes in the module market, BRIDGE TO INDIA has released a new quarterly report titled India PV Module Intelligence Brief. For enquiries, please write to us at market.research@bridgetoindia.com.

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Soaring battery storage costs dim adoption prospects


Greenko has commenced construction of an integrated 5,230 MW pumped hydro storage and solar-wind hybrid project in Andhra Pradesh at an estimated cost of USD 3 billion. The project, with a reported storage capacity of 10.8 GWh, is expected to be commissioned in early 2024. The company would use the project to supply power to SECI under its 900 MW peak power project besides meeting the needs of some corporate consumers (ArcelorMittal and Adani) and IPPs such as Ayana. Separately, the JSW group has expressed a keen interest to develop pumped hydro storage projects. It has already signed MOUs for projects totalling over 5,000 MW in Chhattisgarh (1,000 MW), West Bengal (900 MW), Maharashtra (1,500 MW) and Rajasthan (1,000 MW). The need for storage technology is becoming glaringly evident with morning and evening peak power deficits getting progressively worse over time. Hourly power prices and traded volume data on the exchanges are a clear warning that renewable power is unable to meet critical demand. DISCOMS need firm power to meet peak loads. There is little appetite for new standalone solar or wind projects. The mismatch is bound to get worse with increasing renewable capacity.

Figure: GDAM price and traded volume on Indian Energy Exchange on 1 March 2022

But contrary to all expectations and unlike in other countries around the world, pumped hydro rather than battery storage is finding more traction in India. Slow uptake of battery storage can be attributed to two main factors: soaring costs (and demand-supply imbalance), and policy inertia.

Soaring cost and demand-supply imbalance for batteries

Rising demand and supply side challenges have led to sharp spikes in battery raw material prices. BNEF expects global annual battery storage installations to grow from about 5 GW/ 9 GWh in 2020 to 58 GW/ 178 GWh by 2030. Similarly, global EV sales are estimated to jump from 3.1 million in 2020 to over 50 million in 2030. Indeed, demand growth for clean energy and storage technologies is accelerating since the advent of COVID and Ukraine war. Unfortunately however, supply of minerals is not able to keep up with growing demand. Benchmark prices of lithium carbonate, a key ingredient for the increasingly popular LFP technology, are touching record levels of USD 74,182 per tonne, more than six times prices in January 2021. Price of cobalt has doubled since last January to USD 70,000 a tonne, while nickel has jumped 15% to over USD 20,000 a tonne and price of electrolytes has risen by more than 150%. Prices of lithium-ion battery packs, down to USD 132/ kWh by 2021 have moved up by 20% in just five months to USD 159/ kWh. There are widespread expectations that battery supply would struggle to catch up with growing demand for another 2-3 years at the very least. COVID and Ukraine war have not only pushed up demand but also imposed severe constraints on the entire production and supply side chain. Storage companies, in turn, are moving away from fixed price to structured price contracts to protect themselves from cost volatility risk.

Policy framework not evolving fast enough

So far, the government has announced a few basic measures to delicense storage, give it infrastructure status, allow it to provide ancillary services, waive ISTS charges and issued competitive bidding guidelines. The government has also approved a USD 2.5 billion PLI scheme to develop 50 GWh manufacturing capacity but most of the output is expected to go towards EVs. The challenging part still lies ahead. There is a need to move away from long-term PPAs, make power pricing more market based, reform grid tariff structure, reduce cost of early adopters through incentives, mandate installation targets and demonstrate alternate end use cases through pilot installations. So far, the policy and regulatory system has failed to grasp the need for storage and even seems ill-equipped to design a new paradigm. All this does not augur well for both battery storage and renewable sector. Unfortunately, renewables plus storage is not commercially competitive with coal despite the latter facing its own price and supply side challenges. SECI has issued a first of its kind 1,000 MWh standalone storage tender, which is still in discussion stages. Progress of this tender is going to be a test case for the market.

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IPP valuations driven by technical factors


In the last three years, there have been a total of 33 M&A or private equity transactions exceeding USD 100 million in size in the renewable IPP business. Total investment value of these deals is estimated at USD 12 billion indicating strong lure of the sector. Investors include companies of all hues including oil & gas major (Total, Shell and GPSC), PE funds (Blackrock, Actis, Brookfield, KKR, Mubadala), pension funds (CPPIB, CDPQ, OMERS) and IPPs themselves.

Table: Key M&A and private equity transactions since May 2019

Source: News reports, investor presentations, BRIDGE TO INDIA research

With some notable exceptions (Adani Green, Tata Power), valuations have typically hovered around 9x EBITDA. We estimate that these valuations are equivalent to SPV level post-tax equity IRRs of sub-9% for the incoming investors. At a fundamental level, this return is inadequate even for a ‘de-risked’ portfolio with central government offtake and 1-2 years of operational track record. We are in uncharted territory particularly with long-term resource availability and operational performance risks. But easy liquidity has depressed returns across the market and pushed up valuations on purely technical grounds. Whether this is a satisfactory level of return depends on many other factors.

A case could be built for paying entry premium in a fiercely competitive and rapidly growing sector with multi-decadal growth prospects. In particular, the financial investors – the most dominant investor class – are happy to just get a seat on the table. Investors also seem willing to pay a premium for organisational learning and expertise in building and operating projects besides accounting for accretive option value arising from emerging businesses like storage and green hydrogen.

On the flip side, utility scale project development is a highly commoditised business with open source, easily accessible technology and operational expertise. Moreover, with new business won mainly through fiercely competitive auctions, the possibility of earning premium returns is likely to remain remote. On the contrary, returns are being progressively squeezed. Ability of relatively new players like Ayana (total portfolio including under construction assets 2,367 MW), O2 (1,330 MW), AMP (969 MW), Axis (854 MW), UPC (620 MW), Aljomaih (450 MW), Evergreen and Solarpack (300 MW each) to ramp up the business neatly buttresses these arguments.

We believe that the valuation cycle has peaked. As central banks tighten liquidity and supply side restrictions eat into returns, investment sentiment is set to moderate over the next few years.

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States take on the tendering mantle while SECI goes slow


Pace of tender issuance and auctions has now stayed weak for over two years. Since touching a peak of 38,026 MW and 29,240 MW in 2019, tender issuance and auctions have averaged at annualised levels of 28,742 MW and 19,072 MW respectively. In the first four months of 2022, only 1,875 MW capacity was awarded. The slowdown is mainly because SECI has been prioritising tying up its huge backlog of auctioned projects with DISCOMs. The backlog is estimated to have reduced from about 19 GW back in late 2020 to about 4 GW now. It has issued only one tender of note in 2022 so far – a 1,200 MW ISTS wind tender (tranche 13). In contrast, direct tender issuance and auctions by states has picked up. States have issued new tenders aggregating 7,351 MW capacity so far in 2022 outpacing central government tenders (2,090 MW) for the first time in many years.

Figure 1: Tender issuance and auction, MW

Source: BRIDGE TO INDIA researchNote: Tender issuance figures exclude cancelled tenders.

Main states issuing direct tenders include Gujarat (2,955 MW awarded capacity since 2020), Maharashtra (2,686 MW), Madhya Pradesh (1,275 MW), Punjab (286 MW), Uttar Pradesh and Kerala (200 MW each). It makes eminent sense for Gujarat, a standout state for its highly rated DISCOMs and impeccable payment track record, to issue its own tenders. The state has attractive solar and wind resources, and attracts strong bidding interest from developers.

For most other states, the case for issuing direct tenders is less clear cut. A plausible positive is boost in local economic activity, job creation and tax revenues from intra-state projects, but tariffs in state auctions (excluding Gujarat) continue to come in at about 10-30% higher over central tenders. Competition is relatively low in these auctions as many developers stay away over DISCOM bankability concerns and curtailment risk. Uttar Pradesh, Andhra Pradesh and Punjab have tried to renegotiate tariffs in the last three years. State auctions in the last two years have been dominated by select PSU (NTPC, SJVN) and private Indian developers (ReNew, Tata, Adani and Azure).

Figure 2: Weighted average tariff for solar projects, INR/ kWh

Source: BRIDGE TO INDIA research Note: Data for this figure excludes tenders smaller than 100 MW capacity, cancelled projects, and tenders issued by Gujarat DISCOMs.

With SECI’s backlog of previously auctioned projects expected to be cleared in the next few months, procurement activity should bounce back shortly. We understand that the government is undertaking a comprehensive review of bidding framework in light of poor progress on the execution front and ongoing power supply crisis.

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Private ownership more desirable for renewables


Shell just announced 100% acquisition of Sprng Energy from Actis with an enterprise value of USD 1.55 billion.  The company has a portfolio of 2.3 GW solar and wind projects including 0.8 GW capacity in construction. Earlier this month, Tata Power announced USD 500 million investment from Blackrock and Mubadala, equivalent to about 10% stake, in its integrated clean energy platform comprising project development, EPC, solar manufacturing, C&I, solar pump and EV charging businesses. The two deals, the largest in nearly a year, have been closed reportedly at 9x and 12x FY2023 EBITDA respectively. The deals are a proof that Indian renewable sector continues to be a magnet for the world’s largest investors for its sheer size and growth prospects.

The valuations are significantly more attractive in relation to the two publicly held IPPs, Azure and ReNew, both of which are listed in the USA and currently trading at around 7.5-8.0x FY 2023 EBITDA. The deals again raise the fundamental question: what is the optimal ownership model for Indian renewable assets? A public listing is regarded as the ultimate exit by most project developers and investors – significantly better valuation than in private markets (most buy side analysts assign valuation multiples of 12-20x EBITDA to renewable assets), ease of raising further capital (continuous access to capital markets) and operational freedom for the management (no dominant institutional investors).

But a listing on stock exchanges comes with its own set of constraints and uncertainties. Public markets are impatient and, being prone to general market sentiment, can be irrational. Analysts expect a steady quarter-on-quarter jump in revenues and profits. But that is almost impossible to deliver given the dependence of these businesses on a number of exogenous variables – equipment prices, exchange rates, cost of debt, policy flip flops and delays in PPA execution or transmission connectivity. As an example, US-listed Azure and ReNew are taking a beating along with other international renewable stocks because of fears around rate rises and local regulatory regime.

Figure: Relative performance of Azure and ReNew stocks against S&P500 in last 6 months

Source: Google Finance

Trading history of listed power stocks in India also offers a cautionary tale. The power sector has been perennially ridden with acute challenges including delayed payments from DISCOMs, PPA renegotiation, unviable projects and unpredictable policy. Sobered by past shocks, the Indian public market does not quite seem ready to offer heady valuations to renewable stocks. In contrast, private investors are willing to ride out short-term uncertainty and take a longer term view. Moreover, the huge wall of ESG money pouring into the sector offers a readymade put option to private investors.

NTPC and Tata Power are preparing for jumbo listings over the next 1-2 years. Their progress will be interesting to watch for the whole sector.

PS. This note excludes financial deals or valuation of companies involving Adani group. A separate note on valuation of renewable IPPs shall follow in the coming weeks.

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Wind sector hobbled by soaring costs, unrealistic bids


India added only 1,033 MW wind power generation capacity in 2021, down 14% YOY, taking total wind capacity to 40,709 MW. This is the fourth straight year of decline in capacity addition after competitive auctions replaced feed-in tariff regime in 2017. Out of total allocated capacity of 12.4 GW for vanilla wind projects in the last five years, only 4.3 GW capacity has been commissioned so far. About 3.2 GW capacity has been surrendered voluntarily by project developers on various grounds under SECI tenders. Total remaining pipeline of vanilla wind projects is estimated at 4.9 GW.

Figure: Wind power capacity addition, MW

Source: BRIDGE TO INDIA research

Project completion track record continues to remain extremely poor for multiple reasons. Most importantly, significant cost hikes across the whole value chain and severe land/ ROW availability issues have rendered almost all under construction projects unviable. As a result of increase in metal and other input costs, total EPC cost has surged by 15-20% over the last year alone to about INR 70 million/ MW. The turbine suppliers, faced with increasing cost and execution risks, have been reporting losses over last few years. Consequently, they have resorted to higher prices and derisking of the business by switching from lumpsum EPC model to simple equipment supply model. The Indian manufacturers are in particularly deep financial trouble with many of them partly or wholly shutting down plants.

The project developers are, therefore, having to procure other components and services – project design, land, erection and commissioning, and transmission – piecemeal in many cases further increasing execution cost and risk. Unviable bid tariffs have forced the developers to delay or surrender projects. Some of the largest developers have cited reasons like increased capex, unavailability of land, force majeure etc. while surrendering projects. Average commissioning timeline for projects under initial SECI tenders was 36 months from date of auction. But progress has substantially deteriorated for projects awarded since 2018 onwards (see chart below).

Figure: Commissioning status for wind projects under SECI tenders

Source: BRIDGE TO INDIA researchNote: Dates in this chart represent dates of auction for respective tenders.

Unfortunately, cost pressures and land issues are expected to persist in the foreseeable future. SECI has so far taken a pliant view of project delays and given multiple time extensions to project developers on account of COVID and land/ ROW issues. But we believe that with sub-three INR tariffs being sub-optimal in most cases, many more projects are likely to be abandoned.

Such poor progress of wind sector is a cause for alarm. The role of wind power, as a complementary technology for solar power, cannot be understated. It is critical for balancing the grid and meeting India’s lofty climate targets. The government ought to undertake holistic assessment of the sector as well as the competitive bidding framework to unlock growth. More specifically, the tenders should have adequate safeguards against unrealistic bids and punishing errant bidders.

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