Category: Market Outlook

This video presents a monthly snapshot of key policy and regulatory developments in India’s renewable power sector.

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The Indian Cabinet has approved Production Linked Incentive (PLI) scheme worth INR 45 billion (USD 602 million) for domestic solar manufacturing. The scheme targets total cell-module manufacturing capacity addition of 10,000 MW. Prospective manufacturers need to bid for “production linked” incentive, expected by them over first five years of operations, in a competitive bidding process. The incentive amount is expected to be staggered based on total capacity, module efficiency and extent of vertical integration.

Actual incentive level is expected to be around 4-6% of cost of production;
The scheme is unlikely to have any beneficial impact besides improving profitability of domestic market-focused manufacturers;
We revise upwards our estimate of module manufacturing capacity addition in the next three years to 10 GW;

The government has been providing PLI for other key sectors like electronics and pharmaceuticals without following any auction process. Incentive levels have varied typically around 4-6% of cost of production for granting PLI in these sectors.
MNRE is expected to announce scheme details shortly. Competitive bidding process is proposed to be completed in the next few months thereafter. It would be interesting to see scheme design and final auction process with regards to tiering of incentive structure with capacity, module efficiency and extent of vertical integration. As per ball-park calculations, assuming 100% capacity and funds utilisation, effective incentive amount would work out to 6.25% for average module price of USD 0.20/ W. Actual incentive may be much less depending on competitive bidding process and other variables. Such low levels would be unattractive for most bidders particularly if they have to comply with stringent tender requirements and provide performance guarantees.
The important question is how will PLI support domestic manufacturing? Cost disadvantage of Indian manufacturing in comparison to leading Chinese suppliers is widely believed to be about 20-25%. For domestic sales, the manufacturers would already enjoy a robust 40% BCD protection from April 2022 onwards besides a number of demand assurance measures (PSU, KUSUM and residential rooftop solar schemes). For exports, the proposed incentive is nowhere near adequate levels. The desired purpose of the scheme, coming on top of BCD, is therefore questionable – it would only serve to improve domestic market-focused manufacturing profitability, which should already be healthy with 40% BCD.
With both BCD and PLI implementation moving forward, we revise upwards our estimate of new manufacturing capacity addition in the next three years to 10 GW. Adani remains the biggest potential player with Waaree, Vikram, ReNew and Jakson also keen to set up capacities. But China’s stranglehold in solar manufacturing is now so strong, most of these players would be heavily dependent on Chinese technology and/ or raw materials. The following chart shows wide gulf in capacity of leading Indian and Chinese manufacturers.
Figure: Current solar module production capacity of leading Indian and Chinese players
223921
Source: BRIDGE TO INDIA research
In conclusion, trade barriers and incentives would lead to more domestic manufacturing capacity but the goals of self-sufficiency and making India a “global manufacturing hub” are unrealistic.
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Maharashtra has become the latest state to offer ‘green tariff’ option to grid power consumers. This route allows consumers to notionally procure renewable power through DISCOMs without incurring any capital expenditure or entering into complicated renewable power purchase agreements directly with power producers. As per the state regulator MERC’s notification, all consumers, irrespective of size or connection type, may opt for ‘green tariff’ at a premium of INR 0.66/ kWh over normal applicable tariffs for 100% of their power needs for minimum period of one year.

Simplicity of ‘green tariffs’ is a major positive as consumers face tough choices in traditional renewable power procurement;

It is crucial to ensure that ‘green tariffs’ lead to a direct increase in consumption of renewable power;

The model could gain critical mass if regulators and DISCOMs show more creativity with tariff design and contract structures in response to market needs;

Maharashtra is the third state after Karnataka and Andhra Pradesh to offer ‘green tariffs.’ It has followed broadly the same model by charging a flat premium for green power over existing retail tariffs. The premium has been worked out by MERC based on expected incremental cost of renewable power over conventional power up to FY 2025 across all state DISCOMs. Unlike the other two states, however, it has rightly offered the new option to all consumers including residential and SME consumers, who may be more willing to pay a tariff premium.

Increasing consumer choice by offering ‘green tariffs’ is eminently desirable. More consumers want renewable power because of growing environmental awareness. But direct procurement routes such as rooftop solar (lack of physical space), open access (unwillingness to enter into binding long-term PPAs, policy uncertainty) and green power trading (small volumes, high degree of sophistication required for trading) can be difficult. REC trading has been suspended since July 2020. ‘Green tariffs’ are more accessible with the added potential advantage of allowing DISCOMs to retain consumers rather than losing them to other routes.

The model would need to evolve as there are some serious loopholes. The biggest one is that the proposed structure does not lead to any actual increase in renewable power capacity or consumption. Karnataka and Andhra Pradesh pass on ‘green attributes’ or associated RECs to ‘green tariff’ consumers but both of them have contracted renewable power in excess of their RPO requirement. As Maharashtra is lagging behind on RPO, the state regulator has decided that ‘green attributes’ would be retained by DISCOMs to “reduce extra cost burden for them.”

In Andhra Pradesh and Karnataka, where the ‘green tariff’ option is only available to larger C&I consumers, uptake has been disappointing. We understand that in both states, only one consumer has signed up so far. Consumers are reluctant to pay a premium over already high grid tariffs. State governments and DISCOMs therefore need to examine new pricing models to increase adoption. Consumers should also have choice to vary quantum of green power purchased by them. For example, if a consumer wants to cap ‘green tariff’ purchase to meet its RPO targets, it should be allowed to do so.

The ‘green tariff’ model has gained strong traction in international markets including Australia, China, Europe and USA. In the US, the model accounted for nearly 40% of all corporate renewable procurement in 2020. It has grown consistently since introduction in 2013 accounting for 4% share of total renewable power capacity. The market has evolved hugely in response to consumer needs, utility perspective and local market conditions with multiple implementation models including sleeved PPAs, renewable power subscriber programmes and hybrid structures as well as flexible contract tenures.

We expect the ‘green tariff’ model to gain more prominence in India. Tariff design and consumer flexibility would be critical for future growth. Uptake in residential and SME consumers may be a positive surprise.

SECI concluded its 1,200 MW ISTS wind tranche X auction earlier this week. The tender was oversubscribed by 2.6 times. Successful bidders include Adani (300 MW), Ayana (300 MW), Evergreen Power (150 MW) and JSW (450 MW) with tariffs between INR 2.77-2.78/ kWh. Azure (300 MW, INR 2.79/kWh), O2 (300, 2.80), Shirdi Sai (300, 2.84), AMP (150, 2.88), Enel (150, 3.06), ReNew (300, 3.28) and SITAC RE (300, 3.39) were the unsuccessful bidders. Entire power output would be purchased by Rajasthan DISCOMs.

A combination of lower wind speed in proposed locations, more expensive land and lower tariff would put margins under pressure;

Pressure on developers to deploy capital has led them to bid aggressively notwithstanding operational and financial concerns;

Competitive proposition of wind power vs solar power looks better after 40% BCD on solar modules;

Transmission connectivity is restricted to six pre-identified substations in Karnataka, Tamil Nadu, Maharashtra and Madhya Pradesh. The tender is SECI’s attempt to seek wider geographical spread for wind projects after repeated undersubscription in pan India ISTS tenders. Most projects under these tenders, proposed to be located in Gujarat and Tamil Nadu because of higher wind speeds, have been delayed extensively due to severe land and transmission capacity constraints (besides rising capital costs).

Figure: Wind auction results since 2018

Source: BRIDGE TO INDIA research

Remarkably, this was the first fully subscribed pure wind auction by SECI in over 1.5 years. The number of interested bidders, 11, is the highest for pure wind auctions in nearly three years. For Ayana, Azure, O2, Shirdi Sai and Amp, it is their first bid ever for a wind project. Mixed record of solar auctions in the recent past – lack of DISCOM interest despite record low tariffs – has forced developers to turn attention to wind power. Increase in bid intensity has inevitably led to aggressive bidding. As seen in the chart, the auction tariff of INR 2.77-2.78 is the lowest since September 2018.

Pressure on developers to scale up and deploy capital has led them to set aside concerns related to land acquisition, supply side problems and rising capital costs. We understand that most project developers are looking to set up projects in Karnataka. But a combination of lower wind speed, more expensive land and lower tariff would put margins under pressure. Our financial calculations show equity IRR in the sub-10% territory. With little expectation of wind turbine cost coming down unlike solar equipment, it is hard to justify these tariffs.

The auction result is a sure but small step towards revival in wind power procurement after lull over last couple of years. Competitive proposition of wind power looks better with solar tariffs set to rise by about INR 0.52/ kWh after 40% BCD. Wind also does a better job than solar in meeting evening peak power demand. But turbine supply side – both quantity and prices – remains a daunting challenge.

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).

The new US Energy Secretary, Jennifer Granholm, has signalled a transformational shift in the country’s energy policy to combat global warming. In her first public speech in the new role, Granholm announced that the US would install “hundreds of gigawatts” of clean energy capacity in the next four years to meet its climate targets. Granholm is aiming to gradually shut down oil & gas production to accelerate energy transition. She has also directed investment amounting to “billions of dollars” with revival of a USD 40 billion government loan programme, defunct under the previous government, towards clean energy technology innovation.

Besides the US, China, Japan and EU have announced radical new climate action goals and thrust on clean energy technologies;

We expect global renewable power capacity addition to jump by about 40-50% over the next 2-3 years to over 300 GW per annum;

The expected boom would throw open new opportunities and challenges for the Indian market;

The comments were made by the Energy Secretary at an industry conference this week. Formal policy announcements are still awaited. But the roadmap is becoming clearer after the US re-joined Paris Climate Agreement in January 2021. The US plans to achieve 100% carbon-free power generation by 2035 and carbon neutral status by 2050.

Other major economies including China, Japan and the EU have made similar bold announcements recently. Last month, China released its draft national renewable energy targets for 2030 with share of non-hydro renewable power expected to grow to 25.9% from 12.7% in 2021. Provisional calculations suggest addition of total solar and wind power capacity of a staggering 1,600 GW by 2030, or about 160 GW per annum. Subsequent to announcement of aiming to achieve net-zero status by 2060, China is now focusing on green and low-carbon circular economic development with reliance on locally developed technologies, creation of “green communities” and “zero-carbon cities.” Meanwhile, Germany, the largest economy in the EU, plans to add 48 GW solar capacity by 2030.  

Figure: Total installed capacity and penetration

Source: GWEC, BNEF, AECEA, MNRE, Germany’s federal network agency, BRIDGE TO INDIA research

These are all stunning announcements and herald a new boom era for renewables. Global capacity addition could plausibly jump by about 40-50% over the next 2-3 years to cross 300 GW per annum. The boom would mean more capital flows into the sector, more innovation in technology and faster trajectory for reduction in costs.

This is all good news for the Indian market. But as more countries strive to attract investments, India would need to improve its game to stay relevant. Inconsistent policy regime, implementation snafus and failing distribution utilities need to be tackled immediately. Moreover, there is a real danger that as other countries invest aggressively in R&D and deployment of new technologies, ‘Make in India’ could become more forbidding. In the short-term, there is also a risk of equipment prices further firming up in line with the trend over the past few months.

This video presents a summary of major developments for renewable tenders during the month. It includes details of tender issuance, bid submission, completed auctions and related market trend.

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.

Gujarat’s new solar policy has severely restricted banking provision for surplus power. Banking shall be available to HT consumers only on a daily basis (residential and LT consumers: monthly basis) and only within specified day hours. The state has also proposed a sharp increase in banking fee to INR 1.10-1.50/ kWh for corporate consumers (previously 2%).

Gujarat joins a growing number of state militating against banking of renewable power. Until three years ago, most states allowed free banking until end of the financial year. But as more consumers seek to procure renewable power independently, DISCOMs and state government agencies are trying to curb the sector by making grid connectivity and banking provisions more onerous (see figure below).

Figure: Banking policies in key sates for C&I renewable power

Source: BRIDGE TO INDIA research

Banking restrictions come mainly in two forms. States are curbing both the amount of maximum power that can be banked as well as period for which power can be banked. While some states like Andhra Pradesh are completely disallowing banking, others like Tamil Nadu and Maharashtra now allow banking only for a much shorter period, typically a month. Maharashtra has capped banking at 10% of total generation, while the Joint Electricity Regulatory Commission (jurisdiction Goa and union territories) has proposed to allow banking facility for only 20% of monthly generation. Carry forward of surplus power is allowed to the next billing period, but only if it is below 100 units. Telangana allows carry forward of surplus power only on a half-yearly basis. Haryana allows no banking for third party sale projects. Some states are coming up with novel ways to curb banking. For instance, Punjab allows banking for open access projects only in cases of unscheduled power cuts, which practically means no banking facility for these projects.

Second restriction faced by power producers relates to reduction in compensation for surplus power and/ or levy of banking charges. States are reducing compensation to typically around 75% of average auction tariff or generic tariff (INR 1.50-3.00/ kWh).

Consequently, consumers and project developers are being forced to be more conservative in project sizing to minimise instances of surplus generation. The attempt to cut banking periods and escalate banking charges, together with reversal of net metering and open access incentives, is unfortunately dimming growth prospects of C&I renewable power sector.

Gujarat has done it again. The state’s power procurement agency, Gujarat Urja Vikas Nigam Limited (GUVNL), has cancelled projects awarded under its 700 MW Dholera and 100 MW Raghanesda solar park tenders. Auctions for the two tenders were completed in August 2020 and September 2020 respectively with projects being awarded to Tata Power, Vena, ReNew, O2 Power and SJVN at tariffs between INR 2.73-2.81/ kWh. GUVNL had already issued LOAs (letters of award) to the successful bidders but has now reversed its decision in view of low tariffs discovered in recent auctions.

Cancellation of bids would lead to substantial losses for the successful developers, who had started making concrete progress on project development;

GUVNL’s decision is inexplicable since both tenders were repeatedly undersubscribed due to challenging locations with high flooding and corrosion risk;

An urgent overhaul of tender framework is required to make the process sacrosanct and reduce opportunistic leeway for all parties;

GUVNL believes that since tariffs have been coming down, it should conduct fresh auctions and seek lower tariffs to protect consumer interests. It had previously cancelled a 500 MW solar auction completed in April 2018 (tariffs of INR 2.98-3.06/ kWh) and another 700 MW solar auction completed in December 2018 (INR 2.34-2.89/ kWh) for the same reasons.

GUVNL’s decision would lead to substantial losses for the successful developers. Mindful of the short construction period (15 months) and tough site conditions, they had already paid solar park charges and were making concrete progress on project development. Some of them have even placed equipment orders. For its part, GUVNL had also filed petitions with the state regulator for approval of auction tariffs and was apparently in regular touch with the developers for ensuring speedy execution.

Moreover, GUVNL is well aware that Dholera and Raghanesda are challenging locations for solar projects. The sites, located close to the coast, have silty soil and face extremely high flooding and corrosion risk. Projects require special design entailing higher capital (about INR 3-4 million/ MW, capital cost uplift of about 6%) and operating costs to deal with these risks. The two tenders were repeatedly undersubscribed until GUVNL increased ceiling tariff to INR 2.92.

We believe that cancellation of tenders with benefit of hindsight is indefensible. Unfortunately, the developers have no legal protection under the existing bidding framework until the PPAs are signed and approved by respective regulators. Unwillingness of DISCOMs to sign PPAs and arbitrary cancellation of tenders are draining market confidence.

An urgent overhaul of the tender framework is required to make auctions sacrosanct and reduce opportunistic leeway for all parties. Amongst other measures, tenders should be issued only after identifying offtakers and with ceiling tariffs, pre-approved by the regulators. Second, the tenders should have clearly specified deadlines for PPA execution and project construction. Thirdly, if the procurement agencies decide unilaterally to not proceed with a tender after completing auction, they should compensate successful bidders for their bidding effort and cost.

This video presents a monthly snapshot of key policy and regulatory developments in India’s renewable power sector.

Prices of solar modules, on a downward trajectory following the COVID-19 pandemic, have moved up sharply in the last few months. Mono-PERC module prices had fallen to a low of USD 0.18/ W in July 2020 but have since increased by more than 16% to USD 0.21-0.22/ W. Initially, prices rose due to a spate of supply side disruptions caused by explosions and flooding at various polysilicon factories in China. Subsequent surge in local demand towards the end of the year contributed not only to prices staying up but also shortfall in availability for the Indian market.

Solar module market is undergoing a massive technological and supply side shift;

Soaring global demand in 2021 means that outlook for module prices is unclear;

The increase in prices has come at an inopportune time for the Indian solar sector with expected 2021 imports at an all-time high of 14 GW;

Solar module market is witnessing a frantic pace of technology and structural changes. Higher efficiency mono-PERC modules have almost entirely replaced multi-crystalline modules. Simultaneously, there is a push towards larger wafers and bigger modules, which has caused equipment shortages. Tier 2 and 3 suppliers in China, unable to invest in new technologies, have been squeezed out and leading suppliers are gaining market share at their cost.

Figure: Solar module prices in 2020, USD cents/ W

Source: BRIDGE TO INDIA research

Most supply side issues are expected to ease over the next two quarters. But on the other hand, global demand is expected to reach 145-150 GW this year, about 20% higher than in 2020, with sharp bounce back in demand across the US, Europe and China. Market consolidation in China and increasing global demand mean that outlook for module prices remains unclear.

Indian project developers, typically hard negotiators on prices, are facing a host of challenges including prices being renegotiated upwards by the suppliers and delayed shipments. Even freight rates have shot up 5-8 times due to container shortages. Fortunately for them, exchange rate has been moving in other direction with USD-INR easing by 6% to 72.90 from the annual high of 77.38 in May 2020.

Indian module import data shows volumes gradually picking up. But H2/2020 imports at 3.2 GW are still much lower than expected. 2021 should be a huge year for Indian solar sector with total expected installations of 13.5 GW (AC), equivalent to module demand of at least 18 GW. Setting aside about 4 GW supply from domestic manufacturers, total imports for the year are expected at 14 GW. The increase in prices has come at a distinctly inopportune time for the sector.

Tata Power recently completed acquisition of 51% stake in WESCO and SOUTHCO, two of the four Odisha DISCOMs, covering western and southern parts of the state respectively. Remaining 49% stake will continue to be held by the government of Odisha. The company will operate the two businesses for a period of 25 years. It is also keen to acquire the other two DISCOMs – CESU, where it has already acquired an LOI and NESCO, where it is the sole bidder.

Central government seems to be pinning all its hopes on DISCOM privatisation for revival of the chronically troublesome distribution business;

But power distribution in large states with low consumer density and high agricultural consumption is a far more challenging proposition than distribution in cities;

The government needs to act decisively as DISCOMs financial position is deteriorating rapidly while the range of choices available to fix the sector are narrowing;

Privatisation of DISCOMs seems to be becoming primary hope of the central government for fixing the chronically troublesome distribution business. Progress has been held up on Electricity Act amendments and associated policy measures. Interestingly, while the central government is seeking support from state governments on these policy measures as part of quid pro quo for the INR 1.2 trillion (USD 17.6 billion) DISCOM liquidity support package, it gave in rather quickly to the farmers’ demand to not pass the Electricity Amendment Bill 2020.

The enthusiasm for privatisation stems mainly from perceived success of private DISCOMs in Delhi, Mumbai, Kolkata and Ahmedabad. But power distribution in large states with large geographical spread, low consumer density and high agricultural consumption is an altogether more challenging proposition in comparison to distribution in dense urban clusters with no agricultural loads. A summary comparison of Odisha and Delhi distribution businesses highlights these differences.

Table: Summary comparison of Odisha DISCOMs with Delhi DISCOMs for FY 2019

Source: Power Finance Corporation’s Performance Report of State Power Utilities FY 2018-19

The case of Odisha DISCOMs holds a cautionary tale. Odisha was the first Indian state to privatise its power distribution business in 1999 after AES and BSES gained majority control of the four DISCOMs. But the experiment was not successful with AES abandoning operations in 2001 (the state government revoked its licence in 2005). Then in 2015, the state government also cancelled the three licences given to BSES after persistent operational and financial underperformance of the DISCOMs (see table below).

Table: Performance of Odisha DISCOMs

Source: Power Finance Corporation’s Performance Report of State Power Utilities

According to a recent report by NITI Aayog, the failure of private DISCOMs was mainly on account of inadequate capital expenditure in the distribution network to reduce AT&C losses. But the private parties complained of inaccurate baseline data, high ratio of rural consumers and unmetered connections.

Elsewhere, the central government is pushing through privatisation in union territories of Puducherry and Chandigarh. But the Uttar Pradesh government has already given up on proposed privatisation of Purvanchal DISCOM after facing resistance from its employees.

If the government is serious about privatisation, it needs to commit more political capital as well as learn appropriate lessons from the previous experience. A half-hearted approach and another failed episode will have adverse repercussions across the power sector. Rapidly deteriorating position of DISCOMs and narrowing range of choices to fix the sector means the government needs to act quickly and decisively.

2020 recap in five charts

We look at five charts summarising key developments in the renewable power sector in 2020.

Record-low solar tariffGujarat’s 500 MW solar auction led to a new record low tariff of INR 1.99/ kWh. The new record came on the heels of previous record of INR 2.00/ kWh discovered just one month earlier in SECI’s Rajasthan 1,070 MW solar auction. The lowest solar tariff has dipped by 54% over last five years and by 18% in the last year.

Figure 1: Solar tariffs in 2020, INR/ kWh                   

Source: BRIDGE TO INDIA research Note: Auctions for solar-wind hybrid and other hybrid projects are excluded in this chart.

Mixed trend in tenders and auctionsA total of 19 tenders aggregating 32.8 GW capacity were issued in the year, down 20% over 2019. Capacity allocated increased to 27.3 GW, up 39% over previous year mainly due to the 12 GW capacity allocated under SECI’s mega manufacturing linked solar tender. However, up to 18 GW of this capacity remains uncontracted with DISCOMs.

Figure 2: Renewable tenders and auctions, MW

Source: BRIDGE TO INDIA research

Volatile module pricesPrices of solar modules fell as COVID-19 initially hit project construction but spiked up in the second half of 2020 due to supply chain disruptions in China and spurt in international demand.

Figure 3: Solar module prices, USD cents/ W

Source: BRIDGE TO INDIA research

Major swings in power demand and supply mixPower demand was unsurprisingly subdued during the year. Total power generation reached 1,308 billion kWh, a 6% dip over 2019. But generation from renewable power sources, excluding large hydro, was up nearly 14% y-o-y thanks to the must-run status of the sector.

Figure 4: Power generation, billion kWh

Source: Central Electricity Authority

DISCOM dues to power generators rise even further By November 2020, the latest available data, outstanding payments of DISCOMs had touched a record high of INR 1.3 trillion (USD 17.7 billion) as per the government’s PRAAPTI portal. The rise came despite disbursement of INR 300 billion (USD 4.1 billion) debt funding under the central government’s liquidity package to clear IPP dues.  

Figure 5: DISCOM payment dues, INR million

Source: PRAAPTI portal, Ministry of PowerNote: PRAAPTI portal data is incomplete as it relies on voluntary data submisison by IPPs. Actual outstanding payments are believed to be much higher as seen in the PFC’s report on performance of state power utilities.

As 2020 comes to an end, we take stock of what the year meant for the renewable power sector. It has been a phenomenal whirlwind of a year throwing off-course plans of all stakeholders. COVID has caused unimaginable disruption by further weakening power demand, diminishing DISCOM finances and slowing down project execution.

We list below ten major sector developments during the year. Most of these themes are likely to play out for a long time shaping the sector in innumerable ways.

DISCOMs sink furtherDISCOMs have taken a financial battering with reduction in C&I demand and poor billing and collection performance. Annual losses and payment dues to suppliers are expected to reach all-time highs. Average payment period for power purchase is near the inconceivable 6-month mark. The government’s INR 1.2 trillion (USD 16 billion) liquidity package has proven too small and inadequate in stopping haemorrhaging of DISCOM finances.

Reform hopes remain hopesThere has been almost no progress on long pending power sector reforms. The central government has sought commitments from states on their support for measures such as payment of tariff subsidies directly to consumers, reduction of AT&C losses, regulatory independence, tariff rationalisation and simplification. But many states remain firmly opposed to reforms and the central government has little political will to enforce a solution.

Power purchasers disappearDespite sharp slowdown in power demand, tender issuance and auctions remained relatively robust at 33,087 and 8,014 MW (down 16% and 72% over 2019) respectively. While MNRE and SECI have pushed through auctions, the DISCOMs have been reluctant to sign PPAs with almost 18,000 MW of unsigned PPAs causing a huge overhang on the sector.

Hybrid renewables becoming mainstreamIn a bid to tackle intermittent generation profile of renewable power, MNRE is pushing through complex new schemes combining solar, storage, wind and conventional power. There is a growing sense that we will see fewer vanilla tenders in future. New schemes pose new technical and operational challenges for developers but also provide an exciting differentiation opportunity to them.

Manufacturing plans take off (or do they?)Pursuant to indicating strong support for domestic manufacturing, the government has claimed that up to 20 GW of integrated module manufacturing capacity is being established. However, concrete progress on basic customs duty and financial incentives is still awaited. We believe that fickle government support cannot provide foundation for a robust manufacturing capability.

All change in module technology and supplyNew module technologies finally hit home in 2020 with mono-PERC modules becoming default choice of developers. Bifacial modules are expected to become mainstream by next year end. Pace of technology change is accelerating as leading Chinese players innovate furiously and break further away from tier-2 and tier-3 suppliers. New enhancements promise to bring down costs and improve LCOE, but also present a difficult choice to IPPs due to limited proven track record.

Wall of money a mitigated blessingMigration of capital away from fossil fuels and all-time low interest rates have led to flooding of capital into the sector. While this means better support for secondary deals, intense bidding competition is forcing developers to bid aggressively resulting in unviable bids as seen in the recent SECI Rajasthan solar auction.

End of new coal in sightEven as central government sits on the fence, states and investors are migrating en masse away from coal. New coal capacity is now funded entirely by PSUs as both international and domestic investors focus exclusively on green energy and sustainability. We believe that new coal will become a rarity after 2024.

Government doubles down on mega renewable parksThe government mistakenly continues to focus on mega concentrated parks. Prime Minister Modi just inaugurated a 30 GW renewable park in Gujarat. But project development should get more dispersed as inter-state transmission waiver runs out in June 2023. Unless government reorients its plans accordingly, land and transmission are expected to remain key pain points for the sector.

Distributed renewables caged upRenewable power demand from C&I consumers is soaring but DISCOMs are suppressing demand with policy reversals and execution hurdles. Installation numbers have been coming down for both rooftop solar and open access renewables for the last two years. An incredible growth opportunity is going abegging.

To end on a good note, energy transition is well and truly under process in India. Several pitfalls remain but things can only get better in the new year.

We wish you all a merry Christmas and a very happy new year. Hope you have a restful break and we look forward to seeing you in 2021!

After staying relatively stable in the past year, module prices are on the decline again. Prices of multi-crystalline modules, still the de facto choice for most Indian developers, have fallen from USD 0.23/ W to USD 0.20/ W in the last six months. Cost delta between low efficiency modules and high efficiency mono-PERC has also halved to about USD 0.02/W. Alongside fall in module prices, inverter prices and balance of system (BOS) costs have been falling steadily too (see chart below). As a result, total EPC cost including safeguard duty of 20-25% on modules and 8.9% effective GST has fallen by 13% to INR 27.60/ Wp in the same period.

Module prices are falling steadily as supply is rising sharply but international demand remains stagnant;

Short-term cost outlook is positive with prices expected to reduce further through early 2020;

The industry needs to guard against risk of disruption in international trade policies, logistics or foreign exchange markets due to high dependence on equipment imports;

The module price fall owes mainly to continued demand slowdown in China. After touching a high of 53 GW in 2017, demand has been falling steadily with latest estimates for 2019 suggesting annual capacity addition at only about 25 GW. Demand has risen elsewhere, most notably in Europe, where solar capacity addition has doubled in the last two years to touch an estimated 20 GW this year. Aggregate global demand is believed to stay broadly flat at about 120 GW. In contrast, the module manufacturers have been expanding ferociously. Some of the latest numbers coming out of China, in particular, are mind boggling – Jinko, the industry leader by shipment volumes, expects to supply 20 GW modules next year, up from just 4.5 GW in 2015. LONGi is considering expanding its module manufacturing capacity from 9 GW in 2018 to 30 GW by 2021. Most other leading players including Canadian Solar, Trina, First Solar, JA and Risen are planning similar scale expansions. 

Figure: Total EPC and component cost trends

Source: BRIDGE TO INDIA researchNotes: Cost data is shown using Q1 2018 numbers as benchmark. For modules and inverters, we have used CIF price before any local tax or duty. Total EPC cost includes GST and safeguard duty as applicable. 

Outlook on the cost front remains positive. Prices are expected to reduce further through early 2020. Safeguard duty on modules and cells would also fall to 15% in January 2020 and be phased out completely by the end of July 2020. That alone would reduce EPC cost by 12%. 

Amid all the recent doom and gloom in the sector – PPA renegotiation, delayed payments, undersubscribed tenders, debt financing challenges – fall in capital costs provides welcome respite to the developers. It should help in improving financial returns and raising capital for the projects. However, over-dependence on China raises the risk of potential disruptions in international trade policies, logistics and foreign exchange markets.

Last week, a news report suggested that Madhya Pradesh DISCOMs have accumulated losses of INR 250 billion (USD 3.5 billion). The DISCOMs have requested the state regulator to allow increase in grid tariffs for recovery of losses. It is feared that average power tariff may have to rise by INR 2.00/ kWh or more as a result. The situation is similarly grim in Tamil Nadu, where aggregate DISCOM losses have touched INR 1 trillion (USD 14 billion) because tariffs have stayed flat for five years. The state government is not even allowing the DISCOM to present a tariff increase petition to the regulator. 

Tariffs have failed to keep up with rising costs across most states;

There seems to be rampant misreporting in financial numbers by DISCOMs with various errors reported by external observers;

While long-term reform is deliberated, meaningful tariff hikes can provide much needed relief to the DISCOMs and power producers;

Madhya Pradesh and Tamil Nadu are not isolated examples. Combined DISCOM losses increased by 89% in FY 2018-19 to INR 284 billion as tariffs have failed to keep up with rising costs. To make matters worse, the state governments and public sector consumers are falling further behind in making subsidy and power purchase payments respectively to the DISCOMs. At the same time, post UDAY, banks have cut lending lines to DISCOMs, who have been under pressure to supply 24×7 power throughout the country at subsidised tariffs.

This is a perilous position for the entire power sector and it is not a surprise that payment delays to power producers are rising alongside other insidious practices of curtailment and tariff renegotiation. Worryingly, actual picture may be even worse as there is a question mark about reliability of financial numbers put out by DISCOMs. Last year’s results have been already revised by several DISCOMs. A recent report by Prayas, an energy think-tank, on growing use of subsidies in power distribution contends that: i) subsidy amounts are often not (correctly) reported by the states even to Power Finance Corporation, a Government of India-owned financial institution and the only entity to undertake any kind of financial assessment of DISCOMs; and ii) there are significant discrepancies in detail, terminology and accuracy of subsidy information in various regulatory documents filed by the DISCOMs.

As the following chart shows, with the exception of Karnataka, grid tariffs have stayed broadly flat or even declined in most states over the last five years. 

Figure: Grid tariffs over last five years, INR/ kWh

Source: BRIDGE TO INDIA research, state tariff ordersNote: Figures shown represent energy charge only. Electricity duty, cess and other surcharges including fuel adjustment surcharge are excluded. 

The Ministry of Power has been talking up sector reform in recent months. Various ideas have been mooted including UDAY 2, revised National Tariff Policy and amendments to Electricity Act to make DISCOMs financially sustainable. But there is little actual progress. While these long-term measures are deliberated and implemented, the government needs to bite the bullet and effect meaningful tariff hikes across consumer categories to avoid the crisis spiralling out.

For RE, a substantive grid tariff hike would be beneficial in many ways. Besides reducing offtake risk, it would spur power demand from DISCOMs, and result in better prospects for open access and rooftop solar markets. 

In a major relief to the sector, MNRE has granted project completion deadline extension to wind projects allocated under SECI auction tranches 1-5. More time has been granted to these projects mainly because of delays in land allocation and completion of transmission infrastructure. A total capacity of 7,200 MW was allocated by SECI in these auctions between Feb-2017 and Sep-2018, but only 1,825 MW has been commissioned so far. 

Heavy concentration of projects in Gujarat has exacerbated land and transmission connectivity delays;

The developers face a multitude of other challenges on supply chain, debt financing and project clearance fronts;

Progress is likely to remain slow with total capacity addition estimate of only 9 GW over next three years;

Figure: Developers with pipeline projects in SECI wind auction tranches 1-5, MW

Source: BRIDGE TO INDIA researchNote: This chart excludes commissioned projects. 

Since February 2017, wind projects aggregating 12,265 MW have been allocated under auction route by various central and state government agencies. Based on the mandated completion deadline of 18 months, 5,000 MW of these projects should have been commissioned by now. But only 2,128 MW has been actually completed. The issue is mainly lack of suitable land at acceptable price. More than 75% of total tendered capacity is estimated to be coming up in Gujarat with most of the balance being located in Tamil Nadu. However, late last year, Gujarat refused to allocate state land for central government schemes. This left the developers in a bind – moving to other states was not viable due to low wind speeds and time constraints, and buying private land at 3-4x the cost of government land was simply unaffordable. Under persistent pressure from the central government and developers, the state is believed to be in the process of finally allocating land for the projects. 

The developers face yet more hurdles. All projects in Gujarat need approval from the Ministry of Defence, which can be time consuming. The turbine market has shrunk due to debt woes afflicting Suzlon and Senvion, and many of the smaller suppliers being squeezed out of the market. Lack of bankable turbine makers, willing and able to take large scale lump sum EPC contracts, is bound to affect execution timelines as well as cost. Layering debt financing challenges on top of these problems being faced by the sector currently means that there is a growing risk of some projects being abandoned altogether. 

After a bumper FY 2017, when 4,564 MW of new wind capacity was added, the sector has been in a slow, gut wrenching mode. Capacity addition in FY 2018 and FY 2019 stood at only 1,788 MW and 1,819 MW respectively. Our estimate for total capacity addition over next three years until the end of FY 2022 is around 9 GW. 

Last week, SECI conducted auction for a 1,200 MW utility scale solar tender. The tender received bids for full 1,200 MW but the auction was completed for only 960 MW, equivalent to 80% of the bids received, as per the rules in place. ReNew, Avaada and UPC Renewables won 300 MW each at a tariff of INR 2.71/ kWh; Tata Power won the remaining 60 MW at INR 2.72/ kWh. The developers are free to locate projects anywhere in the country and seek inter-state transmission system (ISTS) connectivity. 

Tariffs have finally started inching up but the increase is not commensurate with various operating and financial risks assumed by developers;

The uniquely open and transparent nature of renewable auctions has created an extremely competitive market;

In the rush to raise more money and build more capacity, most of the leading developers have failed to create any lasting competitive advantage;

The auction is unremarkable for all intents and purposes except that the tariffs have finally started inching up a little. These are the highest ever tariffs in a SECI or NTPC solar ISTS tender. However, the increase is only about INR 0.20 or 6-8% over average tariffs seen in the last two years. Indeed, the surprise is that tariffs have not increased faster in response to various cost increases as well as teething execution and financing hurdles faced by developers. 

How to explain continued investor interest and competitive dynamics in the sector? The answer lies primarily in the massively scaled up, fully transparent auction programme developed by the Indian government. It has (arguably) played a winning hand by creating a near level-playing field and reducing project bidding to a single point online game – tariff. In an already commoditized sector, there is no premium for developers to deploy advanced technology, deliver more reliable plants, reduce land or water requirement, or tailor power output profile to match demand curve. In the process, the government has managed to attract some of the world’s biggest strategic and financial investors including utilities, IPPs, business conglomerates, sovereign wealth funds, pension funds and PE funds. 

On their part, the investors have found lure of deploying huge chunks of capital in a sector with high growth prospects and green credentials too hard to resist. Many of the leading developers have simply followed the motto of ‘raise money, build more’ and struggled to create a lasting competitive advantage. Setting aside financing, it is almost impossible to identify any winning strategy or undertake any meaningful comparative analysis in the project development business. On the contrary, in the rush to raise money and build projects, many developers have cut corners on risk, project quality and long-term business planning. 

Lessons ought to have been learnt after all the problems faced over past two years. For sure, there is more risk aversion and return expectations have increased marginally as evident in the recent tender results. But unless the developers build a true competitive advantage (assuming that the government allows them to), they are likely to be chasing elusive returns in an overcrowded market.

MNRE has announced various changes to the competitive bidding guidelines for utility scale solar projects. There are broadly two categories of changes – to address offtake risk and improve execution timelines. 

On offtake risk, the government has proposed full compensation in the event of power back-down and bolstering of the payment security fund;

Measures to improve timelines include more time for land documentation, deemed tariff approval by the regulator in the event of delays and protection from government failure to issue project clearances;

The changes are highly welcome and seem to have come in response to growing concerns about poor risk profile of RE projects and falling investor interest;

Mitigation of offtake risk seems to be the biggest objective. First, in the event a solar plant is asked to back down, other than for grid security or safety reasons, the developers would be offered 100% compensation (previously 50%) for loss of power output. With growing instances of curtailment across many states, the provision of only 50% compensation was increasingly untenable. Heeding further the demands of project developers, the amendment also specifies that no backdown may be ordered without formal written instruction and that the details of such backdown need to be made public by the concerned Load Dispatch Centre. 

Second, there is a new provision for top-up tariff, whereby the ultimate offtakers are required to pay an extra INR 0.10/ kWh in case they are not able to provide state government guarantee to cover their PPA obligations. But this amount would be payable only to intermediary offtakers (for example, SECI or NTPC) for topping up the three month payment security fund maintained by them. It is a positive step but the amount is too small at about 3-4% of power tariff. The government ought to consider enhancing this amount as well as widening ambit of this clause to projects where there is no intermediary procurer.

Third, the developers are required to contribute INR 500,000 per MW of project capacity towards the payment security fund maintained by intermediary procurers. They would not be very pleased to cough up this amount as maintaining payment security should really be an obligation for the offtakers. The contribution would increase capital cost and raise tariff expectations by about 1%, both unwelcome in times of cash crunch. The amount is insubstantial though and would not be adequate to cover even one month of revenue shortfall. 

There is also an attempt to introduce more certainty on the project execution time-table. As land acquisition and subsequent documentation formalities have posed teething problems in many states, the developers are now given time until COD to complete these requirements as against only 12 months earlier. In response to another problem faced by many projects relating to delay in approval of project tariffs by the regulators, the amendment proposes deemed approval if the regulators fail to issue a decision within 60 days of application. 

The last material change in the guidelines is introduction of the concept of non-natural force majeure, in particular, failure of a government authority to provide any project clearances. If such an event persists for more than 6 months, the developers are entitled to terminate PPA and seek full termination compensation as under the offtaker default scenario. 

The changes are highly welcome and seem to have come in response to concerns about deteriorating risk profile of RE projects and falling investor interest. They are also consistent with the recent draft guidelines for solar-wind hybrid projects. But the move is largely reactionary and akin to a sticking plaster. To build new growth momentum, RE needs a new procurement model and some fresh thinking. MNRE guidelines are not binding on the DISCOMs in theory, but they would be compelled to accept these changes as investors get more demanding.

Indian developers have been rushing out to issue green bonds as liquidity in the Indian financial markets continues to stay stretched. An aggregate amount of USD 2.9 billion has been raised by Greenko (USD 1.3 billion), Adani (USD 862 million), ReNew (375) and Azure (350) in the last seven months. The spurt in issuance comes after a lull 2018 when no bonds were issued. Prior to that, a total of USD 2.5 billion worth of bonds were issued in 2016 and 2017. 

The bonds are being issued at a relatively unattractive cost of USD 5.65-6.67%;

The developers have no option other than to tap into green bonds to free up bank lines for their pipeline projects;

Because of worsening risk perception of Indian RE, the green bond option is available only to a very small group of developers with the necessary scale and reputation;

Most issuers have followed a template structure issuing bonds with bullet maturity of around 4-6 years. The bonds, rated sub-investment grade at about BB mark, have had to pay high coupon rates of between 5.65-6.67% per annum to attract investors. These rates are about 50-100 bp higher than respective rates two years ago. The one standout offering was made by Adani, which issued USD 362 million of 20-year bonds (average maturity of 13.3 years) against an operational portfolio of 570 MW of operational solar assets. These bonds follow a conventional project finance structure with: i) an annual redemption profile tailored to meet project cash flows; and ii) a tight security structure including several reserve accounts, cash waterfall mechanism, cash sweep and other covenants. As a result, the company managed to improve credit rating to investment grade BBB- and reduce cost to 4.625%, an all-time low for Indian RE developers.

Table: Green bonds issued by Indian RE project developers

Source: BRIDGE TO INDIA researchNote: Portfolio capacity includes only utility scale solar and wind projects except for Greenko. 

Overall, we do not deem terms, particularly the cost, of the bonds as attractive vis-à-vis INR term debt. But the developers are keen to free up bank lines for their pipeline projects as both availability and cost of debt have been impacted adversely in the local financial markets. Despite five interest rate cuts by the Indian central bank this year, the Indian lenders are weighed down by liquidity and asset quality concerns.

Green bonds should be an ideal option for the developers when interest rates in developed markets remain near all-time lows and debt investors are increasingly hungry for yield. Unfortunately, risk perception of Indian RE has taken a massive hit following recent instances of payment delays, contract renegotiation and curtailment. As such, this option is available only to a very small group of developers with the necessary scale and reputation.

A mini-controversy broke out last week with Indian credit rating and advisory company CRISIL issuing a report claiming that India would under-achieve the 175 GW renewable capacity target for March 2022 by 42%. MNRE immediately issued a prickly rebuttal terming the report as factually incorrect and lacking credibility. It has expressed confidence that capacity target of 175 GW would “…not only be met but exceeded.” But it later betrayed its own statement by extending timeline for meeting the target from March 2022 to December 2022. 

The sector is facing double whammy of severe supply side constraints as well as weakening power demand growth;

States with high RE penetration are already struggling to cope with associated financial and operational challenges;

The sector seems likely to muddle along at 8-10 GW annual capacity addition unless the government backs up its ambitious talk with urgent reforms;

CRISIL has put blame for undershooting the capacity target primarily on policy uncertainty and falling developer interest. Those are valid reasons but there are more important exogenous factors at play. The sector faces serious supply side challenges on land, transmission and debt financing. There is a huge pipeline of 31.3 GW of projects in various stages of construction but most projects are facing delays of 6-18 months because of various bottlenecks. We stated just last week that utility scale solar and wind capacity addition has averaged below 2,000 MW over last six quarters.  Moreover, power demand growth in the country is showing worrying signs of a slowdown. Total generation has slipped by about 5% in the last two months over previous year. Power prices on the exchange have fallen to a two-year low of INR 2.77/ kWh. Weak demand is being attributed variously to slowdown in the economy and extended monsoon.

Figure: Monthly power generation, million kWh

Source: CEA, BRIDGE TO INDIA research

The bottom line is that the sector is facing the double whammy of execution challenges as well as weak power demand. Andhra Pradesh and Telangana, two leading RE states have formally raised the issue of excess renewable capacity and their inability to pay for it. We believe that Karnataka is likely to be facing similar challenges with RE penetration already in excess of 30%.

In such a scenario, it seems difficult and even inadvisable to add more than 8-10 GW of renewable capacity on an annualised basis. In fact, we believe that CRISIL’s estimate of 40 GW incremental capacity addition by March 2022 is a tad optimistic. Including about 5 GW of rooftop solar capacity, we estimate new capacity addition at only about 35 GW in this period. The government may not like these estimates but it needs to acknowledge industry concerns and be open to critique.

We maintain that long-term fundamentals of renewable sector remain very strong in India. But revival of growth requires a multi-pronged approach including power distribution reform, adoption of new technologies like storage and, progressive measures on ancillary services market and demand side management.

Last week, Amplus Solar announced a foray into the residential rooftop solar market. The company, so far focused only on C&I consumers, plans to offer standard rooftop solar solutions backed by a long-term warranty and integrated financing solution.

Residential rooftop solar accounts for a tiny 16% share of the total rooftop market in India;

Long payback periods, lack of standard financing and technical solutions have held the market back but the outlook is beginning to improve;

Falling costs, improving supplier interest and favourable policy stance should see market growth outstripping other segments;

Unlike in most other countries, residential consumers account for a tiny 10% share of rooftop solar market in India. As of March 2019, total installed capacity in the residential segment is estimated at only 690 MW. Average annual installations are estimated at only about 187 MW per annum. The market is not only much smaller than the C&I rooftop market (1,500 MW per annum) but has also been growing erratically. Many factors explain this tepid state of affairs – long payback periods, high upfront cost, lack of standard financing as well as technical solutions backed by reputable vendors. These factors continue to hold the market back, but there are some encouraging signs of the market opening up.

Figure: Residential rooftop market growth

Source: BRIDGE TO INDIA research

We expect growth to pick up in the next 2-3 years on the back of improving project economics and supply eco-system, increased consumer awareness and favourable government policy. Payback period on investment can be as high as 10 years depending on consumer tariff and rooftop system cost but we expect it to fall to an average of less than five years by 2022 as grid tariffs rise in response to poor DISCOM finances and system costs fall. In any case, retail consumers have lower return expectations and are happy with overall returns of about 10% on their investment.

Improvement in supply side eco-system and consumer awareness may be other game changers. While the C&I market continues to grow rapidly, intense competition and low profitability is pushing players to look at newer opportunities. There seems to be growing interest in the residential market both from start-ups and corporate players. Even the financiers, disenchanted by high risk in the utility scale market, are beginning to explore this market. Moreover, as consumers see more rooftop installations on their office premises, local metro stations and schools, hospitals etc, rooftop solar is moving from a technical curiosity to a proven energy system. Once the early adopters move in, the network effect should take over.

Favourable government policy should also help. Capital subsidies have been withdrawn from all consumers bar residential consumers, who can still avail capital subsidies of 20-40% depending on system size. The Indian government has set aside INR 66 billion for capital subsidies for residential consumers over next three years. We expect DISCOMs to offer less resistance to net metering for residential consumers because of lower applicable grid tariffs.

States are jumping in. Gujarat recently announced a scheme to install 800,000 residential systems aggregating to 1,600 MW capacity by March 2022. Other states are likely to follow providing a major boost to the market.