ALMM chaos


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 It was, however, inexplicably withdrawn within a week creating a state of confusion and speculation in the industry.

We believe that the proposed amendment was withdrawn for two reasons – it was poorly drafted with many ambiguous provisions and led to a storm of protests from the domestic manufacturers.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

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

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

Figure: Estimated domestic module availability, GW

Source: BRIDGE TO INDIA research

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

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

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Project developers facing equity crunch


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

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

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

Figure: Equity investment deal announcements, USD million

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

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

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

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DISCOMs scramble for green attributes


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

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

Table: Availability of green attributes for consumers

Source: BRIDGE TO INDIA research

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

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

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Surge in auctions hard to sustain


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

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

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

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

Source: BRIDGE TO INDIA research

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

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

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

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Government throwing it all at residential rooftop solar


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

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

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

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

Figure: New rooftop solar installations by consumer category, MW

Source: BRIDGE TO INDIA research

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

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Encouraging progress on green hydrogen


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

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

Figure: Green hydrogen production bid winners

Source: BRIDGE TO INDIA research

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

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

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

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Lots riding on 2024


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

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

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

Here are our major themes for the year.

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

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

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

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

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

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

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

Lok Sabha elections

ALMM policy announcement

Auction of ‘firm’ power tenders

Offshore wind tender

Waaree IPO

Announcement of a new PLI scheme for BESS

Implementation of tariff pooling mechanism

Implementation of new carbon market

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Slow 2023 failed to live up to high hopes


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

Key positive developments

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

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

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

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

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

Key negative developments

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

Figure: Capacity addition in 2023, MW

Source: MNRE, BRIDGE TO INDIA research

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

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

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

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

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Oil & gas companies show renewed ambition


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

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

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

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

Figure: 2022 capital expenditure split for oil & gas majors

Source: Reclaim Finance Analysis

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

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Maharashtra’s new regulations – open access neutral, rooftop solar positive


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

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

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

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

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

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

Source: BRIDGE TO INDIA research

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

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Carbon market – key details still missing


The Bureau of Energy Efficiency (BEE), an agency set up under the Ministry of Power to promote energy efficiency, have issued more details of India’s carbon trading scheme announced back in June. In the first phase starting FY 2024, 89 companies across four sectors including iron and steel, cement, petrochemicals and pulp & paper shall be subject to GHG emission intensity based annual targets. The targets shall be applicable only to partial scope 1 and 2 emissions – direct emissions from fuel combustion and indirect emissions related to power consumption. The Ministry of Environment, Forest and Climate Change is expected to shortly announce specific targets for each of the four sectors for three years up to FY 2027. Companies exceeding their GHG emission reduction target at the end of every year shall be issued carbon credits, while those falling short would be mandated to buy credits. The credits may be traded on the power exchanges or retained by the companies for future utilisation. The government has nominated CERC as the scheme regulator and the Grid Controller of India for managing a carbon market registry.

The scheme scope – range of sectors, number of obligated entities and type of emissions – is expected to be enhanced over time. The government has set an aggregate emission reduction target of 1 billion tCO2e by FY 2030 covering additional sectors like textiles, aluminum, chlor-alkali, transport, building and agriculture.

The scheme design – a baseline and credit system with intensity-based emission reduction targets – is similar to the one adopted by China. It acknowledges the Indian government stance that economic growth must take precedence over environmental considerations. In contrast, most developed economies have chosen to adopt absolute emission reduction targets.

Table: Comparison between international carbon trading schemes

Source: International Carbon Action Partnership, BEENote: Average carbon price for California market is given for 2022.

Several key details including applicability threshold for companies, ability to use offsets and industry emission targets of the scheme are still missing. Given the lack of availability of these crucial details, commencement of the scheme from next year onwards seems improbable. Unless the initial targets are kept very low, which is very likely, the corporates would find it challenging to prepare in such limited time.

As yet, there is also no information available on how and if the carbon trading scheme would be integrated with other market mechanisms like REC and PAT, which are designed ultimately with the same objective of reducing corporate emissions. Multiple schemes operating in parallel, with different targets and trading mechanisms, is likely to lead to confusion and operational challenges.

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Improving domestic debt outlook a big plus 


The three central government financial institutions (FIs) – PFC, REC and IREDA – have been aggressively expanding their debt exposure to the renewable sector. In the last few months, REC and PFC have together sanctioned debt of INR 57 billion (USD 684 million) to Serentica Renewables for its 960 MW wind solar hybrid project portfolio. PFC has sanctioned another INR 102 billion (USD 1.3 billion) and INR 22 billion (USD 269 million) to JSW and Vibrant Energy for financing Mytrah Energy acquisition and 300 MW wind solar hybrid projects respectively. REC has approved debt funding of INR 61 billion (USD 729 million) for Greenko’s 1,440 MW pumped storage project in Madhya Pradesh. In addition, PFC and REC have signed several MOUs with project developers including ReNew (INR 640 billion), Avaada (INR 200 billion), Apraava (INR 91 billion), Hero Future (INR 62 billion), and Acme (INR 40 billion), among others, to finance their upcoming projects.

The three FIs have been the mainstay of greenfield project finance for some time now. Their seven year cumulative sanctions and disbursements to the renewable sector stand at INR 2,133 billion (USD 26 billion) and INR 1,151 billion (USD 14 billion). Total outstanding exposure to the sector has grown over 6x in seven years to INR 1,030 billion (USD 12 billion) as of March 2023, approximately 50% of total debt quantum in the sector. The FIs have always enjoyed the advantage of ability to write bigger cheques for longer tenors, but now they have also managed to reduce their lending cost and cut processing times by making due diligence and documentation approach more friendly. Cost for greenfield projects has fallen by more than 1.0% in the last two years, despite interest rates going up, to about 9.0-9.5% per annum.

Figure: Debt financing in the renewable sector

Source: Reserve Bank of India, annual reports of IREDA, PFC, REC, BRIDGE TO INDIA researchNote: Annual debt requirement is estimated for solar and wind sectors based on new installations in respective years, while total FI disbursement data includes financing for other technologies including biogas, pumped storage and e-mobility.

After steadily reducing their total exposure to power sector from 2.4% of loan book in FY 2019 to 1.7% in FY 2023, the domestic banks are also turning more positive. The banks have been marginal players in renewable financing so far but improvements in overall techno-commercial maturity of renewables, general power sector outlook and DISCOM financial position have eased many of their credit concerns. Most public and private sector banks are keen to enhance their lending to the sector. The State Bank of India recently sanctioned INR 27 billion (USD 326 million) to ReNew for its 403 MW peak power project, one of its biggest underwriting commitments in the sector. Some banks including Punjab National Bank and Bank of India have also signed MOUs with PFC and REC for co-lending to renewable projects.  

The sector is likely to need fresh annual debt up to INR 800 billion (USD 9.6 billion) as project construction picks up in response to low module prices, ALMM waiver and strong demand in the corporate market. That represents only about 5% of total FI and bank exposure to the power sector and should be easy to fund domestically. The healthy appetite of domestic institutions is a great comfort at a time when the offshore markets have become more expensive and uncertain.

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Record low module prices a boost for project developers


Module prices have been on a downward trajectory for fifteen straight months now. China FOB prices plummeted to a record low of USD 0.14/ W last week, 53% lower than all-time highs reached in Apr-June 2022 and down 46% YOY. The sharp price decline owes to massive supply glut in China and fall in upstream component prices. Polysilicon prices have declined to USD 11/ kg, down by 72% YOY, while cell prices are now reported at just USD 0.06/ W, down 65% YOY. Domestic module prices have also fallen in response while maintaining a premium of about 40-50% on landed cost of imports.

Figure 1: Module import volumes and prices

Source: PV Insights, Infolink, OPIS, BRIDGE TO INDIA researchNote: Prices are shown for mono-PERC modules on CIF basis.

China’s polysilicon-wafer-cell-module manufacturing capacity, growing at an unprecedented pace, is expected to cross 1,000 GW by end 2023. July and August polysilicon, cells and module production reached 233,500 tonnes, 85 GW and 77 GW, an unprecedented YOY surge of 94%, 78% and 80% respectively. But international demand has failed to keep pace (see figure below) due to subdued demand in Europe and elsewhere.

Figure 2: China module exports, GW

 Source: Infolink Consulting

Given the supply excess, arguably set to worsen because of domestic manufacturing initiatives in the US, EU and India, prices are widely expected to stay soft for the foreseeable future. News reports indicating inventory build ups in China also suggest these low prices persisting at least over the next 6-9 months. However, the outlook beyond H1 2024 is less certain. With the supply chain facing tremendous margin pressure, many players, especially the tier 2 and tier 3 suppliers, are expected to phase out up to 300 GW of relatively obsolete cell and module capacity. It is also difficult to rule out managed factory shutdowns as seen in the past. As demand begins catching up, prices may pick up from next year onwards.

For the Indian buyers, the fall in prices coming at the same time as ALMM waiver is great news. Import volumes have been surging steadily for six months now and are expected to reach as high as 5 GW per month by the end of the year. Domestic manufacturers are also able to sustain their margins thanks to limited availability and the attractive export market.

The biggest unknown for the Indian market is applicability of ALMM post March 2024. Domestic module availability is not expected to pick up materially until the end of next year and the project developers are hopeful of another extension. If that extension does not come through – the manufacturers are lobbying the government against such a move – limited supply and consequent spike in prices would hurt capacity addition prospects in 2024.

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No cogent plan for offshore wind


MNRE has again revised offshore wind plans and outlined alternative project development models. The revised target is to auction 37 GW capacity by FY 2030, up from 30 GW as announced last year, primarily off the coast of Tamil Nadu and Gujarat. Three different models are proposed – i) lease of pre-identified sites to developers for supply of power to DISCOMs with viability gap funding (VGF) support; ii) lease of pre-identified sites to developers for supply of power to DISCOMs or under open access; and iii) others. In addition to the VGF support, the government has agreed to undertake development of power evacuation infrastructure, waive ISTS charges and additional surcharge (AS) for projects commissioned by December 2032, and offer REC multipliers and carbon credit benefits (not quantified yet). Concessional custom duty has also been proposed on import of components required for offshore wind turbines.

Table: Alternate models for development of offshore wind projects

MNRE is proposing to offer VGF for 1 GW capacity, split equally across Tamil Nadu and Gujarat projects, for supply to the respective DISCOMs. The Ministry of Finance has approved a quantum of INR 68 billion (USD 817 million). Final approval from the Cabinet is expected shortly. The VGF is sized to reduce the final cost of power to about INR 3.50/ kWh, maximum tariff that the DISCOMs are willing to bear.

MNRE has also issued a preliminary tender under model B for allocating seven equal sized sites covering an area of 1,443 sq km off the coast of Tamil Nadu for developing 7.2 GW capacity (5 MW/ sq km). Lease rental has set at a floor of INR 0.1 million/ sq km per annum. NIWE shall be responsible for securing stage 1 and stage 2 clearances from various government departments. No firm offtake is on offer. Final bids are expected to be invited in early 2024. The government has offered a lease period of only five years for site surveys, project development and construction, extendable for full operational life post commissioning date. Without a firm offtake, subsidies and long-term lease, the tender is unlikely to make any progress.

The government first announced offshore wind plans in 2018 with a target of developing 5 GW capacity by 2022. These plans have been revised several times with little concrete progress. Model A is the only viable route in the current market environment but a cap of 1 GW is too low for creating an eco-system and improving risk perception. Unless the government offers further funding and offtake support, investors are likely to be deterred by high project development, construction and operational costs, long gestation period and an undeveloped eco-system.

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Rooftop solar market stagnant


As per our latest data collection exercise for rooftop solar market, total capacity addition in the 12-month period ending June 2023 was about 2,540 MW, up only 1% YOY. The residential market witnessed steady growth with annual installations totaling 797 MW (up 21% YOY) but the corporate installations were down 6% YOY at 1,743 MW. Total installed capacity is estimated to have reached 12,762 MW with share of industrial, commercial and residential segments at 54%, 25% and 21% respectively.

Figure: New installations by consumer segment, MW

Source: BRIDGE TO INDIA research

Q1 is typically the strongest quarter for new installations but this year was marred by high module prices and ALMM. Another reason for sluggish growth is unfavourable policy and regulatory framework relative to open access since the issuance of Green Open Access Rules. Issues like system size ceiling of 500 kW for net metering, imposition of grid charges in many states and ad hoc restrictions on behind-the-meter systems have affected the market badly.

Residential segment growth was again led by Gujarat and Kerala, which added 475 MW and 137 MW capacity, 60% and 17% share respectively of the market. Encouraging progress was also seen in other states like Maharashtra (73 MW), Uttar Pradesh (21 MW) and Madhya Pradesh (16 MW). The market is improving on the back of recently launched national portal for rooftop solar subsidy applications. Timely disbursal of subsidies, together with reduced role of DISCOMs and freedom to choose vendors, has resulted in demand growth particularly from tier 2 and 3 cities.

In the corporate rooftop solar market, policy flux continues to impact market prospects. Maharashtra (278 MW) and Karnataka (274 MW), the historic leaders, were followed by Uttar Pradesh (132 MW) and Tamil Nadu (130 MW). The latter two states showed an impressive YOY growth of 190% and 85% respectively due to shift from gross metering to net billing in the last 20 months. On the other hand, Rajasthan witnessed a slowdown due to increasing restrictions on behind-the-meter systems in the form of levy of grid charges.

Figure: Corporate installations in select states, MW

Source: BRIDGE TO INDIA research

OPEX model installations hit a 5-year low at 279 MW in the year. OPEX market share has now fallen for three straight years to 16% from a high of 43% three years ago. The market is seeing a loss of appetite from both demand and supply sides. Most consumers, now well versed with operational aspects, are happy to bear investment risk while the project developers are more keen to pursue big ticket business in the open access market. Amplus, Fourth Partner and Tata Power are the three biggest developers. In the EPC category, Tata Power maintained its leading position, but other top spots were taken by relatively newer entrants like Roofsol and Enerparc.

Figure: Corporate installations by business model, MW

Source: BRIDGE TO INDIA research

Stagnation of the rooftop solar market is a missed opportunity and a policy blunder. While growth is expected to pick up in the short-term with sharp fall in module prices and temporary ALMM relaxation, the market remains largely untapped.

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Duty battles linger in upstream solar supply chain

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.

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SECI seeking new frontiers with a ‘firm’ renewable power tender


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.

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Electrolyser subsidy – what’s the point?


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.

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Green hydrogen subsidy too little to make an impact


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.

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BRIDGE TO INDIA – India RE Tenders Update – May 2023


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

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Low visibility in OA charges still a major risk


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.

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Better days are here for wind power


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.

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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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