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Maharashtra has allocated a remarkable 9,000 MW agri-solar project capacity across 95 project developers. The state agency, MSEB Solar Agro Power Limited (MSAPL), had issued a flurry of tenders in the last three months for setting up distributed solar capacity in chunks of about 10-15 MW each for injection at individual substation level. There were two different kinds of tenders – for individual projects and for aggregated district level (about 200 MW each) – totaling 5,000 MW and 3,650 MW respectively. MSAPL finally awarded 4,484 MW and 3,299 MW capacity respectively at tariffs ranging between INR 2.90-3.10/ kWh. MSEDCL, the government-owned DISCOM, awarded an additional 1,217 MW in the same tariff range. The process was rushed through as MNRE’s waiver of domestic content requirement for cells was running out by 31March 2024.

In the individual substation project tenders, two PSUs including SJVN (1,352 MW) and MAHAGENCO (1,079 MW) were the big winners followed by NACOF (990 MW), a farmers’ association. In the district level tenders, winners were mostly private companies including Megha (1,880 MW), Avaada (1,132 MW), Torrent Power (306 MW) and Reliance (79 MW).

Figure: Allocated capacity and winning  tariffs

Source: BRIDGE TO INDIA research

Maharashtra’s mega award comes after a series of agri-solar disappointments across the country. In 2022 and 2023, 38 agri-solar tenders aggregating 12,250 MW capacity were issued but only 958 MW capacity was awarded. Tenders have been routinely undersubscribed to the extent of 95-98% because of physical challenges in installing and maintaining distributed capacity, low grid availability and unviable ceiling tariffs.

The state revamped its agri-solar scheme in 2023 after an extensive industry consultation and introduced several new measures to incentivise investment. MSAPL completed substantial project preparatory work in advance of issuing the tenders. Land parcels with sufficient evacuation capacity were identified and most projects clearances were obtained before tender issuance. Together with demand aggregation across 16 districts, this drastically cut down project development effort and cost. To tackle concerns about low grid availability, the project developers have been offered full compensation in the event of availability falling below 98% on a monthly basis and also provided an incentive of INR 0.25/ kWh in the first three years of operations subject to commissioning at least 75% of project capacity on time. A revolving fund of INR 7 billion has been created to assure timely payment to the project developers.

For the project winners, it is an attractive opportunity as they would also be eligible for KUSUM scheme subsidy of 30% capital subsidy up to INR 10 million/ MW subject to meeting the eligibility criteria. We understand that around 75% of all projects are eligible for this subsidy.

For Maharashtra, a relative laggard in the renewable sector, the enormous capacity award is a big win in many respects. It would feed solar power to more than 50% of agricultural feeders in the state, meet growing power demand as well as achieve compliance with the distributed RPO target (ramping up to 4.50% by FY 2030). The state government should be lauded for determinedly pursuing the agri-solar opportunity with a design that alleviates pressure on scarce land and transmission resources.

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

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

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

Source: BRIDGE TO INDIA research

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

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

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

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

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

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

Figure: REC trading volumes and prices

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

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

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

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

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

Source: BNEF, BRIDGE TO INDIA research

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

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

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

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

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

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

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

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

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

Figure: Equity investment deal announcements, USD million

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

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

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

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

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

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

Source: BRIDGE TO INDIA research

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

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

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

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

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

Figure: Financial results, INR billion

Source: Company presentations, BRIDGE TO INDIA research

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

Figure: Relative stock prices for Suzlon and Inox Wind

Source: NSE, BRIDGE TO INDIA research

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

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

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

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

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

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

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

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

Figure: Hourly demand profile on peak demand day, MW

Source: Niti Ayog, BRIDGE TO INDIA research

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

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

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

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

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

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

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

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

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

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

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

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

Figure: 2022 capital expenditure split for oil & gas majors

Source: Reclaim Finance Analysis

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

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

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

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

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

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

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

Source: BRIDGE TO INDIA research

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

The Ministry of Power has again revised Renewable Purchase Obligation (RPO) trajectory for FY 2025-30. Total target of 43.3% by FY 2030 remains intact but sub-targets for wind and hydro power have been reduced sharply from 6.9% and 2.8% to 3.5% and 1.3% respectively. The gap has been filled by a new sub-target of 4.5% for distributed renewable power, to be met by power procured from rooftop solar and other projects with capacity less than 10 MW each. Residual target for other technologies including solar, bio-mass, small hydro, older wind and large hydro projects remains largely unchanged. The technology specific sub-targets shall henceforth not be applicable to obligated corporate consumers, who shall be required to meet only the aggregated target. The revised targets shall take effect from FY 2025 onwards. The government has also brought RPO trajectory under the ambit of the Energy Conservation Act from Tariff Policy 2016 to give it statutory status and make it binding on all respective parties. 

Figure: Revised RPO trajectory 

Source: Ministry of PowerNote: Wind and hydro RPO targets can be met only by power procured from respective projects commissioned after March 2024. Hydro target includes small hydro and power output from pumped storage projects irrespective of input power source. Combined target for solar, bio-mass, small hydro, older wind and large hydro projects is almost unchanged – rising from 24.8% in FY 2024 to 34.0% in FY 2030.

The new trajectory, coming on top of previous changes in July 2022 and October 2022, does not seem well thought out and raises some key questions.

Why such a drastic reduction in wind and hydro RPOs?The nearly 50% reduction in wind and hydro RPO targets is hard to explain. According to the initial trajectory, approximately 70 GW and 24 GW of new wind and hydro capacity was expected to be built by FY 2030. These figures have now been adjusted to 35 GW and 11 GW, significantly lower than CEA’s recently announced National Electricity Plan. The reduction is not only an acknowledgement of severe challenges facing both sectors but also seems inconsistent with huge (and unchanged) solar capacity target.

How to implement distributed RPO?The new sub-target for distributed power – implying total installed capacity of about 75 GW by FY 2030 – is laudable but difficult to implement. It is technology agnostic but is intended mainly to boost rooftop solar and agri solar markets. Because of difficulties in collating power generation data from such projects, the government has proposed that the DISCOMs may use an annual power output benchmark of 1,278 kWh/ kW capacity. However, this proposal creates a serious risk of double-counting of green attributes between the DISCOMs and project owners. If the DISCOMs impose restrictions on green attribute claims by project owners, as happens in many states currently for net metered systems, the proposal would be self-defeating.

What happened to storage RPO?In July 2022, the government had introduced a separate storage purchase obligation (ESO) of 4.0% on top of the total 43.3% RPO target. There is no mention of the ESO target in the last two revisions, which suggests that it may have been dropped altogether, a setback for the still fledgling sector. RPO is an important overarching policy setting overall direction for the sector and sending appropriate signals to various demand and supply actors. But lack of rigour, over-detailing and arbitrary tinkering are creating confusion in the sector and undermining sanctity of this process. Many states have belatedly started accepting the older recommendations and will now need to reconsider their plans. We also continue to believe that creating a uniform technology-specific RPO trajectory across all states is not desirable because of major differences in availability of natural resources across the country.

The Ministry of Power has amended Electricity Rules, 2002 to harmonise power tariff across a pool of ISTS-connected renewable projects in central government tenders. The government is planning to create separate pools for different project types including solar, wind, solar-wind hybrid, hydro, RTC, peak power and firm power. A weighted average tariff shall be determined for total power output from each pool using tariffs of individual projects. Projects will be added to each pool over a period of five years as more auctions get completed, after which the pool will be frozen and a new pool created for future auctions. DISCOMs will need to specify the quantum of power they want to buy from one of the relevant pools – in turn, they will need to commit to pay weighted average tariff of that pool over remaining PPA life of respective projects. The Grid Controller of India shall be responsible for maintaining pool data and updating tariffs from time to time.

The pooling mechanism means that the DISCOMs – instead of buying power from pre-identified projects at a fixed tariff known upfront – will now buy power from an unspecified projects at a tariff that will change with every successive auction until the five-year window is completed. It is designed to ensure that the DISCOMs do not cherry pick projects with low tariffs. There is conclusive evidence to show that every time tariffs go up because of, say, increase in equipment costs, taxes and/ or interest rates or even changes in tender conditions, the government struggles to find buyers. When tariffs go up, the DISCOMs choose to walk away – resulting in cancellation of auctions – and wait for the cycle to turn, slowing execution progress in the sector. The change is positive for the developers as it diversifies their offtake risk and significantly reduces risk of tariff renegotiation and project cancellation. However, it is (almost) a zero sum game and exposes DISCOMs to tariff variability risk (see figure below).

Figure: SECI ISTS solar and wind auctions in last 5 years, INR/ kWh

Source: BRIDGE TO INDIA researchNote: Weighted average tariff is revised over time as more auctions are completed in the five year period.

SECI solar and wind auction tariffs have ranged between INR 2.00-2.71/ kWh and INR 2.69-3.22/ kWh respectively in the last five years. Early procurers will be concerned that they run the risk of bearing higher costs if tariffs go up later (as happened in wind sector in 2022-23). Late procurers will not be interested if the tariffs were higher in the earlier years (as in the solar sector in 2018-19).

We believe that the DISCOMs will not be keen on the pooling mechanism. While they get an advantage of bulk power procurement from central government tenders at relatively attractive tariffs in comparison to state tenders, particularly for states with poorly rated DISCOMs, they hate that they have little control over these procurements. Projects often get delayed and/ or cancelled upsetting their procurement plans and RPO performance. DISCOMs also have no control over change-in-law and other legal matters exposing them to additional risks in central government tenders. The pooling mechanism seems to be a non-starter especially for hybrid technologies due to high volatility in tender conditions and resulting tariffs. Pooled mechanisms are created successfully in other parts of the power sector – most notably, in transmission. DISCOMs are obligated to pay pooled transmission system costs across the entire national grid. They also need to often buy power on the exchanges at market rates. But the net impact of these variations is relatively small. And change is always difficult to bring. Unless the government revises the pooling mechanism, the DISCOMs would prefer to issue their own tenders as seen with greater frequency of late.

MNRE has announced the widely awaited green hydrogen standard for India. The standard –covering only green hydrogen production stage and excluding all pre and post-production emissions – has been set at an average of 2 kg CO2e/ kg over 12 months. No standards have been defined for derivative products like green ammonia and methanol. The Bureau of Energy Efficiency (BEE) shall provide accreditation to agencies undertaking monitoring, verification and certification of green hydrogen projects. A detailed methodology for the same is expected to be issued shortly.

In contrast, the European Union (EU) has set a much more onerous standard at about 3.4 kg CO2e/ kg covering entire lifecycle from power generation to end-use (scope 1, 2 and partial 3 emissions). The EU has also set strict requirements for additionality, geographical and temporal correlation of associated renewable power output. Renewable power projects must be commissioned not more than 36 months before respective hydrogen plants, located in the same power market and produce power matching with consumption profile on an hourly basis (monthly basis until 2029). Strict temporal matching of power output would have serious implications on production cost because of expensive power storage and/ or lower capacity utilisation of electrolysers.

Notably, the EU has not classified biomass-based hydrogen as green hydrogen because of its carbon emission intensive process requiring carbon capture.

The US hydrogen mandate extends beyond ‘green hydrogen’ to other forms of hydrogen, for example, blue hydrogen using fossil fuels coupled with carbon capture. The emission threshold has been set at 4 kg CO2e for well-to-gate processes including water treatment, electrolysis, gas purification, drying and compression (scope 1 and 2). Hydrogen output will receive incentives under the Inflation Reduction Act based on emission levels – full tax credit of USD 0.60/ kg for emissions less than 0.45 kg CO2e (with the possibility of a fivefold increase if labour and wage standards are met), 33% tax credit for emissions between 0.45-1.5 kg CO2e, 25% tax credit for emissions between 1.5-2.5 kg CO2e and 20% tax credit for emissions between 2.5-4.0 kg CO2e. However, the US is now mulling stricter rules with requirement for additionality likely to be added as a qualifier.

Over in the UK and Japan, the emission standard has been set at 2.4 kg CO2e and 3.4 kg CO2e respectively for well-to-gate processes (scope 1 and 2). Japan has also set a separate threshold for green ammonia production emissions at 0.84 kg CO2e.

Figure: Green hydrogen standards across the world

Source: BEE, EPRS, US DOE, BRIDGE TO INDIA research

The huge divergence in international standards is confusing but understandable given the nascent nature of the market. It is fair to believe that the standards would get streamlined over time. The EU, expected to be the largest importer and an early user of green hydrogen, may set the tone with other countries converging behind its strict standards. Evolving standards are expected to be a major challenge for hydrogen producers around the globe.

India’s relatively loose standards are not consistent with its aspiration to become a global hydrogen hub. There is also the important issue of mismatch on use of banked power, permitted in India but not in the EU.

The Ministry of Power has issued a framework for promoting energy storage to support integration of variable renewable power capacity. The framework mostly seeks to combine the different policies and plans already announced – energy storage obligation of 4% by FY 2030, projected capacity of 74 GW/ 411 GWh by FY 2032 in line with the National Electricity Plan, competitive bidding for storage and hybrid projects, 25-year ISTS charge waiver for projects completed by June 2025, financial support for PSP and participation in ancillary markets as well as High Price DAM window on the exchanges. Separately, the government has announced that it will subsidise 40% of capital cost through Viability Gap Funding (VGF) for developing 4 GWh battery storage capacity by FY 2031 with a financial budget of up to INR 94 billion (USD 1.1 billion).

There are some interesting new provisions in the framework but without concrete detail. As an example, it is suggested that renewable power projects over 5 MW may be mandated to install storage capacity equivalent to 5% of power capacity with minimum one-hour duration. Similarly, it adds that: i) ALMM (shudder!) and further production linked incentive schemes for BESS may be introduced in future; ii) concessional finance and priority grid connectivity may be provided to storage projects; and iii) the government may establish a nodal agency to coordinate dedicated R&D efforts with additional funding. The only material new provision relates to allowing storage projects utilising renewable energy to avail carbon credits, a potentially important incentive for the sector.

Figure: CEA’s storage capacity projection, GW

Source: CEA, BRIDGE TO INDIA research

The VGF scheme has been designed to reduce battery LCOS to INR 5.50-6.60/ kWh as against current estimates of over INR 11.00/ kWh. The scheme requires minimum 85% of capacity to be tied up in long-term contracts with DISCOMs. VGF shall be awarded through a competitive bidding process and disbursed most likely in five annual tranches post completion.

Subsidy support for BESS is much needed as users seem unwilling to bear full cost despite struggling to cope with intermittent profile of renewable power – delaying growth of this critical technology. The government is right to subsidise BESS but the proposed scheme size of 4 GWh is negligible in comparison to the FY 2032 BESS target of 236 GWh. The proposed VGF budget of INR 94 billion anyway seems sufficient to subsidise up to 10 GWh capacity and it is to be hoped that the scheme size will be enhanced over time.

The storage framework, already too late, needs more substance and concrete provisions for boosting R&D efforts, improved access to minerals and metals, more domestic manufacturing capacity and developing technical standards. From this point onwards, growth of the renewable sector would be dependent on growth of storage capacity.

India added 2,206 MW solar capacity in Q2 2023, 40% lower YOY, declining QOQ for five straight quarters in a row. Main culprit for the slowdown was utility scale solar, which added a mere 420 MW in the quarter. Open access was the saviour with volumes jumping steadily and outpacing utility scale capacity addition for the first time since the start of 2023.

The slump in utility scale solar can be attributed to a multitude of factors but three factors stand out – high module prices (greater than USD 20 cents/ W until April 2023), untimely ALMM implementation (relaxed in March 2023) and limited domestic module availability (only 4,404 MW in last 12 months, net of exports). Project developers have been delaying execution with help of multiple deadline extensions from the government on account of COVID, supply chain disruption and ban on laying overhead transmission lines in parts of Rajasthan and Gujarat. Only 16% of the total 12,678 MW capacity allocated in 2020 with SCOD up to March 2024 has been completed so far. There are still 4,043 MW of projects allocated in 2018 and 2019 waiting to be completed. Total project pipeline with SCOD before March 2024 and in FY 2025 stands at 26,817 MW and 19,714 MW respectively. Top five project developers by pipeline capacity with SCOD up to Mar 2025 include Adani (6,700 MW), NTPC (4,877 MW), ReNew (2,940 MW), SJVN (2,565 MW) and Azure (2,546 MW).

Figure: Solar capacity addition, MW

Source: BRIDGE TO INDIA research

The tide is now set to change with sharp correction in module prices – China FOB prices fell to record lows of USD 0.16/ W, down nearly 50% from last year’s highs – and ALMM relaxation. MNRE’s ultimatum to the project developers to complete all projects allocated before 9 March 2021 by March 2024 or risk suspension from future bidding has also spurred developers into action. Other growth enablers include rising contributions from open access and rooftop solar as well as significant increase in domestic module manufacturing capacity.

Consequently, we expect a big step up in annual capacity addition to over 18,000 MW and 20,000 MW in FY 2024 and FY 2025 respectively. Most of new projects completed this year are expected to use modules from China and SEA countries, which is bound to cause further policy angst. Cue further tussles on ALMM extension and import duties on SEA modules.

Note: INDIA RENEWABLE WEEKLY shall take a summer break over next three weeks. Next edition shall be released in the week commencing 11 September 2023.

Indian module exports have been on the way up for a year now. Q2 2023 export volume amounted to 1.3 GW modules, up 1,492% YOY. Total exports in the year ending June 2023 were estimated at 4.3 GW, up from just 247 MW in the previous year. Share of exports in total module production has now increased to 45% from just 4% in the previous year. Main exporters include Waaree and Adani with 61% and 31% share respectively during the year. The USA accounted for 97% of total exports.

Figure: Module export volume and price data

Source: Ministry of Commerce, BRIDGE TO INDIA research

Evolving global trade dynamics and keenness of the US and Europe to reduce reliance on China have turned the tide for India-made modules. The US has imposed anti-dumping duty of up to 165% on Chinese imports. Concerned by human rights abuses in China, it even enacted a sepcial legislation, the Uyghur Forced Labor Protection Act (UFLPA) in 2022, and detained 2 GW of Chinese shipments causing major uncertainty for project developers.

For India, the international aversion to Chinese imports is a terrific export opportunity. The US and European markets have a combined annual demand of up to 150 GW and no viable alternatives. Both regions are ramping up their own manufacturing bases with generous incentives for manufacturers under the Inflation Reduction Act (IRA) and Net Zero Industry Act respectively. However, despite expectations of a big bump in manufacturing capacity over next three years to about 60 GW and 30 GW respectively, supply is expected to remain well short of demand. These markets are focused on quality and willing to pay high prices. Exports to US have been priced at a rather lucrative USD 0.36-0.38/ Wp as against domestic market prices of around USD 0.25-0.30/ Wp over the last year.

It is therefore disappointing that the Indian companies have made only a feeble and opportunistic play to tap into the export markets. India’s module manufacturing capacity is growing but polysilicon, wafer and cell supply shortage seems set to continue. Indian manufacturers are heavily dependent on China for import of technology, engineering skills, upstream supplies and other critical components. Barring 2-3 companies, most manufacturers are focusing merely on low tech assembly or meeting in-house demand.

Customers in the US and EU want the latest technology, traceability, scale and security of supply. Most Indian manufacturers do not seem well positioned on any of these parameters.

There has been a slew of new entrants in the open access (OA) market over the last two years. Vedanta, a large industrial conglomerate has set up a dedicated platform, Serentica Renewables, to decarbonise group companies. International IPPs like BrightNight, Ampyr and AB Energia have entered the market recently and are already developing 100+ MW capacities across multiple states. New platforms like Sunsure have been set up with the support of private equity. Many utility market-focused project developers like Apraava, O2, Blupine and Sprng have jumped into the market. Torrent Power recently signed a 132 MW solar PPA with Shapoorji Pallonji for supply to its desalination plants in Gujarat. Public sector majors like NTPC and SECI are also keen to tap the opportunity. The number of active project developers with annual investment appetite of 50+ MW in the OA market is estimated at more than 30.

The increased interest comes in the face of improving market fundamentals with liberalised central government policy stance and higher corporate demand. Total OA renewable capacity addition in FY 2023 was estimated at 3,414 MW, up 67% over FY 2022, which itself was up 53% YOY. Share of OA in total renewable capacity addition increased to 25% in FY 2023 from 15% in the previous year. Most utility scale developers are also attracted by an opportunity to diversify portfolio – lower DISCOM exposure, higher financial returns and a more stable business (utility scale business is more lumpy, prone to longer gestation periods).

The inherent nature of the corporate renewable market means that it is highly fragmented. ReNew, the biggest player in the market by commissioned capacity over last three years, accounted for only 8% share of the total market. It was followed by Continuum, Cleantech, Fourth Partner and Ampin with market shares of only 4-7%. Top 14 developers accounted for only 56% share.

Figure: Leading OA project developers by commissioned capacity in FY 2021-23, MW

Source: BRIDGE TO INDIA researchNote: Data includes projects developed by consumers for 100% captive use.

With entry of so many new players, the marketplace is getting crowded and intensely competitive. There is some evidence of aggressive tariffs and risk positions in the PPAs, particularly around offtake and default provisions, especially in the private equity funded ventures. But there is also plenty of evidence of reasonable discipline in the market, due in part to lessons learnt from exceptional sector uncertainty over the last three years (BCD, ALMM, Covid, equipment and commodity price hikes, supply chain disruption) as well as the need to raise capital frequently. Rapid growth is also easing some of the competitive pressure.

So how are players seeking to establish a competitive edge? Indian corporate houses like Tata, Aditya Birla, JSW, Vedanta and Hero have a huge advantage because of the substantial in-house demand. As an example, JSW and Serentica have set targets to install 6 GW and 5 GW capacity respectively in the near-term future for captive use. Tata Power recently signed a 966 MW wind-solar hybrid PPA with Tata Steel for supply of round-the-clock (RTC) renewable power to its steel plants. Such players are generally more conservative when working with non-group consumers. Meanwhile, the utility scale developers enjoy a relative advantage in financing, execution scale and familiarity with the latest technologies. They are generally targeting select consumers with a 20 MW+ ticket size with the help of their corporate relationships. The corporate market specialists, on the other hand, are more nimble and focused on the 5-20 MW project business with larger business development teams on the ground.

One way to gain competitive edge is to make early investments in land acquisition, transmission connectivity approvals and other related infrastructure, typically about 8-10% of project cost. Readiness to commission a project within 6-12 months of signing the PPA is a big draw for consumers. Going forward, wider technology expertise and an ability to offer hybrid RTC solutions are also expected to be key differentiators.

Madhya Pradesh has recently issued a detailed procedure to verify captive status of renewable projects every year to ensure compliance with requirements as per the Electricity Act – minimum collective 26% equity ownership and 51% power offtake by respective consumers(s). In May 2023, Punjab had issued somewhat similar criteria to verify the captive status but went one step further. It mandated captive consumers to furnish a security deposit equivalent to estimated Cross Subsidy Surcharge (CSS) and Additional Surcharge (AS) for 51% of total annual power generation on a pre-emptive basis. Other states to have issued procedures to verify captive status of projects include Uttar Pradesh, Tamil Nadu and Himachal Pradesh. The Ministry of Power has also appointed CEA as the nodal agency for verifying captive status of inter-state projects.

Each state agency is using a different interpretation of the Electricity Act particularly in relation to changes in project shareholding structure or offtake over time. Recent amendments in Electricity Rules, 2005 have created further confusion. As per the amendment, a captive generating plant requires minimum 26% ownership and consumption of minimum 51% of power generation by a “consumer.” It is not clear if the change from “consumer(s)” to “consumer” is intentional – the amendment effectively permits only one consumer to claim captive benefit from a project and disbars multi-consumer captive transactions. The amendment also allows a parent company to claim captive status for a project owned by an affiliate subject to minimum 51% ownership in the latter.

All these measures, designed to prevent abuse the captive policy, are adding to unwarranted uncertainty in a growing market. Captive projects have become the de facto norm for open access transactions as they allow consumers to transfer all financial and operational risk for the project to a specialist third party and yet claim full benefit of CSS and AS exemption (see figure). The only niggle is that the consumers need to cough up 26% equity, equivalent to 7.8% of the capital cost, but they get pro rata reduction in PPA tariff.

Figure: CSS and AS waiver benefit for industrial consumers connected at 132 kV level, INR/ kWh 

Source: State tariff orders for FY 2024, BRIDGE TO INDIA researchNote: For Karnataka and Madhya Pradesh, AS is ignored as they have adopted the Green Open Access rules.

States are fiercely opposed to the idiosyncratic captive definition as it creates a hole in their finances. Many states including Rajasthan, Gujarat and Haryana have been downright denying approvals to such projects, while some others are using ad-hoc measures like unlawful levy of AS, captive tax, operational restrictions on existing projects and increased regulatory scrutiny to deter use of captive status.

We believe that it is time to unwind the captive policy, a vestige of old times, and simplify all associated processes particularly for renewable projects. The policy was designed at a time of severe power shortage for delivering (firm) conventional power to a group of consumers that could not individually set up thermal power plants. None of those assumptions hold true for renewable projects being developed today. The policy should no longer discriminate between projects based on their ownership or offtake. And if it can propose a simplified grid charge structure which compensates DISCOMs fairly for services provided by them, the policy could be a win-win for all parties.

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

L&T recently signed a technology licence agreement with France-based McPhy for making alkaline electrolysers in India. Before this, Greenko had signed an agreement with John Cockerill to build a 2 GW alkaline electrolyser manufacturing plant. Other companies to show an interest in electrolyser manufacturing include Adani, Ohmium, H2ePower, Reliance and GR Infraprojects. The latter two have signed technology partnerships with Stiesdal and H2B2 respectively. The US-based Ohmium already has an annual capacity of 500 MW, the only one to make electrolysers in India at present. These announcements add up to a total of 8 GW annual capacity by 2025. While most of the companies are looking to produce alkaline electrolysers, some are hedging their bets while Ohmium is focused exclusively on the newer PEM technology.

Electrolyser availability is obviously a key requirement for green hydrogen production. In view of the nascent market status, there are concerns that lack of supply may hold up green hydrogen growth. India’s green hydrogen production target of 5 MMT by 2030 requires total electrolyser capacity of about 50 GW, translating to annual manufacturing capacity of about 15-20 GW by that time. Global demand-supply scenario shows a similar deficit. Total manufacturing capacity at the end of 2022 was reported at only 15 GW – with China predictably taking the lead – as against estimated 2030 demand of between 134-240 GW. As per IEA, manufacturing plans announced so far by all companies worldwide add up to only 65 GW capacity by 2030.

Figure: Present electrolyser manufacturing capacity, GW per annum

Source: BloombergNEF, BRIDGE TO INDIA research

It is a great opportunity for India to take lead in a high growth market. China is expected to remain the dominant supplier with its large domestic market, strong government support and manufacturing prowess. But other countries need a supply alternative. The US and EU are also promoting domestic manufacturing with eye-watering incentives although it is debatable if they can ever become genuinely competitive with their high cost base and tougher permitting process.

Getting private companies to accelerate their manufacturing plans, however, is tricky since even the current small capacity remains underutilised. Private capital needs some demand visibility or at least a clear roadmap to price competitiveness of green hydrogen. It is a classic chicken and egg problem.

We believe that growth of Indian electrolyser manufacturing business is contingent on three factors – getting demand certainty, access to latest technology and critical raw materials. The government’s plan to offer incentives for green hydrogen production does not go far enough. The proposed INR 44 billion (USD 538 million) subsidy for electrolyser manufacturing is misguided since electrolyser cost accounts for barely 15% of total cost of green hydrogen production. These funds should instead be diverted to green hydrogen production and/ or incentivising technology research and/ or gaining access to supply of mineral and metals like zirconium, nickel (both dominated by China), iridium and platinum (concentrated in Africa). It seems more desirable to focus efforts on improving technology to handle variation in renewable power availability, reducing dependency on rare metals and developing recycling capability than trying to reduce the cost of electrolysers.

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

The European Parliament has given final nod to its landmark climate policy initiative, Carbon Border Adjustment Mechanism (CBAM). The scheme’s objective is to provide a level playing field to European Union (EU) businesses by subjecting imported goods to an effective tax equivalent to incremental environmental cost borne by domestic manufacturers because of EU’s tighter emission standards. The carbon tax will be determined based on differential of emissions produced in the production of goods overseas in comparison to benchmarks used in the EU Emission Trading Scheme (EU-ETS). The scheme is dsigned to eliminate expected to promote local production by eliminating arbitrage opportunity between domestic and international emission standards.

CBAM will be implemented in two phases. The first phase starting from 1 October 2023 will be a trial period applicable only to select industries like cement, iron and steel, aluminium, fertilisers, electricity and hydrogen that are exposed to higher risk of carbon leakage. These industries together account for more than 50% of emissions covered in EU-ETS. There will be no actual financial tax or payments during this period. This phase is meant to provide a learning curve both to the policy makers and businesses and also give the latter sufficient time to develop low carbon products. CBAM will be applicable only to direct emissions (scope 1) in this phase with indirect emissions expected to be added at later stage.

Full rollout of CBAM, the second phase covering more sectors and wider range of emissions, will start from 1 January 2026 when companies exporting to EU will have to purchase CBAM certificates based on emission intensity of their manufactured products. The certificates, meant to be non-tradable, shall be priced at levels corresponding to carbon pricing in the EU-ETS market, where prices have been observed in the range of USD 88-114/ tonne this year.

Indian exports of iron, steel and aluminium products to the EU amount to a considerable USD 8.2 billion (INR 670 billion) annually, 11% of total exports to EU and 26% of total exports of these commodities.

Figure: Indian exports to EU, million USD

Source: Ministry of Commerce, BRIDGE TO INDIA research

CII estimates that CBAM will levy an effective carbon tax of 39.6% and 19.8% on Indian steel made from blast furnace and electric arc furnace routes respectively. The presumptive tax on aluminium is 20.3%. Such high taxes are mainly due to dependence of Indian industry on coal-fired power resulting in its high carbon intensity – 2.6 MT CO2/ MT of crude steel, 37% higher than global average and 56% higher than EU average. Similarly,  carbon intensity of Indian aluminium production at 17-20 MT CO2/ MT is 150% higher than the EU average.

CBAM levy of 20-40% would obviously be highly detrimental to Indian businesses. It comes on top of a domestic carbon trading scheme, also imminent over the next few years, and rising RPO trajectory. The growing regulatory thrust on decarbonisation provides strong tailwinds for green technologies. We expect corporate renewable market to be the biggest beneficiary as renewable power enjoys significant lead in terms of techno-economic viability over other decarbonisation technologies like carbon capture and green hydrogen.

After witnessing one of the slowest periods in project auctions through 2022 and early 2023 (average monthly auction capacity of 802 MW), last six weeks have seen a surge in activity. Since April, a remarkable ten auctions totalling 6.9 GW capacity have been completed. Prominent auctions include 1,200 MW peak power by SECI, 1,000 MW RTC power by Indian Railways, 1,750 MW solar power by REC, 1,100 MW solar and 500 MW wind power by Gujarat, 1,000 MW solar power by Rajasthan, and 500 MW solar power by Maharashtra. Appropriately for these times, total allocated capacity was split 60:7:2:31 between standalone solar, wind, solar-wind hybrid and solar-wind-storage-hybrid projects. Actual hybrid project capacity is expected to be about 50% higher because of oversizing to meet higher CUF requirement.

Market response has been keen but not desperate. Most auctions were oversubscribed by about 1.2-3.0x. There were 27 unique bidders with bulk of the interest coming from private equity backed platforms and PSUs. The three biggest winners were ReNew (1,400 MW), NTPC (1,250 MW) and Avaada (1,040 MW). Notable absentees included Adani, Azure, Tata, JSW, Sprng, O2 and most international utilities.

Figure: Leading participants in auctions between 1 April–12 May 2023, MW

Source: BRIDGE TO INDIA research

As the following chart shows, tariffs have been on an upswing in the last year recovering to levels last seen in 2019/ early 2020. Even in SECI’s peak power tender, average tariff of INR 4.70/ kWh was about 15% higher than its last such auction in January 2020. Tariffs also seem more rationally based around differences in offtaker and location than at any time in the past. Barring the top winners, bidders have shown willingness to walk away if risk-return is not attractive. One hopes that Gujarat and other tendering agencies will accept these results rather than resorting to any cancellations.

Figure: Average tariffs in key auctions, INR/ kWh

Source: BRIDGE TO INDIA research

The upswing in tariffs, coming at a time when the cost outlook is becoming more benign, is a positive development for the industry. Module prices have now fallen by over 30% since May 2022 and look set to fall by another 10-15% by this year end.

This rare period of optimal bidding balance for the industry is explained by the fact that many developers are sitting on large project pipelines. Having delayed construction over last 2-3 years, they are still occupied by financing and execution issues. We believe that this scenario of rational bidding would last for another six months or so.