Category: Market Outlook

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

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

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

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

Source: BRIDGE TO INDIA research, Infolink

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

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

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

Figure 1: Exchange rate and bond yields

Figure 2: Annual changes in inflation indices, %

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

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

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

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

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

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

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

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

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

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

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

No cell manufacturing capacity has been approved as yet.

Figure: ALMM approved manufacturing capacity

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

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

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

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

(Micro) industrial segment leads the way

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

Figure 1: New installations by consumer segment, MW

Source: BRIDGE TO INDIA research

Further slowdown in OPEX model

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

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

Source: BRIDGE TO INDIA research

Tata Power racing ahead

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

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

Corrigendum: Module PLI 2 to benefit fully integrated manufacturers

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

Table: Different bid categories

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

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

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

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

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

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

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

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

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

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

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

Source: Indian Energy Exchange, BRIDGE TO INDIA research

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

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

Source: Indian Energy Exchange, BRIDGE TO INDIA research

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

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

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

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

Figure: Solar BOO project pipeline

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Soaring cost and demand-supply imbalance for batteries

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

Policy framework not evolving fast enough

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

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

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

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

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

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

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

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

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

Figure 1: Tender issuance and auction, MW

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

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

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

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

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

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

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

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

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

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

Source: Google Finance

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

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

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

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

Figure: Wind power capacity addition, MW

Source: BRIDGE TO INDIA research

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

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

Figure: Commissioning status for wind projects under SECI tenders

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

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

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

MNRE has revived offshore wind plans with industry consultation for developing 1 GW and 2 GW capacity off the coast of Gujarat and Tamil Nadu respectively. Power is proposed to be sold to the respective states at a fixed tariff of about INR 3.50/ kWh with SECI as an intermediary offtaker. MNRE aims to award total capital subsidy of up to INR 140 billion (USD 1.8 billion) to project developers through a competitive bidding process. It is proposing to complete bidding process for the first 1 GW project this year with expected commissioning date of 2025. The second tranche of 2 GW capacity in Tamil Nadu is expected to be tendered out in 2024. Overall, the government is aiming to issue tenders for 30 GW capacity by 2030.

It is worth recalling that offshore wind has so far failed to take off since states are unwilling to buy expensive power – expected LCOE of about INR 9.00/ kWh – and the central government has refused to bear the substantial subsidy burden. MNRE had announced the offshore wind policy in 2015 with a target of developing 5 GW capacity by 2022. Preliminary wind resource assessment, environmental impact assessment, geophysical and geotechnical studies were completed for a 1 GW pilot project off the Gujarat coast in 2018 with financial and technical assistance from the European Union. But the project never took off because of economic challenges.

MNRE seems more keen this time possibly because of acute execution challenges faced by onshore wind (note to follow next week) and sharp fall in offshore wind cost (see figure below). It is also more hopeful of the Finance Ministry’s support after getting support for expansion of the solar PLI scheme.

Growth led by Europe and ChinaTotal global offshore wind capacity is currently estimated at 55,678 MW. China has leapfrogged other countries by installing a mammoth 17 GW capacity in 2021 ahead of its USD 134/ MWh (INR 10.20/ kWh) feed-in-tariff expiry date. Other leading nations including the UK (total installed capacity of 12,700 MW), Germany (7,747 MW) and the Netherlands (2,460 MW) have also relied on feed-in-tariffs and other subsidies to kick-start the market. The USA, Denmark, France, Japan, South Korea and Taiwan are planning significant offshore wind development in near future.

Figure 1: Annual capacity addition, MW

Source: IRENA

Developed nations prefer offshore wind mainly as they run out of suitable onshore sites due to complex planning laws and resistance from local populations.

Improving techno-commercial viabilityWith improvement in technology, scale and increase in turbine sizes (up to 16 MW each), capital cost and LCOE have declined by about 50% since 2016, but are still relatively steep at about USD 2 million/ MW and USD 0.10-0.12/ kWh respectively in the Indian context.

Figure 2: Offshore wind LCOE in other countries, USD/ MWh

Source: U.S. Department of Energy

Weak case for offshore wind in India.We believe that the government plan to tender 30 GW capacity by 2030 is too ambitious to be realistic. DISCOM appetite is likely to be nil in absence of central government subsidies. Moreover, gestation period for first few projects is likely to stretch to over five years since requisite infrastructure and manufacturing capacity is not available in India.

Given the substantial subsidy burden and lack of domestic manufacturing capacity, a robust debate is needed on future of offshore wind in India. Certainly, there is no scarcity of suitable onshore sites in India unlike in more developed nations. Use of government funds would be significantly more beneficial in accelerating build out of storage and transmission capacity.

BRIDGE TO INDIA estimates that new rooftop installations in 2021 touched a record high of 2,196 MW, up 62% over previous year. As of December 2021, total rooftop solar capacity is estimated at 8,988 MW, 18% of total solar capacity in the country. The increase came mainly from the residential segment, which contributed 746 MW in new installations (34% market share), an YOY increase of 108%. These numbers are highly encouraging, coming after 2 years of market decline, and in face of several acute challenges including 7% annual capex increase, modules shortage and net metering policy uncertainty in many states.

Strong residential demand The residential market, one of the most under-penetrated segments of the renewable sector, has been gaining momentum over last couple of years with steady improvement in implementation of MNRE’s revamped subsidy scheme. Recent relaxation of the scheme whereby consumers can choose any installer rather than being restricted to installers empanelled by state governments or DISCOMs should also help going forward. MNRE has so far sanctioned subsidy for 3,162 MW capacity (scheme target 4,000 MW), out of which 1,252 MW capacity has already been installed. Gujarat leads in total tender issuance (2,200 MW) as well as total installations (992 MW). It recently issued a 1,000 MW tender, the largest residential rooftop solar tender so far. We expect the market to accelerate further with total capacity crossing 10 GW by about 2027-28.

Figure 1: New installations by consumer segment, MW

Source: BRIDGE TO INDIA research

CAPEX trumps OPEX in the C&I marketGrowth in the corporate market has been muted in comparison. The larger consumers and solution providers seem to have shifted focus to open access projects in push for volume. And while high capex cost is a deterrent for many consumers, self-financed market is growing robustly. Share of the OPEX model has now been falling for three straight years.

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

Source: BRIDGE TO INDIA research

No sign of consolidation in the marketThe market remains keenly fragmented across regions, consumer segments and business models. Larger utility scale players like ReNew, Azure and Statkraft have exited the OPEX business but there seem few players able to grab the opportunity. Exceptions include Fourth Partner and Amplus in the OPEX business, and Tata Power, which has made impressive gains in both business models.

Figure 3: Leading players by installed capacity in 2021

Source: BRIDGE TO INDIA research

Hostile policy environment is affecting growthMaharashtra continues to be the leading state for C&I installations (254 MW capacity addition in the year), followed by Gujarat (173 MW), Rajasthan (138 MW), Andhra Pradesh (122 MW) and Karnataka (107 MW). The impact of regressive policy actions can be clearly seen in slowing market growth in Uttar Pradesh and Karnataka.

Figure 4: Annual capacity addition in major states, MW

Source: BRIDGE TO INDIA research Note: Data excludes residential installations.

The short-term market outlook is clouded by many factors. Firm module prices and BCD may deter customers although there is some evidence of leading installers having stockpiled modules. Need to comply with ALMM, deferred by six months to October 2022, is also a major source of uncertainty. Our estimate is that the market would grow by about 10-15% over last year, led again by the residential segment.

CERC, India’s central power sector regulator, has revised regulations pertaining to the Deviation Settlement Mechanism (DSM) for solar and wind power projects. The regulator has both tightened the deviation bands and increased penalties for deviations. Consequences for over-injection are considerably worse with developers not to be paid anything for more than 10% extra output. Penalty for under-injection has been restructured and linked to ancillary service charges for secondary and tertiary services instead of PPA tariff.

CERC has justified making the regulation more stringent by claiming improvement in forecasting accuracy and low penalties for individual power producers due to aggregation of schedules at pooling station. Effective date of the new regulation is yet to be notified.

Table: Deviation bands and penalties under previous and revised regulations

Notes: 1. In practice, penalties are imposed on power producers on top of their entitlement for power sale payments on the basis of power scheduled quantum. Effective penalty figures in this table are presented on a net basis after accounting for payment due for scheduled power. 2. In FY 2022, weighted average ancillary service charge was INR 6.91/ kWh.

It is worth recalling that all renewable projects are required to forecast and schedule their power output in 15-minute intervals on a day-ahead basis. They may revise the schedule up to 16 times a day subject to one revision for each time slot of 1.5 hours. The objective of these regulations, which apply to all renewable power projects, DISCOMs and consumers connected to the national grid, is to minimise scheduling deviations in order to maintain grid stability and security.

Following the new CERC regulation, the states are expected to revise their respective regulations. Most state regulations follow deviation bands defined by CERC and levy penalties of INR 0.50-1.50/ kWh depending on the amount of deviation. However, some states including Gujarat, Haryana, Madhya Pradesh and Tamil Nadu have defined tighter bands. Gujarat has adopted the tightest bands at 7% for solar power and 8-12% for wind power. Andhra Pradesh even tried to remove deviation bands altogether with a proposed flat penalty of INR 2.00/ kWh for all deviations exceeding 4.89%. But following strong opposition from the developers, the state regulator withdrew draft regulation and introduced 10% tolerance bands.

The new regulation is considerably more penal for over-injection and hence, inadvertently promotes over-scheduling. An analysis of a 250 MW solar power project in Rajasthan shows a sharp increase in penalty impact under new DSM bands. Average annual penalty amount is expected to increase from about 0.15% of revenues to 1.65% of revenues for the same schedule. However, a shift to over-scheduling can bring down annual penalty amount to about 0.5-0.8% of revenues. This amount should come down further over time as the industry adapts to new regulations and forecasting ability improves.

Another unintended consequence of the new regulation and deliberate over-scheduling by renewable IPPs would be increase in real-time and ancillary services trading volumes since actual renewable power output is likely to be lower than the scheduled amount.

ArcelorMittal, one of India’s largest steel producers, has signed an agreement with Greenko to procure a 250 MW inter-state round-the-clock (RTC) open access (OA) renewable power project. Power would be supplied from a combined 975 MW wind-solar power plant integrated with a pumped storage project in Andhra Pradesh. The project is expected to be commissioned by H1 2024 by Greenko in EPC mode at an estimated cost of USD 600 million. It would allow ArcelorMittal to achieve over 20% renewable penetration for its 10 million tonne manufacturing plant in Hazira, Gujarat. Earlier this month, Adani also announced a separate agreement with Greenko to procure 6 GWh pumped hydro capacity from Greenko projects in Madhya Pradesh and Rajasthan to enable consumption of 1 GW RTC renewable power at its manufacturing facilities in Gujarat. It is worth noting that landed cost of RTC renewable power is expected to be materially higher than cost of power from all other sources.

Large companies are coming under increasing pressure to accelerate their decarbonisation plans;

100% ISTS waiver for OA projects commissioned by June 2025 is expected to result in massive surge corporate renewable market over the next three years;

Domestic equipment suppliers and EPC contractors are expected to be the main beneficiaries;

The two deals validate Greenko’s unique strategy of proactively developing pumped hydro projects across India in anticipation of RTC power demand particularly as battery storage viability remains a few years away. Separately, Reliance Industries has obtained transmission connectivity approval for a 500 MW open access renewable power project for its Jamnagar refinery. The company is believed to be considering a multi-fold expansion of this project in the next few years. These developments reflect a fundamental shift in the corporate renewable market, which could be attributed to three factors. One, corporates making pledges to achieve net zero emissions status and consume 100% renewable power are coming under increasing pressure to accelerate their decarbonisation plans. Their primary focus, when considering renewable power procurement, has changed from just reducing cost of power procurement to increasing share of renewable power consumption and reducing carbon emissions. They are prepared to procure RTC renewable power even if it means an increase in cost of power. Larger corporates are also pushing their suppliers, including small businesses and SMEs, to increase adoption of renewable power across the supply chain. The two other factors are extension of inter-state transmission charges waiver to open access projects commissioned by June 2025 and a realisation that renewable power cost is not going to decline forever. Capex spike, increase in GST rates and looming 40% BCD on modules have nearly wiped out cost advantage of renewables over grid power in many states.

Figure 1: Landed cost comparison for industrial consumers connected at 33 kV, INR/ kWh

Source: BRIDGE TO INDIA researchNote: Grid power cost includes variable energy charges, surcharges, taxes and duties.

The behavioural shift is opportune at a time when the OA renewable market has been struggling in face of state level policy resistance and cost uncertainty.

Figure 2: OA capacity addition, MW

Source: BRIDGE TO INDIA research

Market activity is expected to see a massive surge over the next three years with 100% captive model likely to dominate. Main beneficiaries are expected to be domestic equipment suppliers and EPC contractors.

Thirty two months after the Andhra Pradesh government’s flagrant attempt to renegotiate over 7,500 MW of renewable power PPAs, the state High Court has finally restored status quo. The High Court has, in an order dated 15 March 2022, directed the DISCOMs to honour contracted tariffs and clear all outstanding dues within six weeks. It has also definitively ruled that once projects have been duly allocated under a transparent process, tariffs may not be unilaterally revised by the state government, DISCOMs or even the state regulator. It has further directed the DISCOMs to not curtail power from renewable producers unless there is a risk to the grid.

BackgroundIn July 2019, the then newly formed government in the state had sought to: i) reduce tariffs of all renewable projects; ii) cancel ‘must run’ status of renewable projects; and iii) cancel all renewable power procurement initiatives in pipeline. Subsequently, the High Court issued an order in September 2019 asking the DISCOMs to pay an interim tariff of INR 2.43/ kWh and 2.44/ kWh to solar and wind power producers respectively as against average contracted tariff of INR 4.30/ kWh.

Affected project developers The impasse has been a major strain on finances of developers to the tune of INR 72 billion (USD 948 million) in aggregate pushing smaller developers to the brink of default. Total project portfolio, selling power to DISCOMs in Andhra Pradesh is estimated at 7,569 MW (split between solar – 3,907 MW and wind – 3,662 MW). Greenko (1,616 MW operational capacity), ReNew (777 MW), Adani (604 MW), Mytrah (364 MW) and Tata (305 MW) are the worst affected private developers.

Figure: Leading project developers in Andhra Pradesh, MW

Source: BRIDGE TO INDIA research Note: Capacity excludes open access projects.

Implications for the sector The High Court decision is being widely reported as a “significant positive” for investment sentiment in the sector. However, as we maintained in 2019, there was no justifiable basis for the state to renegotiate tariffs and it was only a matter of time before legal sanctity of contracts was held. The exercise was a mere political gimmick and an outrageous attempt to buy some respite for the financially struggling DISCOMs (rated B and C respectively by the Ministry of Power).

On the contrary, the fact that it took the High Court nearly 2.5 years to resolve such a black-and-white case is a blemish on the Indian legal system. Moreover, there remains considerable uncertainty for the affected developers. The DISCOMs will have to find an estimated INR 72 billion (USD 935 million) for past compensation and INR 27 billion (USD 350 million) for annual incremental payments to power producers. Being unable to clear all dues to power producers within six weeks as directed by the High Court, they may seek more time from the High Court or drag the process by appealing to the Supreme Court.

It is not even certain that other states would learn from the Andhra Pradesh precedent. After all, Andhra Pradesh chose to renegotiate PPAs despite failure of all such precedents. In the long run, the permanent cure lies in restoring financial health of DISCOMs by improving their governance and granting them operational autonomy. However, so long as state governments see an opportunity to curry favour with the masses by offering them cheaper power, they will keep meddling in the sector.  

It is early March and peak power demand this month has already hit 195 GW as against 186 GW last year. Peak demand over last five years has grown at a CAGR of 4.6% outpacing total power demand CAGR of 3.4%.

Figure 1: Peak and total power demand

Source: CEA, BRIDGE TO INDIA research

These are official peak demand numbers reported by CEA, which also reports a rising peak deficit of 2.9 GW in the current financial year as against a deficit of about 1.4 GW in the last 3-4 years. Actual peak deficit is almost certainly much higher as DISCOMs routinely resort to load-shedding in response to rising demand. Increasing peak demand has led to greater volatility in hourly prices in the day-ahead-market on the exchanges. Morning and evening peak power prices are now routinely hitting and crossing INR 8/ kWh as shown in the following chart. Indeed, the day-ahead prices touched a new high of INR 20/ kWh on 4 March 2022.

Figure 2: Average hourly prices in the day-ahead market, INR/ kWh

Source: Indian Energy Exchange, BRIDGE TO INDIA research

There has been a similar increase in round-the-clock (RTC) prices on the exchanges over last 5 years. RTC prices in first week of March 2022 touched INR 5.41/ kWh against INR 4.07 and 2.46 seen one and two years earlier respectively.

There are several factors explaining demand-supply imbalance and price spikes. Growth of renewable capacity, concomitant with the sharp slowdown in thermal capacity addition over the last few years, is the biggest factor at play. Surplus power available for sale on the exchanges has almost completely dried up. Imported coal prices have shot up to over USD 100/ ton, an increase of over 2x in the last year, rendering affected plants unviable. And domestic coal production capacity does not seem fully geared up yet to cater to 100% demand.

The deficit is expected to get worse in the next few months as we hit peak summer. And prognosis for the next few years does not look good. A simple extrapolation of demand-supply suggests that peak deficit could reach 30-40 GW levels in the next five years. Expected renewable power capacity addition of around 60 GW, almost all without any storage capacity in the same period, would exacerbate peak power deficit and price volatility.

There are already some calls for developing new thermal power projects to ease supply pressure. The government would do well to resist such pressure and examine alternate remedial measures like incentivising addition of storage capacity, demand side management and move to market based pricing of power. Meanwhile, soaring peak power prices should provide sufficient financial reasons to DISCOMs to overcome their financial concerns and commit to RTC renewable power. It is worth noting that SECI’s first peak power tender (1,200 MW solar-wind-storage hybrid capacity, peak power price of INR 6.12-6.85/ kWh) is still not fully contracted, more than 2 years after the auction date.

CERC, India’s central power sector regulator, recently issued a regulation expanding scope of ancillary services and including large consumers and energy storage as potential service providers. The regulation covers mainly energy balancing services, also called frequency control, which have been split by CERC in three segments based on response time – primary, secondary and tertiary. The regulation does not yet cover other services like reactive power support and voltage control. NLDC, the national grid operator and designated nodal agency for the services, shall estimate demand for ancillary services on day-ahead and real time basis.

Ancillary services are expected to play a critical role in growth of renewable power by improving grid security and stability;

Trading is expected to commence in 2023 post issuance of guidelines by NLDC and launch of appropriate market instruments by the power exchanges;

Retrofitting old plants and upskilling plant and grid operators can help by improving market capacity;

Primary ancillary services, launched for the first time, shall be fully automated and provided by power plants on an instantaneous basis. Secondary ancillary services, entailing response time of less than 30 seconds and minimum duration of 30 minutes, may be provided by power plants and consumers connected directly to the transmission grid (including those with energy storage) with a capacity/ demand greater than 1 MW. Such services shall be triggered if difference between scheduled and actual power flow exceeds 10 MW at regional level. Compensation shall include variable supply cost for power plants and a fixed charge, quoted on a monthly basis, for consumers in addition to an incentive of INR 0.10-0.50/ kWh depending on service quantum. Secondary ancillary service shall be implemented using automatic generation control (AGC) – a system that allows grid operators to send signal to power plants to change their generation profile. As of January 2022, AGC had been installed at 51 power plants.

Tertiary service may be offered by power plants and consumers with response time of 0.5-15 minutes and response duration of an hour. This service shall be triggered if quantum of secondary service exceeds 100 MW for more than 15 minutes. NLDC will seek this service on day-ahead and real-time basis on the exchanges at market clearing prices.

Next steps include: i) issuance of guidelines by NLDC for power plants and consumers to participate in the market; and ii) launch of appropriate market instruments by the power exchanges post stakeholder consultation and CERC approval. Trading is therefore expected to commence sometime in 2023.

Ancillary services market became operation in India in May 2017. The current scope of services is quite simple, akin to just secondary reserve service under the latest regulation. As of January 2022, only 82 inter-state connected power plants – coal or gas fired – with aggregate capacity of 72 GW were allowed to offer this service. Market volume has been stagnant over the years but increased significantly last year.

Figure: Ancillary market volume and value in India

Source: POSOCO, BRIDGE TO INDIA research

The term, ‘ancillary services,’ refers to a vast array of services such as operating reserves, frequency control and voltage control provided by bulk energy producers and consumers to maintain grid security and stability. Expanding scope and design of such services has become extremely crucial in view of rising distributed power generation, variable renewable power supply and transmission capacity constraints. Together with demand side management, ancillary services are expected to play a huge enabling role in growth of renewable power.

Ancillary market design and requirements vary significantly across the world. Response time for secondary and tertiary services ranges from 5-15 minutes in most European countries and 6 second to 5 minutes in Australia. The UK recently added a fast reserve service with response time of less than 1-2 seconds due to increasing deployment of battery storage systems.

The market is expected to become deeper and larger over time with growth of new instruments, expansion to include intra-state markets and participation by newer technologies. Lack of readiness among power producers is a potential challenge, which needs to be overcome with retrofitting old plants and upgradation in skill sets of plant and grid operators.

The Ministry of Power has issued a green hydrogen policy. The policy was much anticipated post Indian government’s commitments at COP 26 as green hydrogen is seen as a very promising route to decarbonisation. The policy focuses mainly on provision of renewable power for hydrogen production. DISCOMs ‘may’ sell renewable power to hydrogen producers at a price equivalent to actual cost plus ‘small margin.’ For open access procurement, the policy has provisions for 15-day single window connectivity approval, one month banking and ISTS charge waiver for 25 years for projects commissioned by June 2025. It also envisages location of hydrogen production plants in renewable energy zones or dedicated manufacturing zones developed by the government as well as setting up storage bunkers at port sites.

The policy fails to address most key areas for development of a green hydrogen ecosystem;

Providing cheap renewable power, a critical requirement for reducing cost of green hydrogen, would be a major problem;

Immediate priority should be to nurture domestic technology and infrastructure development capabilities through R&D investments, subsidies and tax breaks;

Overall, the policy fails to address most key areas for development of a green hydrogen ecosystem – technology, manufacturing capacity, infrastructure for transportation and storage, demand creation and cost reduction. In the run up to the policy release, the government had made various provisional announcements – green hydrogen purchase obligation of 20-25% for fertiliser and petroleum sectors by 2030, Viability Gap Funding (VGF) for heavy mobility sector and a PLI scheme for setting up 10,000 MW per annum electrolyser manufacturing capacity. The Ministry of Power had also talked about setting up a target to develop 5 million tonnes per annum of production capacity by 2030 and an aim to reduce cost of green hydrogen by about 80% to INR 75/ kg (USD 1/ kg) in the next four to five years. The policy is notably silent on all these aspects. Most substantial elements of policy – relating to grid power cost and open access power procurement – fall under the purview of state government agencies, which remain fiercely resistant to growth of open access market. It seems unlikely that they would change their stance for green hydrogen. So what gives? Playing catch up on solar and battery manufacturing, the government is under pressure to scale up green hydrogen. But the challenge of supporting a nascent technology with limited production capacity worldwide and high cost must not be underestimated. It is a classic chicken-and-egg problem. Setting consumption targets for industrial users can be counter-productive in absence of route to economical procurement. We believe that instead of adopting ambitious targets, the government should focus on nurturing an all-round ecosystem through R&D investments, subsidies for pilot projects and seeding infrastructure development.

Leading corporates are increasingly adopting RE 100 pledges to decarbonise their businesses in response to demands from investors and consumers. There are now eight Indian companies alongside many international companies operating in India that have signed up to RE100 pledge.

Rooftop solar and open access are the only two mainstream choices for renewable power procurement;

Corporate renewable can be a critical pillar for sector growth and decarbonisation of the economy;

Consumers can make incremental progress by dovetailing their demand pattern with renewable power output profile and exploring solutions like energy efficiency, storage and solar thermal power;

But the consumers simply have no pathway to 100% RE in the current market and policy framework. Available choices remain limited mainly to rooftop solar and open access, which account for 93% of total corporate renewable business at present. And both these routes face severe restrictions. While rooftop solar is constrained by availability of suitable onsite space, open access remains partially or wholly inaccessible due to denial of approvals or project capacity/ banking restrictions in most states. For an average consumer with 24×7 operation, these two routes can therefore meet typically only about 30% of total power requirement. In Karnataka and Gujarat, where open access wind is viable and project approvals are forthcoming, renewable power share may go up to about 50-60%. All other available options – green power exchange, renewable energy certificates (RECs) and green tariffs – are either too expensive or riddled with cost, liquidity, policy and reliability constraints. These routes can therefore be used only as part of a supplementary sourcing strategy on an opportunistic basis.

Figure: Estimated capacity of different procurement routes, December 2021, MW

Source: BRIDGE TO INDIA research Note: REC capacity has been estimated based on trading volume in FY 2020.

Most of the problems stem from the convoluted grid tariff structure and the need to preserve financial interests of DISCOMs. However, it is becoming increasingly untenable to deny access to renewable power for these archaic reasons. By delaying reform and denying access to renewable power, the policy makers are not only perpetuating sector distress but artificially suppressing growth of the renewable sector and delaying progress on decarbonisation. They are also potentially blocking Indian businesses from staying competitive in the global marketplace, where replacement of fossil fuel sources is seen as an essential business competence.

MNRE has shown some belated willingness to support the corporate renewable market by waiving inter-state transmission charges and liberalising open access route. But these measures are largely cosmetic in absence of more pressing sector reforms and DISCOM support for growth of this market.

In the meantime, the old dictum, ‘necessity is the mother of invention,’ could be helpful for consumers and project developers alike. Consumers can make incremental progress by managing their demand pattern, wherever possible, and exploring solutions like energy efficiency, storage and solar thermal power. There is also an opportunity for a more robust engagement effort with the central and state governments on policy advocacy. The project developers have an attractive opportunity to move beyond commoditised solutions and offer more complex, higher value solutions.

We present five charts summarising key developments in the renewable power sector in 2021.

Soaring module prices and other costsMono-crystalline module prices surged to USD cents 30/ Wp before falling marginally by year end, a rise of 21% over previous year due to rising component prices and shutdown of factories in China. Higher costs affected project viability leaving project developers in a dilemma – import modules at higher prices now or wait for prices to fall and run the risk of basic customs duty payment from April 2022 onwards.

Figure: Module price and total EPC cost

Source: BRIDGE TO INDIA researchNote: Module prices are shown on a CIF basis before domestic duties and taxes. EPC cost includes GST and all duties as applicable at the end of each quarter.

Capacity addition stagnantWe estimate total 2021 capacity addition at 11.2 GW, split between utility scale solar – 7.8 GW, rooftop solar – 1.8 GW and wind – 1.6 GW, 30% below our estimate due to various execution challenges including higher costs, transmission and duty uncertainty.  

Figure: Capacity addition, MW

Source: BRIDGE TO INDIA research

Domestic manufacturing pushThe year saw a series of decisive policy moves to support domestic manufacturing. The PLI scheme received huge interest from 18 bidders for an aggregate capacity of 55 GW. We estimate total installed capacity of polysilicon, cells and modules to touch 30,000 MW, 40,000 MW and 55,000 MW respectively by 2025.

Figure: List of qualified bidders

Source: IREDA

Slowdown in tender activityWhile new tender issuance stayed robust during the year at 33 GW, 40% increase YOY, project allocation fell by 21% to 19.5 GW in response to low willingness of DISCOMs to contract capacity.

Figure: Tender issuance and allocated capacity, MW

Source: BRIDGE TO INDIA research

Offshore debtProject developers raised a total of USD 4.8 billion in offshore debt, a 309% increase over previous year. All-time low yields in western economies (German 10-year government bonds yield at -0.28%, USA 1.14%, UK 0.85%) attracted institutional investors to the sector. Leading developers including Adani (total issuance in 2021 – USD 2.1 billion), ReNew (USD 1 billion), Azure (USD 577 million), Continuum (USD 560 million), Hero (USD 363 million) and Acme (USD 334 million) have benefitted immensely from benign capital market conditions.

Figure: Offshore debt fund raising by project developers, USD million

Source: News reports, press releases and BRIDGE TO INDIA research

The government has approved basic customs duty (BCD) for cells and modules as well as an enhanced budget of INR 240 billion (USD 3.2 billion) for production-linked incentive (PLI) for domestic manufacturers. As per the budget announcement made this week, 25% and 40% BCD would be levied on cells and modules respectively from 1 April 2022 onwards. Both measures were widely expected and finally clear way for a dramatic transformation of the solar sector in India.

We expect total module manufacturing capacity to touch 55,000 MW by 2025;

BCD would add to overall cost pressures in the sector and reduce cost advantage of solar power;

The challenge for the government would be to wean manufacturers away from trade barriers and subsidies over time;

Enhanced PLI budget means that all 15 remaining bidders in the scheme with total bid capacity of 48,600 MW can now be accommodated in the scheme. The move is being hailed across the industry but we question the need for financial incentives when manufacturers have significant protection from imports through BCD and ALMM. The incentive is a waste of taxpayer money. Moreover, it risks distorting the market by creating massive capacity glut. We estimate total installed capacity of polysilicon, cells and modules to touch 30,000 MW, 40,000 MW and 55,000 MW respectively by 2025, far in excess of domestic demand. Some smaller bidders may, however, struggle to raise required funds within the tight deadlines – only 1.5 years for cells-modules. Based on an analysis of the investment requirement vs PLI bids, Adani, First Solar, ReNew, Waaree, Tata Power and Vikram would be the biggest beneficiaries.

Figure: PLI bid capacities and amounts

Source: IREDA’s list of qualified bidders

India’s renewable sector, having so far focused on adding more generation capacity with ever lower tariffs, is set for a drastic change with pivot towards manufacturing. Total manufacturing investment over next three years is expected to touch INR 600 billion (USD 8 billion). Despite oversupply and financial incentives, prices for domestically produced modules are expected to remain higher than for Chinese module prices by up to 10%. It also seems fair to assume that fall in Indian module prices and tariffs would be much more gradual going forward. The challenge for the government would be to wean manufacturers away from trade barriers/ subsidies and ensure that they remain competitive with leading international manufacturers on technology and cost.

Impact on project developers and consumersThe government has refrained from providing any BCD exemption for under construction projects, which will now see capital costs going up by a further 16%. Change in law compensation would ultimately cover utility scale project developers for the additional cost. But there is no clear compensation formula specified in most state tenders resulting in a significant hit because of: i) additional working capital requirement arising from delay of up to 2 years in claim approval from regulators; and ii) inadequate carrying cost allowed in determination of incremental tariff. We estimate total project pipeline impacted by BCD at 38,575 MW with Adani and Azure accounting for the biggest share because of their combined 12,000 MW win in the manufacturing-linked tender.

Figure: Estimated project pipeline affected by BCD imposition, MW

Source: BRIDGE TO INDIA research

BCD would have far more negative impact on the corporate renewable market, where effective cost for consumers would increase by about INR 0.50/ kWh eating into shrinking cost advantage of open access solar.

Other budget announcements The government has also extended operations commencement deadline for new manufacturing companies to avail concessional corporate tax of 15% by a year to March 2024. Beyond the pro-manufacturing announcements, there was little of note in the budget for the sector. Storage has been included within definition of ‘infrastructure’ sector, which may mean marginally better access to financing. The government also announced a plan to issue sovereign green bonds and extended BCD exemption on electrolysers to FY 2024.