Category: Solar

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.

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.

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.

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.

MNRE has expanded scope of the ALMM policy by bringing open access and rooftop solar projects under its purview. As per an order released last week, all open access and net-metering based projects applying for approval from 1 April 2022 onwards may procure only modules approved under ALMM policy.

The ambiguous order has created confusion in the already struggling distributed renewables market;

So far, MNRE has approved only 10.9 GW of module manufacturing capacity and nil cell manufacturing capacity under the policy;

ALMM is a flawed policy concept as it restricts competition, promotes inefficiency and increases costs for consumers;

MNRE has clarified in the past that only Indian manufacturers would be approved under ALMM. But utility scale solar projects bid before 9 March 2021 – 42,491 MW of pipeline – would continue to import modules as they are exempt from both ALMM and BCD. The policy scope has therefore been widened to open a new demand source for domestically manufactured modules.

There are, however, some major discrepancies in the MNRE order. The meaning of “apply for open access” is not clear since open access projects require multiple approvals from different agencies. The lead time of 2.5 months given to such projects is also inadequate as some projects may have already procured, or be in advanced stage of procuring, modules particularly as the Basic Customs Duty is expected to kick in on all imports from April 2022 onwards. Finally, rooftop solar systems are installed in many alternative configurations (gross metering, net billing, or non-grid connected) without net metering benefit. Exclusion of such systems from policy coverage seems to be an oversight. The MNRE order has left a trail of confusion and we expect to see a series of amendments and clarifications in the coming months.

There is another fundamental issue with the new order. So far, MNRE has approved 38 module manufacturers with total manufacturing capacity of 10.9 GW under the ALMM policy. No cell manufacturing capacity has been approved yet. In any case, total estimated domestic cell manufacturing capacity of 3.5 GW is highly insufficient to meet market demand. Commencement of commercial operations by new cell and module manufacturers is expected to take minimum 2-3 years. It is therefore not possible for project developers to comply with the ALMM policy during this period.

Table: Approved module manufacturers under ALMM policy

Source: BRIDGE TO INDIA research

The government has already undertaken a series of measures to promote domestic manufacturing – BCD, domestic content requirement for PSUs, agricultural solar and residential rooftop solar, Production Linked Incentives, manufacturing-linked project development tender, and tax rebates. In the backdrop of such extensive multi-faceted support, the ALMM policy is irrelevant. Moreover, the government’s intent to deny approvals to foreign manufacturers or creation of a walled garden, is akin to a tax on consumers. It restricts competition, promotes inefficiency and increases costs for consumers. If the policy continues to be implemented in its current form, it also runs the risk of international trade litigation and retaliatory measures by other countries.

Trading of Renewable Energy Certificates (REC) resumed on 24 November 2021 after a suspension lasting over 16 months due to a legal tussle over regulated prices. The first trading session saw an enthusiastic response on the back of huge pent-up demand with over 3.5 million RECs traded, out of total accumulated inventory of 8.6 million. Total traded volume was split 9:91 between solar and non-solar RECs at prices of INR 2,000 and INR 1,000 respectively. Interestingly, C&I consumers accounted for 69% share of total purchases on the Indian Energy Exchange, one of the two exchanges trading RECs.

Stricter RPO enforcement is leading to high demand for RECs and may push the prices further up;

High REC prices and limited availability should eventually push obligated entities to procure more renewable power;

We expect the REC mechanism to be eventually amalgamated with other market mechanisms as part of a larger carbon trading market;

Trading had been suspended since June 2020 when some power producers challenged a CERC order removing floor and forbearance prices of INR 1,000 and INR 2,500 respectively. APTEL (Appellate Tribunal of Electricity) has set aside CERC’s order citing that the latter had not complied with stipulated consultation process.

Detailed state level information is not available but we believe that only four states including Karnataka, Rajasthan, Andhra Pradesh and Telangana were Renewable Purchase Obligations (RPO) compliant in FY 2020. Lax RPO enforcement by state regulators, a historic problem, is getting fixed slowly but surely. Recently, Punjab regulator asked the state DISCOMs to clear their RPO shortfall of 562 million kWh by procuring necessary RECs by March 2022. Similarly, Uttar Pradesh regulator imposed a hefty penalty of INR 15 billion (USD 200 million) on the DISCOMs for RPO shortfall of 14.6 billion kWh in FY 2021. Indeed, the Draft Electricity Act Bill, now tabled in the winter session of the Parliament, is proposing additional penalties of up to INR 2.00/ kWh for failure to meet RPOs. Trading momentum should therefore continue at least until March owing to massive RPO backlog.

However, the mechanism is beset with two fundamental problems. One, there is simply not enough supply of RECs as most renewable projects pass associated ‘green attributes’ directly to offtakers. Only 4% of total renewable power capacity is registered for RECs is only 4.5 GW, about (see chart below). Solar’s share in this capacity is only 21%, explaining higher demand and prices for solar RECs.

Figure 4: Capacity addition under REC mechanism, MW

Source: REC Registry of India

Two, there is still no uniform RPO trajectory across the country. States are free to set their own targets irrespective of central government guidance and COP commitments. Even the national trajectory, currently set until only March 2022, needs to be extended.

Looking further ahead, it is a matter of time before REC prices are fully liberalised. CERC should be able to do away with floor and forbearance prices after following a due consultation process. The change would be consistent with the Ministry of Power’s recent recommendations on reforming the REC mechanism. But there is need for a more ambitious overhaul. RECs should be made fungible with other market mechanisms including Perform, Achieve and Trade (PAT) scheme and Energy Saving Certificates (ESCerts) to establish a homogenous and efficient carbon trading market consistent with the new COP deal.

COP26 concluded on 13 November, 2021 with bitter disappointment. The conference was expected to provide a firm roadmap for cutting carbon emissions after the tentative goals agreed in Paris in 2015. But there were no binding commitments on emissions or phasing out fossil fuels, nor any conclusion on global emission standards or any agreement on climate financing from the developed countries.

A deal on carbon trading is being touted as one of the few significant achievements. The new unified ‘rules-based’ global carbon market is meant to allow countries and companies to partially meet their climate targets by buying credits from other countries (arising from their larger than expected emission cuts or carbon sinks). However, it is a complicated deal and seems far from perfect. About 320 million credits, each equivalent to a tonne of CO2, issued since 2013 may still be traded – diluting effectiveness of the initiative. India could be a major beneficiary because of its large accumulated stock of credits but the scheme implementation and enforcement framework is still far from clear.

As a growing economy with rising emissions and heavy dependence on coal, India was under heavy pressure to make concessions at the conference. The Prime Minister made five promises:

Expand total non-fossil fuel based energy capacity to 500 GW by 2030

Meet 50% of energy requirement from renewable sources by 2030 (previous target 40%)

Reduce total carbon emissions by 1 billion tonnes from now until 2030

Reduce the economy’s emissions intensity by at least 45% by 2030 over 2005 levels (previous target 33-35%)

Achieve net-zero emissions status by 2070

While many stakeholders have at least publicly lauded these statements, we find the vagueness and non-effectiveness of these promises disconcerting. Reference to ‘energy’ in the first two promises is a definite mis-statement – the reference ought to have been to ‘power’ instead. More significantly, India is set to undershoot the 2022 renewable power capacity target of 175 GW by a significant margin. Before coming up with ever more ambitious goals, there should have been a clear assessment of various issues plaguing the sector and a comprehensive plan for addressing those. In absence of such methodical planning, the promises appear hollow.

The deadline of 2070 for reducing net emissions to zero is worthless and insincere. Fifty years is simply too long a period to have any material benefit when the environmental need is so dire. GHG emissions must fall by 45% from 2010 levels by 2030 for global warming to be contained within 1.5°C above pre-industrial levels. In contrast, UNFCC predicts emissions to rise by 14% in the business-as-usual trajectory. The available emissions allowance to stay within 1.5°C temperature rise of 400 billion tonnes is being eroded by more than 10% every year.

It is often argued that alongside other developing countries with a relatively small quantum of historic emissions, India has a right to keep burning fossil fuels for its economic growth. But the situation is grim. Rather than delaying its net zero commitment to 2070, it would have been preferable if India had adopted a target of say, 2050, contingent on the developed countries fast tracking their commitments to 2035, and definitive financial support.

India has lost a valuable opportunity to take a leadership role in climate negotiations and prepare its businesses and citizens for a low carbon economy.

SECI has issued a first of its kind standalone battery storage tender for 500 MW/ 1,000 MWh capacity. Tendered capacity is split into two projects of 250 MW/ 500 MWh capacity each to be set up in Rajasthan near Fatehgarh inter-state transmission substation. Projects would be awarded on the basis of a flat availability based fixed charge quoted as INR per MW. Curiously, SECI is proposing to contract only 70% of project capacity. Balance capacity is expected to be utilised by project developers for meeting their internal needs or selling to other system users.

Key terms of the tender are listed below:

Agreement term would be 12 years and the developers are required to transfer project ownership to SECI at the end of the term.

Land would be provided by transmission utility or SECI on a lease basis.

Developers may bid for both projects subject to fulfilment with eligibility criteria.

L2 winner would need to fall within L1 price plus 2% to be eligible to win capacity.

Projects are expected to be completed in 15 months from the date of the agreement.

100% transmission charge waiver would be available for project life if at least 50% of input power is sourced from renewable sources.

Most other provisions including eligibility criteria, delay and performance shortfall penalties, curtailment compensation, payment security mechanism, change in law mechanism etc are similar to provisions in renewable project tenders. While the tender claims to be technology agnostic, technical specifications seem designed for Li-ion batteries. The specifications, however, are onerous and would need to be relaxed: two operational cycles per day, annual degradation of 2.5% on a linear basis, minimum roundtrip efficiency of 85% exclusive of auxiliary power consumption and minimum annual availability of 95%.

Fatehgarh has been chosen as the project location as it has the largest transmission capacity for renewable projects – 14 GW of solar projects have been given connectivity approval so far (only 550 MW commissioned at present). Leading developers with projects connected at Fatehgarh include Adani (5,000 MW), Azure (2,500 MW) and ReNew (1,900 MW).

SECI claims that it has obtained buying interest from DISCOMs but has not confirmed names of any interested offtakers. With ancillary services and some of the other use cases for storage not developed yet in India, primary applications for these projects would be to balance and smoothen renewable power output profile, meet evening peak demand and comply with Deviation Settlement Mechanism regulations. As the batteries may be charged with any power source, it should also be possible to store cheap thermal power at late night for usage in peak morning hours. However, expected effective tariff of around INR 8.00/ kWh raises question mark over acceptance to the DISCOMs.

For the developers, 30% untied capacity would be a tough proposition particularly because of the relatively large project size. It is difficult to anticipate market demand and prices in a nascent sector with evolving regulatory framework and declining cost curve.

We believe that the government’s top objectives for battery storage right now should be to nurture an ecosystem and learning for all stakeholders through pilot installations while minimising investor risk. To that end, the tender size should be cut back drastically to, say, 200 MW/ 400 MWh, and further split into 4-5 projects. The government should also offer capital subsidies to reduce cost for early adopters and get storage projects off the ground.

Following up on its mega announcement in June, Reliance Industries (Reliance) has completed a series of acquisitions and investments heralding its entry in the clean energy sector. The company has: a) acquired 100% stake in Norway-headquartered solar panel manufacturer REC for an enterprise value of INR 58 billion (USD 771 million); b) bought a 40% stake valued at INR 28 billion (USD 372 million) in Sterling & Wilson, one of the world’s largest solar EPC and O&M companies; and c) announced strategic tie-ups with technology companies spanning grid storage, silicon wafer and electrolyser manufacturing.

REC is an integrated polysilicon-module manufacturer with a production capacity of 1.8 GW per annum. The company, one of the first to commercialise PERC and heterojunction technologies (HJT), is regarded as a pioneer in module manufacturing. Inability to compete with Chinese manufacturers on cost – manufacturing operations are split between Norway (polysilicon) and Singapore (cells and modules) – has restrained growth. But with trade protectionism rising and wide-ranging concerns about reliance on Chinese imports, business prospects are looking up. REC is considering plans to set up a 2 GW manufacturing plant in France and a 1 GW plant in the US.

The India-based Sterling & Wilson has expanded aggressively into 24 countries around the world including Middle East, Americas, Europe, SE Asia and Australia. Its business portfolio includes over 11 GW of commissioned and pipeline solar EPC capacity, 8.7 GW of O&M capacity and recent forays in wind-solar hybrid, storage and waste-to-energy sectors.

Other investments/ tie-ups entail relatively young companies with breakthrough technologies under development:

USD 144 million investment in Ambri, a US-based grid energy storage company working on alternatives to lithium-ion technology with more resilient batteries that can store power for up to 24 hours;

USD 29 million investment in Germany’s NexWafe, with a proprietary technology to produce ultra-thin low-cost monocrystalline silicon wafers by going directly from gas phase to finished wafers;

Cooperation agreement with Denmark’s Stiesdal, to make hydrogen electrolysers using Stiesdal’s innovative technology at a significantly lower cost than other prevalent methods and collaborate in development of other technologies for offshore wind energy, fuel cells, and long duration energy storage.

This week, Reliance also gave a first peek into its tangible plans. It is planning to set up a fully integrated 20 GW module manufacturing plant and commission a 3 GW solar power generating capacity for producing 400,000 tonnes of green hydrogen for captive use at its Jamnagar refinery and petrochemical complex. The company has already sought transmission connectivity for a 500 MW solar project.

The scale, breadth and pace of these deals are breath-taking. Reliance has (rightly) identified access to best-in-class technology as a key plank of its business plan. And it is using its deep pockets for acquisitions and strategic tie-ups to cut the lead time required to become an end-to-end player. All boxes to guarantee success – financial might, access to latest technology, scale, integration, large captive market, larger domestic market and favourable policy – are ticked off.

Reliance’s entry into the clean energy sector will bring down costs for consumers and accelerate overall growth. But its plans must be unnerving for some of the existing players. The company seems poised to disrupt manufacturing and installation businesses.

India is reeling from a power crisis, which no one saw coming even as recently as two weeks ago. A mix of various factors including jump in demand following post-COVID economic recovery, depressed renewable power output, fall in domestic coal production and spike in international coal prices has squeezed coal supply and, in turn, led to power shortages and blackouts in multiple states.

Moving 12-month power demand growth, after falling to a low of -7.5% in August 2020, has slowly crept up and increased to over 10% by September 2021. However, growth in renewable power output including power from hydro and biomass sources has hovered around 3-4% in the last year partly because of exceptionally low wind speeds.

Figure 1: Coal and total power generation in India, million kWh

Source: CEA, POSOCO, BRIDGE TO INDIA researchNote: RE generation includes power from all renewable sources including solar, wind, large hydro, small hydro and biomass.

As the only effective balancing source available, coal shoulders heavy burden of meeting residual demand. As Figure 1 shows, coal power output has grown faster (15% in the last 12 months) than total power generation (10.6%). This has eaten into coal stocks as domestic production has failed to keep up (hit by flooding of some mines) and imports have fallen (spike in international prices). Average coal inventory at power plants has fallen from 15 days one year ago to just 3 days or less at many plants.

The government is now proposing higher coal imports despite trebling of international coal prices since September 2020. This is clearly an unworkable plan as DISCOMs/ consumers are not willing to bear higher prices and international freight channels are severely congested. As Figure 2 shows, imports have now shrunk month-on-month for the last five months.

Figure 2: Domestic coal production, imports and international prices

Source: CEA

Coal India, the PSU giant, is dealing with its own precarious problems ranging from diminution of financing and management capacity to delayed payments by power producers. Attempts to make India self-sufficient in coal have borne little results with stagnant production trailing behind targets by huge margins.

Amidst a deteriorating demand-supply balance, short-term trading volume and prices have soared as seen in Figure 3. Peak hour tariffs in the real-term market platform have repeatedly breached INR 20.00/ kWh mark in the past month.

Figure 3: Short-term power trading volume and peak tariffs at Indian Energy Exchange

Sources: IEX, NLDC, CERCNote: Short-term trading volume includes power traded on exchanges and in the bilateral market.

Events of these last two weeks show just how critically the entire power sector is stretched to a breaking point. It is important to draw right lessons from this crisis, surely one of many more to come, as share of intermittent renewable power with must-run status increases. The entire value chain needs more resilience and reform with strengthening of institutional capacity, more reliable payment streams and market-oriented trading mechanisms besides robust long-term planning.

It has been raining auctions again. Seven auctions totalling 3,950 MW have been completed in just seven weeks. Strong bidding interest has led to further fall in tariffs. SECI discovered a record low tariff of INR 2.34-2.35/ kWh for wind-solar hybrid projects in its 1,200 MW auction this week with NTPC (450 MW), Ayana (450), NLC (150) and Azure (150) as the winners. Tariffs fell by 3% over last SECI solar-wind hybrid auction in December 2020. Madhya Pradesh’s 500 MW solar auction received bids of INR 2.14-2.15/ kWh, another new low tariff since announcement of basic customs duty (BCD) on solar cells and modules. Winning bidders in this auction included Tata Power (330 MW) and Saudi Arabia-based Aljomaih (170).

Tenders are getting heavily oversubscribed due to scarcity of auctions and high investor interest;

Tariffs have fallen in comparison to last year despite levy of BCD on solar cells and modules, higher equipment prices and implementation of ALMM;

Only a miraculous fall in equipment costs would make these bids viable;

Bid interest in utility scale tenders is at near all-time high levels. Tenders are getting routinely oversubscribed by 5-6x as developers are anxious to win projects. As the following chart shows, there was a big slowdown in auctions in the 12-month period leading up to July 2021. Scarcity of auctions, huge backlog of unsigned PPAs from last year and strong investor interest have distorted demand-supply balance.

Figure: Winning tariffs in select solar and wind-solar hybrid tenders

Source: BRIDGE TO INDIA research Note: Prices are given for imported modules on a CIF basis, before any domestic taxes and duties.

There were as many as 22 unique bidders in the seven auctions. Aggressive bids by NTPC and other PSUs (total capacity won: 1,125 MW, 28% share) have added to the bidding pressure. Even state tenders with higher offtake risk are sailing through again. In fact, state auctions have dominated this year (88% share) with Madhya Pradesh, Andhra Pradesh, Maharashtra and Gujarat taking the lead. Remarkably, SECI has completed only two auctions this year.

Solar tariffs have hovered broadly in the INR 2.30-2.40 range, lower than levels seen for most of last year. This is despite levy of 25-40% BCD on solar cells and modules, equipment prices shooting up by more than 10%, implementation of ALMM and higher offtake risk. All recently tendered projects face uncertainty in procurement of modules with likely ban on use of imported modules.

It is hard to justify winning bid levels. As we noted recently, investment enthusiasm is running ahead of fundamentals and clouding objective risk assessment. Equipment prices would need to come down by 35-40% for these projects to be viable.

In the past few months, there have been multiple reported instances of Chinese module suppliers renegotiating prices and/ or cancelling orders. Mono-crystalline module prices have surged to USD cents 25/W on a CIF basis (before domestic duties and taxes), a rise of 39% in the last year, on the back of rising input costs.

Spike in polysilicon prices explains most of the recent price increase;

The Chinese manufacturers have been cutting back production rather than accepting lower margins unlike in previous market cycles;

With entire solar value chain expected to become supply side surplus by mid-2022, prices should start falling by middle of next year;

There are two fundamental reasons leading to the jump in prices. The major contributor is a spike in polysilicon and other commodity costs including aluminium, silver and glass in response to global economic recovery. Polysilicon prices, in particular, have jumped by a staggering 4.4x in the last year after a series of disruptions owing to floods, fires and other outages at various factories.

The other contributor to higher prices is increasing consolidation in the module manufacturing business and the changed outlook of leading module suppliers on volumes vs profits. Top 10 suppliers now command 80% market share, up from 47% just five years ago due to aggressive investments in technology upgradation and capacity expansion. The suppliers, already suffering from low margins, have chosen to cut back production rather than accept a reduction in margins. Capacity utilisation for some players in H1 2021 is believed to have fallen to a low of 30-40%. The new practice has even led to accusations of cartelisation against the suppliers.

While market consolidation is expected to carry on, there is relief coming up on the input cost front. Glass prices have already fallen to the lowest levels in recent years as Chinese glass manufacturing capacity has jumped from 28,000 tons/ day last year to an estimated 46,000 tons/ day this year. Polysilicon prices are similarly expected to start coming down from H2 2022 onwards due to huge expansion plans in advanced stages – capacity is expected to grow by more than 2.0x times to 1.5 million tons per annum in the next two years. Downstream cell and module capacity is already well in excess of demand at about 350 GW (2021 demand estimate: 160 GW).

Figure: Relative movement in polysilicon, PV glass and aluminium prices

Source: PV Infolink, BRIDGE TO INDIA research

Even if global demand stays strong, entire solar value chain is expected to have surplus capacity by middle of 2022. Prices should therefore start softening next year. However, a sharp fall, as witnessed in 2018 and 2020, seems unlikely due to higher concentration in the industry. We expect prices to fall more gradually to around USD 20 cents/ W levels by end 2022.

For the Indian market, the implications are not savoury. There is a substantial pipeline of about 30 GWp, reliant on imports, over the next two years. This pipeline is unaffected by ALMM and is also entitled to ‘change in law’ compensation for basic customs duty (BCD). The developers face a tough choice – import modules at higher prices now, or wait for prices to fall next year and deal with BCD risk and delay penalties.

This video presents a summary of major developments for renewable sector tenders with details of tender issuance, bid submission, completed auctions and related market trends. It also covers a snapshot of key policies and regulatory developments from the previous month.

India’s central electricity regulator, CERC, has proposed implementation of a new power scheduling and despatch system titled, Market-Based Economic Despatch (MBED), from 1 April 2022 onwards. MBED requires DISCOMs and conventional power producers to submit buy and sell bids respectively on day-ahead basis on power exchanges rather than scheduling power directly between themselves based on their contracted PPAs. The first phase would be applicable to all DISCOMs but only to NTPC as a power producer.

MBED aims to bring down power procurement cost for DISCOMs by instituting a national level merit order despatch;

Routing all transactions through exchanges would bring sorely needed market discipline to both power producers and purchasers;

It would be crucial to get DISCOMs and state governments on board for effective, time bound implementation;

In effect, MBED is akin to merit order despatch at a national level rather than at state level as at present with the added feature of market trading. The primary rationale is to utilise the cheapest power available and reduce cost for DISCOMs. Where the DISCOMs have already signed PPAs, they would effectively purchase power at the lower of agreed variable rate and market price. Fixed charges for contracted capacity would be paid separately to power producers. CERC has estimated that MBED would reduce overall system cost by 11% and total DISCOM power procurement cost by 7%.

The market trading part is extremely beneficial for two reasons. First, it would improve trading market depth, currently only about 6% of total power volumes, and provide much needed pricing transparency in the sector. True price discovery based on demand-supply, prevailing costs and other operating parameters would send critical market signals to investors, financiers, system operators and policy makers besides facilitating growth in power derivatives and risk management tools. The second major benefit would be timely payment by DISCOMs, who would be required to clear payments to power producers on the day of delivery as against a normal delay of 3-6 months.

There are multiple other benefits. Routing all transactions through exchanges would bring sorely needed market discipline to both power producers and purchasers. Power producers would be incentivised under the new regime to optimise operations and reduce cost. They would also be able to sell any unscheduled capacity in the real-time market (RTM) – DISCOMs would lose the right to this capacity in return for 50% share of profit from sale of power to other consumers. Growth in RTM volumes would provide further impetus to power trading. MBED is also likely to reduce curtailment risk for renewable power as DISCOMs get more flexibility in scheduling conventional power.

So, what’s the catch? DISCOMs would need more financial resources for trading margin and timely payments to power producers. The government is proposing to provide liquidity to them through new funding lines from PFC and REC. But the DISCOMs and state governments could still oppose the new system on grounds of higher funding costs and loss of state autonomy. Thermal IPPs with untied capacities and/ or those with higher costs would also stand to lose because of greater competition particularly in RTM trading. Moreover, increase in inter-state power flows may be constrained by transmission capacity.

MBED is by far the most important proposed reform in the power sector for a very long time. If implemented effectively and in a time bound manner, it would mark a major step towards liberalisation of the Indian power sector and making it more market oriented.

Last two years have seen a rapid growth of ‘virtual’ power plants (VPPs) across the world. A VPP is an aggregated portfolio of distributed energy resources including storage and rooftop solar systems that mimic an actual power plant to provide grid services such as peak load management, grid balancing and fast frequency response. Each distributed resource is centrally controlled via an aggregation software and operated by a service provider or distribution utility. The assets respond to signals from grid operators to inject or withdraw power as needed in a very short amount of time, a span of minutes or even seconds. At the same time, the assets continue to serve their primary role of power supply, backup and energy storage for the owners.

Figure 1: Virtual power plants configuration and benefits

Source: BRIDGE TO INDIA research

VPPs are gaining in popularity across the USA, UK and Australia as power grids increasingly need more flexibility to absorb growing capacity of variable renewable power. Pools of small-medium sized distributed generation systems, located closer to load centres, are best placed to provide system decongestion, frequency support, system upgrade deferral, balancing and ancillary services at a competitive cost. For service providers and owners of the distributed assets, the additional income streams can optimise original investment and enhance returns.

As an example, US-based Sunrun, a leading installer of residential rooftop and storage systems, has signed a contract with the utility Southern California Edison to provide 5 MW capacity for peak management and grid balancing services. Similarly, Green Mountain Power, a US utility, implemented a pilot VPP of 13 MW capacity across 2,567 residential battery storage systems to manage peak demand and provide power backup services. The project saved USD 3 million for the utility over nine months from January to September 2020. In January 2020, Centrica, UK’s gas utility, partnered with battery manufacturer Sonnen to create a VPP comprising 100 residential systems to provide frequency response services to UK’s transmission system operator. VPPs are also being proposed in distributed solar heavy grid of Hawaii to balance the grid.

In the Indian context, C&I renewable developers would be the ideal VPP service providers. While high capital cost has been a key deterrent in adoption of battery storage, the ability to realise additional income streams through VPPs could kickstart the distributed storage market. Recently issued draft ancillary services regulations allowing energy storage to provide ancillary services to the grid also provides hope for VPP prospects.

The government’s Make in India policy is creating endless uncertainty for the solar sector. The Ministry of Commerce and Industry has initiated a new anti-dumping duty (ADD) investigation into solar cell and module imports from China, Thailand and Vietnam potentially dashing hopes of developers for a duty-free window between July 2021 and April 2022. Separately, MNRE has issued a small list of approved manufacturers under its Approved List of Models and Manufacturers (ALMM) policy. Only 21 Indian manufacturers with a total module manufacturing capacity of 8.2 GW have been approved so far. MNRE has refused to provide any clarity on when international suppliers may be approved.

Bizarrely, the anti-dumping investigation comes on behest of only one company, Jupiter Solar (cell capacity 450 MW), which is deemed to represent the entire Indian manufacturing industry. The other applicant, Mundra Solar (an Adani group company with cell and module manufacturing capacity of 1,200 MW), has been excluded from the investigation. There are other unusual aspects to the investigation. “Injury” has been determined to be caused to the “domestic industry” on spurious accounts – module sales by other countries at prices below cost of production and inability of the applicant to sell its production in the “open” market in India. But the applicant has used Indian cost of production as a proxy for cost of production in China (and other countries) ignoring vast differences in scale, technology and capabilities of manufacturers in the two countries. Similarly, the application ignores the fact that project developers prefer imports despite additional duty cost because of their superior technology and limited capacity of Indian manufacturers.

The ALMM policy is equally frustrating. MNRE has indicated that international suppliers may not be approved for another 12-18 months because of COVID-related delays. Delays in approval of more suppliers could massively restrict choice and result in inflated costs. While the policy document mandates projects with bid submission date after 10 April 2021 to use only those modules that have been approved as on the date of module invoice, SECI’s recent 1,785 MW Rajasthan solar tender stipulates that project must use only those modules that have been approved on the date of bid submission. It is impossible for developers to make proper procurement and bidding decisions in such an environment.

The government needs to be careful in walking the tightrope between support for domestic manufacturing and project capacity addition. Manufacturing policy uncertainty is beginning to unnerve investors, already struggling with project viability concerns arising from safeguard duty and the proposed basic customs duty.

PLI bid document at odds with the scheme The Indian Renewable Energy Development Agency (IREDA) has released a bid document for the PLI scheme for domestic module manufacturing. As expected, bidders must ensure minimum backward integration into cell manufacturing, set up at least 1 GW production capacity and produce modules with efficiency greater than 19.5%. Successful bidders would be selected only on the basis of two criteria – extent of backward integration and production capacity (see table below) – through a bucket filling method rather than any competitive bidding as stated in the scheme document.

Figure: Selection criteria for PLI

Depending on module efficiency and temperature coefficient, actual PLI amount is proposed to be between INR 2.25-3.75/ W multiplied by local value addition. However, maximum capacity awarded to any bidder would be capped at 50% of respective bid capacity, or 2,000 MW, whichever is less. Brownfield projects would be eligible for only 50% incentive amounts.

Last date of bid submission is 30 June 2021. We suspect that the market response may be muted because of complex design, relatively small incentive and ambiguity in several provisions vis-à-vis scheme document issued in April 2021.

Coal India Limited, a public sector company and the world’s largest coal producer, won 100 MW capacity in the recent 500 MW solar auction in Gujarat with a bid of INR 2.20/ kWh. Two of the other four bidders in the auction were also PSUs – NTPC and SJVN won 150 MW and 70 MW capacities with bids of INR 2.20 and 2.21 respectively.

With conventional businesses slowing down, the PSUs have set ambitious renewable capacity targets and left themselves with no choice but to bid aggressively;

In a sector with no specific operational or financial complexity, PSU investment is needlessly crowding out private capital;

The PSUs need to instead play to their strengths and look for opportunities where they enjoy a unique competitive advantage;

Gujarat auction marks Coal India’s first foray into mainstream renewable sector project development activity. Together with NTPC, SJVN, other coal miners and IPPs including NLC, Gujarat State Electrical Corporation (GSEC) and Gujarat Industries Power Company (GIPC), the public sector giants are scaling up their renewable ambitions as conventional power prospects get dimmer.

Table: Presence of PSUs in renewable sector

Source: Company websites, BRIDGE TO INDIA researchNote: This data excludes projects where NTPC and other PSUs are acting as intermediary offtakers.

NTPC has set a target of adding 30,000 MW of renewable capacity by 2032. SJVN, a leading hydropower generator, wants to add 12,000 MW solar capacity by 2030. Meanwhile, coal producers like Coal India and NLC are attracted to the sector both by a desire to be seen as “green” as well as the opportunity to use spare cash. Coal India, generating cash profits of almost USD 3 billion per annum and not nearly enough opportunities to expand coal production, plans to develop 3,000 MW solar capacity over three years as well as set up an integrated solar wafer manufacturing facility.

Determined to grow their renewable business, the PSU giants have given themselves no option but to bid aggressively. But two critical questions arise – 1) can they compete against private developers; and 2) what role should they play in the sector? There is no dearth of equity capital in the project development business – there were as many as 49 unique bidders in large scale solar project auctions alone (setting aside small bidders in agricultural solar tenders) in the last two years. Private developers have sufficient capital and not only all necessary operational expertise but also an advantage over their PSU counterparts in terms of cost optimisation, risk appetite and financial engineering. Sure, the PSUs enjoy advantage of cheaper debt – around 7% as against 9-10% for private developers. But being forced to bid low against private competition is resulting in sub-optimal deployment of capital and crowding out of private investment.

If not project development, then what else? Ideally, the PSUs should play to their strengths (complex businesses needing patient capital, technology advantage, low competition) and look for opportunities where they enjoy a unique competitive advantage – for example, upstream solar manufacturing, hydrogen production, smart grids.

We finally have it. After almost a year of uncertainty, MNRE has announced that PV cells and modules shall be subject to basic customs duty (BCD) of 25% and 40% respectively from April 2022 onwards. MNRE has also clarified that only bids submitted until 9 March 2021 shall be offered BCD related ‘change in law’ compensation. Final Finance Ministry notification for effecting the duty is yet to be released.

The one-year implementation interregnum is expected to serve dual purpose – give interested entities lead time to set up manufacturing facilities as well as respite to projects under construction from additional costs. The period is, however, too short on both counts and should have ideally been at least two years.

Imposition of BCD is in breach of the Information Technology Agreements signed by India under WTO framework.The government seems aware that the decision may be challenged by China, US and other countries but is banking on dispute resolution process to take many years. Nonetheless, MNRE decision provides much needed clarity to the sector. We give below our summary assessment of various related issues.

BCD is expected to stay in place for minimum 4-5 yearsLack of clarity about period of duty imposition is not a surprise as end date for BCD is typically not announced upfront. But it is acknowledged that safeguard duty (SGD) failed to have any beneficial impact on domestic manufacturing because of its limited time span. The government has already informally indicated that BCD would stay in place for at least 4-5 years.

SGD extension almost certainLast year, SGD was extended until July 2021. We expect another extension at the prevailing 14.50% rate until March 2022 notwithstanding the fact that the Commerce Ministry’s trade investigation is still not complete.

Steep duty would dim solar’s shine 40% duty level is excessive as the cost disadvantage for domestic manufacturers is believed to be no more than 20-25% and the government has already outlined production-linked incentives and demand enhancement for domestically manufactured modules.

The cost impact would be compounded by 10% Social Welfare Surcharge raising effective level of duty to 44% and increasing solar tariffs by about INR 0.52/ kWh. The extra cost would not be welcome by DISCOMs particularly when they are already reluctant to purchase vanilla solar power. The duty improves relative cost attractiveness of wind power and solar-wind hybrid power. 

Higher cost would also dampen long-term growth prospects in rooftop solar and open access solar although there would be a temporary demand boost around H1/ 2022 to avoid BCD burden.

Terrible news for pipeline projects While ‘change in law’ provisions are enshrined in most PPAs now, proposed compensation increase of INR 0.005/ kWh tariff for every INR 100,000/ MW increase in project cost is not adequate. The formula does not consider ‘carry’ cost of BCD for 25 years and leaves project developers out of pocket by about INR 0.05/ kWh.

On the flip side, the DISCOMs would be even more reluctant to sign PPAs for nearly 18,000 MW of project capacity tendered in the past year – at tariffs ranging between INR 2.36-2.92/ kWh – because of extra ‘change in law’ cost.

Surge in capacity addition expected in H1 2022Most developers would be keen to import modules for under development projects before BCD comes into effect subject to module price outlook and availability from tier 1 suppliers. H1 2022 could be a really busy time with utility scale solar capacity addition of as much as 10,000 MW.

Little improvement in competitiveness of domestic manufacturing We maintain that BCD does little to improve cost competitiveness of Indian manufacturing. Small scale, lack of domestic supply chain and dependence on imported technology (plus upstream components) means that India’s self-sufficiency hopes would remain elusive for the foreseeable future.

We expect 10-12 GW of module manufacturing capacity to be developed over the next three years. Interest in cell and other upstream manufacturing is expected to be much lower because of higher capital cost and technology risk (and lower duty).

As C&I consumers in India seek to procure more renewable power, they are keen to consider alternative procurement models particularly because of the various challenges faced by traditional rooftop solar and open access routes. A new route, virtual power purchase agreements (VPPAs), immensely popular internationally, is gaining more attention in the process. In the USA, VPPA volumes were estimated at 6.4 GW in 2018 and 3.8 GW in H1 2019. The model has become the favoured choice of consumers in the USA, UK, Australia and elsewhere. It is preferred over conventional PPAs and other procurement routes because of its simplicity and scalability.

VPPAs are hybrid financial transactions providing effective price hedge to both project developers and consumers subject to efficient exchange-based trading of power;

VPPAs have huge growth potential in India as physical delivery-based open access route faces severe implementation barriers in many states;

Many large consumers are keen to tap the VPPA model in India but progress still seems some way off because of various regulatory glitches;

A VPPA is a hybrid transaction, somewhat akin to a Contract for Difference (CFD), whereby a consumer agrees to notionally purchase power from a project developer for a fixed cost (strike price, X) and period. But both parties trade physical power on the exchange at prevailing market prices (M) and settle the difference between strike price and market price periodically between themselves, effectively providing them a complete price hedge. ‘Green’ attributes attached with renewable power, or RECs, are simultaneously transferred by the developer to the consumer.

Source: BRIDGE TO INDIANote: This chart shows only financial flows between different counter-parties.

The VPPA model is best used when a renewable power plant is not able to supply physical power directly to the consumer because of sub-optimal location (lack of suitable land in proximity or high cost, low resource) and/ or transmission constraints and/ or high grid charges. There is no need for the two parties to be connected to the same utility or regional transmission network. On the flip side, VPPAs require an efficient exchange-based market with market price parity between the points of power generation and consumption. Any deviation in prices at the two points reduces effectiveness of the hedge. Similarly, VPPAs work only when there is negligible curtailment risk.

In India, VPPAs can help consumers overcome lack of inter-state scheduling of power, infrastructure constraints as well as policy risk associated with open access. The model could be huge success in states like Haryana, Punjab, West Bengal, amongst others, where such challenges have prevented growth of open access renewable market so far. But there are a few regulatory and market challenges in the way. First, there is no clarity over regulatory jurisdiction over VPPAs. Since VPPAs are structured as bilateral contracts i.e., not traded on any platform, there should be no approval required from any regulatory agency for such transactions. But both CERC and SEBI, the financial market regulator, claim jurisdiction over all power derivative contracts. Subsequent to a legal case, the two agencies have agreed that SEBI would regulate financially traded contracts, while CERC would oversee physically settled contracts. However, VPPAs combine elements of both financial and physical settlement and hence, ambiguity in this matter still persists.

The second major regulatory issue with VPPAs relates to bilateral transfer of ‘green’ attributes or RECs from project developer to consumer, which is currently not allowed in India. Moreover, the project developer needs to sell power on the ‘brown’ exchange to retain ‘green’ attributes for transfer to the consumer. But selling renewable power on the ‘brown’ exchange is not viable due to onerous forecasting & scheduling provisions. High (and volatile) short-term open access charges are also a barrier.

We understand that as open access market is facing severe implementation challenges in many states, some international IT and manufacturing companies are actively exploring feasibility of the VPPA model in India. But progress still seems some way off.

Andhra Pradesh completed auction for its mega solar tender last week. Winners include Adani (2,400 MW), Shirdi Sai and HES Infrastructure (believed to be affiliates of Greenko, together 2,500 MW), NTPC (600 MW) and Torrent Power (300 MW) with tariffs ranging between INR 2.47-2.49/ kWh. Another 600 MW project was won by Adani with a bid of INR 2.59/kWh but the state government has not accepted this relatively high bid. Projects would be developed in 10 government solar parks across the state.

The state has had to offer a sweet deal to attract developers following its regressive actions in the last two years;

Bidding interest was confined to select domestic developers with tariffs expectedly coming at significantly higher levels than in recent auctions;

These projects, if implemented, would pose serious grid management problems given that Andhra Pradesh’s total power requirement is only around 9 GW but the state already has total operational renewable capacity of 7.9 GW;

Andhra Pradesh became a pariah state for the renewable sector after its brazen attempt to renegotiate all past PPAs in July 2019. Subsequently, the state also cancelled all under development projects, withdrew financial incentives provided to open access projects as well as banking provision for renewable power. The PPA renegotiation case is still stuck in the High Court, which has in the meantime directed DISCOMs to reduce tariff payments to IPPs to INR 2.43-2.44/ kWh, down 43% over the capacity-weighted average contracted tariff of INR 4.28/kWh. The move has caused huge financial stress to investors. Renewable capacity addition in the state fell sharply from 1,138 MW in 2019 to 269 MW in 2020.

Unsurprisingly, the state has had to offer a sweet deal to attract developers. Payment security package comprises letter of credit for an unprecedented four months beside a state government guarantee. PPA tenor is longer at 30 years instead of standard 25 years and solar park charges have been kept low (see table below).

Table: Solar park charges payable by developers, INR/ MW

Source: BRIDGE TO INDIA research

Despite the sops, the state failed to attract interest from most of the developer community. Bidding interest was confined to select domestic developers. Tariffs are expectedly significantly higher than in recent auctions with estimated equity returns considerably over 20%.

The tender seems like an exercise in grand-standing and reviving the government’s reputation. The apparent objective is to reduce burden of tariff subsidies (FY 2020, INR 75 billion (USD 1 billion) arising from providing free power to farmers. The sheer scale of the tender is hard to justify. Andhra Pradesh’s total power requirement is only around 9 GW and the state already has total operational renewable capacity of 7.9 GW. We believe that these projects, if implemented, would pose serious grid management problems.

There is another fly in the ointment. The High Court has put a stay on the tender following an appeal by Tata Power. The core issue is that the state government has stripped APERC, the state power regulator, of all jurisdictional powers including tariff approval and dispute resolution in violation of the Electricity Act. The High Court is due to hear the matter next week.