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BRIDGE TO INDIA hosted a webinar on 28 July, 2021 to discuss various O&M related issues for solar projects in India. Panellists included Mr. Ashwini Kumar Patil (CEO, Tata Power Renewables), Mr. Idrish Khan (CTO, Solis), Mr. Sudhir Pathak (Head of Engineering – Hero Future Energies), Mr. Nalin Kumar Sharma (VP-Asia & Pacific, Ecoppia), Mr. Puneet Jaggi (Founder, Prescinto Technologies) and Mr. Aakash Trivedi (Senior General Manager, TUV SUD).

The discussion started with overall performance of solar projects. While most panellists agreed that projects are largely delivering satisfactory operational performance with power output ranging between P60-P90 profiles, Mr Trivedi from TUV SUD outlined that several projects continue to suffer from poor performance due to poor equipment selection and installation quality. It is also observed that high variation in solar radiation and adverse weather events such as cyclones and heavy rainfall have been posing a significant challenge in recent times. Mr. Pathak emphasised that operational performance is largely dependent upon design, engineering and selection of components at the construction stage.

On role of third-party contractors – market share is up from nominal levels five years back to about 40% – Mr. Jaggi believes that project developers have started seeing value in specialised services provided by O&M contractors. In contrast to the traditional self-O&M model, which continues to be followed by most large Indian developers, third party O&M has a higher cost particularly because of the extra GST component (18%). He also mentioned that there is still an issue of lack of trust from developers in third-party O&M contractors and a need to realign contractual structures to incentivise operators. As an example, he suggested that if the operator is able to improve PLF by 2-3%, part of this should be shared with it for a win-win proposition for both parties.

Figure: O&M market share for utility scale solar projects, March 2021

Source: BRIDGE TO INDIA research

On the cost front, Mr. Patil stated that most of the cost reduction owes to increase in average project size to 300 MW or more as against 10-120 MW five years ago. O&M service fee have fallen steeply from INR 450,000/ MWp to INR 160,000/ MWp in the last five years. The panellists agreed that with use of new technologies, there was still scope for cost to come down marginally. All panellists were very enthusiastic about role of new technologies in O&M activity. Mr. Khan mentioned that introduction of string inverters in large scale projects has significantly reduced time required for troubleshooting and done away with need for spare parts as string inverters can be replaced easily within a few hours. Mr. Sharma talked about the immense focus on robotic cleaning systems to maximise power output. There was long discussion on the pivotal role of data analysis, IOT, automation and digitisation to minimise risks and identify faults at an early stage.

Finally, in response to a question from the audience, Mr Patil noted that asset management service model is still at a very nascent stage in India. As more international developers enter the Indian market, this model may gradually pickup in future. For more insights on the topic, watch the full webinar recording here.

The Ministry of Power has extended completion deadline for inter-state transmission system (ISTS) charges waiver for solar and wind power projects by two years. The waiver would now be available to projects commissioned by 30 June 2025. The waiver has also been extended: i) in part to pumped hydro and battery storage projects commissioned by 30 June 2025 provided that minimum 70% of their power requirement is met from solar or wind plants; and ii) to power traded on green exchange until June 2023.

The ISTS waiver has been instrumental in allowing hinterland states with scarce land availability and/ or low natural resource to tap into more renewable power;

The waiver has led to heavy concentration of projects in Rajasthan and Gujarat exacerbating land, transmission and environmental bottlenecks;

Restriction of this benefit to storage projects to allow wider regional spread of capacity and incentivise storage market would have been ideal;

The extension would be applicable only for ISTS charges and not losses (ranging between 3-4%), which would need to be borne by DISCOMs from July 2023 onwards. Applicable waiver for pumped hydro and storage projects would be 75% in the first 5 years, 50% in years 6-8, 25% in years 9-11 before being phased out from year 12 onwards.

The ISTS waiver, mooted to reduce cost of renewable power for states with scarce land and/ or low wind or solar resource, has become a cornerstone of sector growth since 2018. This is the third extension for ISTS charge waiver, provided initially to projects commissioned by December 2019. As the following chart shows, ISTS projects have gained a critical share of tender activity. Between 2018-2020, 71% of total allocated capacity (62,967 MW) was awarded under the ISTS framework. To date, 31,086 MW of solar, 12,270 MW of wind and 5,435 MW of hybrid projects (total 48,791 MW) have been awarded under ISTS framework.

Figure: Growing share of ISTS-based solar and wind projects, MW

Source: BRIDGE TO INDIA research

Hinterland states including Haryana, Punjab, Delhi, Uttar Pradesh, Bihar, Jharkhand and Chhattisgarh have been the main beneficiaries. It is beyond doubt that the ISTS waiver has been instrumental in allowing these states to grow consumption of renewable power.

Figure: Project location and offtaker mix for ISTS projects, MW

Source: BRIDGE TO INDIA researchNote: Offtake data is available for only 21,609 MW capacity.

But as this chart also shows, the ISTS waiver has led to heavy concentration of project capacity in Rajasthan (solar) and Gujarat (wind) – inevitably exacerbating land acquisition, power transmission and environmental bottlenecks, and delaying project commissioning progress. As an example, out of 5,600 MW solar ISTS capacity awarded in 2018, only 1,350 MW has been commissioned to date.

Making ISTS waiver available to storage technologies and green exchanges is a self-evident move. Green exchange offers a promising avenue to DISCOMs looking to fulfil RPO requirements while the REC mechanism remains defunct. But at present, only competitively bid projects selling power to DISCOMs are eligible for ISTS waiver. Extending waiver to all power traded on the green exchange would discriminate against bilateral open access contracts and is an oversight in our view.

We believe that the ISTS waiver extension is not desirable. It would worsen execution challenges in Rajasthan and Gujarat. Moreover, as solar and wind are already the cheapest sources of power, such incentives are unnecessary. It would have been better if the extension were granted only to storage projects to allow better regional spread of capacity and reduce their effective cost, which has been a major barrier in adoption of this technology so far.

Interestingly, the order also states that waiver for pumped hydro, battery storage and green exchange would be reviewed periodically depending on “future development in the power market.” Multiple amendments and incremental extensions are reflective of ad hoc state of policy making partly in reaction to various challenges facing the sector. Lack of long-term policy consistency and visibility has become one of the biggest stumbling blocks in India’s renewable sector.

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.

As COVID pandemic rages across the country, MNRE has granted further time extension to projects under construction. The extension, not yet quantified because it is still too early to assess actual impact, would be applicable only to projects tendered by central government agencies with scheduled COD after 1 April 2021. But state government agencies are expected to follow suit.

COVID is not only delaying project execution but also curbing DISCOM appetite for renewable power;

Fall in investment potential risks undermining investor confidence;

Going forward, India would need to compete harder for attracting global capital;

As we assessed last year, COVID is not only delaying project execution but also suppressing power demand and curbing DISCOM appetite for renewable power. Even setting aside manufacturing-linked and storage tenders with relatively expensive power costing around INR 3.00/ kWh or more, there are about 6,000 MW of projects with unsigned PPAs adding to investor anxiety.

Capacity addition has now been slowing down for three straight years. India added only 2,725 MW of solar and wind capacity in Q1 2021, taking total installed renewable capacity to 94,443 MW by 31 March 2021. Our 2021 capacity addition estimate of 16 GW now looks distinctly unfeasible. We believe that the actual capacity addition may be only about 10 GW. Investments, taking into account falling costs, have fallen even more steeply. In 2020, total investment in the sector amounted to only about INR 241 billion (USD 3.3 billion, see chart), down 75% over 2017.

Figure: Annual capacity addition and estimated investment

Source: BRIDGE TO INDIA researchNote: Investment estimates exclude investments in solar parks, transmission and distribution network

The slowdown is consistent across the sector including utility scale, open access, rooftop solar, agricultural solar and manufacturing. But it would be wrong to blame everything on COVID. Age old issues including delays in land acquisition and transmission connectivity, poor DISCOM finances and policy uncertainty continue to derail ambitions. Many critical problems such as tariff renegotiations, curtailment, import duties, delays in ‘change in law’ approvals have been self-inflicted. Looking ahead, increase in module and other input costs, risk of anti-dumping duty and environmental challenges are only going to compound these woes further.

Fall in capacity addition and investment potential risks undoing the greatest success story of the Indian renewable sector. Leading international investors including energy utilities, oil & gas companies, sovereign wealth funds, pension funds and other developers have been drawn to India mainly because of the lure of its large market size. But they are feeling disenchanted and unwanted. In a country usually crying out for more capital, the situation paradoxically now is one of high investor appetite unmatched by weak demand for capital. Project developers find it easier to raise capital than to deploy capital leading to unhealthy competition and downward pressure on returns.

At a time when other countries are doubling their efforts to grow renewable sector, it is imperative for the Indian government to resolve the pressing problems urgently to avoid investor exits.

BRIDGE TO INDIA’s latest data compilation exercise for rooftop solar suggests that India installed 1,352 MW capacity in 2020, down 13.5% YOY. Total installed capacity is estimated to have reached 6,792 MW by December 2020. In a COVID-afflicted year with two months of severe lockdown, these are encouraging numbers.  

Residential market bucked the downward trend with growth of 100% over previous year;

The larger developers are becoming more conservative in face of weak credit outlook and policy uncertainty;

After declining for last two years, 2021 again looks like a challenging year due to COVID surge and strong DISCOM resistance to net metering;

Market activity seems to have picked up soon after lockdown ended in June 2020. Maharashtra was again the leading state with 147 MW of installed capacity in the year, nearly double the number for Karnataka, the runner up state. But notably, installations were down significantly in most large states including Maharashtra (down 44% YOY), Madhya Pradesh (63%), Rajasthan (58%), Andhra Pradesh (44%) and Tamil Nadu (36%). Karnataka and Uttar Pradesh bucked the trend with lower falls (16% and 26% respectively) while West Bengal, Chhattisgarh and many smaller states actually grew on an YOY basis.

Despite the highest financial savings potential from rooftop solar, C&I market volume was down 30% YOY. Residential segment provided hope with a heartening annual growth of 100%. MNRE’s residential rooftop solar subsidy scheme, with 16 states empanelling vendors so far, is making slow but steady progress with Gujarat and Kerala in the lead.

Figure: New installations by consumer segment, MW

Source: BRIDGE TO INDIA research

Share of OPEX model fell to 27%, down from 34% in 2019 and 36% in 2018. Discussions with industry players suggest strong continuing consumer preference for OPEX model. The slowdown seems a function of other factors including bigger developers adopting a more conservative stance on client rating, delays in PPA closures and push back against net metering in some states.

As usual, there was major churn in player rankings across the value chain. In project development category, Fourth Partner swapped places with Cleantech Solar to occupy top slot. Amplus retained third position, while ReNew and Tata Power moved up. In EPC category, Tata Power, Fourth Partner and Mahindra retained top three ranks but there were major changes further down. Meanwhile, in the inverter market, the Chinese quartet of Growatt, Solis, GoodWe and Sungrow consolidated their stranglehold over the market with over 75% share including OEM supplies.

2020 was the second successive year of market slowdown. Prospects for 2021 remain distinctly uncertain with COVID flaring across the country and mini-lockdowns currently in many states. Continuing DISCOM resistance to net metering and proposed levy of grid charges (Gujarat, Maharashtra and Karnataka) are also expected to slow down the market.

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.

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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.

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

BRIDGE TO INDIA’s latest webinar attempted to make sense of recent record low solar tariffs observed in SECI’s Rajasthan 1,070 MW and GUVNL’s 500 MW tenders. Panellists included Mr. Sanjay Varghese (President & Head – Solar, ReNew), Mr. Sanjay Kumar (Head BD & Proposals, Larsen & Toubro), Mr. Andrew Gilhooly (Head – Trina Pro, Trina solar – APAC), Mr. Lim Cheong Boon (Head – Product & Marketing, Trina solar – APAC), Mr. Honey Raza (Head – Sales, Ginlong Solis) and Ms. Zia Nariman (Senior Investment Officer, International Finance Corporation).

The discussion was kicked off by ReNew’s Sanjay Varghese, who attributed unprecedented low bids to a number of factors including market slowdown in the months leading up to the two auctions, influx of major capital in the market, falling cost of capital, aggressive bids by PSUs as well as optimistic assumptions – related to use of new technologies and equipment prices – made by some developers. He argued that offtake certainty and availability of transmission infrastructure also increased appetite in the two tenders.

Trina Solar’s Lim Cheong Boon noted that bifacial modules provide up to 25% additional power output with trackers and an overall 5-10% reduction in LCOE in comparison with monofacial modules. Boon also highlighted other benefits of larger and more efficient modules leading to faster installation times and savings in BOS costs. Meanwhile, Andrew Gilhooly acknowledged that trackers have not been historically popular in India but “things have started to pivot rapidly now.” As per him, intelligent tracker algorithms help maximise power output yield particularly for bifacial modules across different terrain and soil types. Solis’ Honey Raza also pointed towards multiple changes in inverter technology with rapid innovations and optimisation for new module sizes and bifacial products. According to Raza, these innovations have led to improved reliability, reduced equipment failure, operational and logistical issues, labour costs etc. String inverters already occupy about 60% market share, which seems set to rise in the near future.

Notwithstanding various technology advancements, most panellists also emphasised high risk arising from soaring equipment prices, steel and aluminium prices, freight rates etc. L&T’s Sanjay Kumar said that in the past, faced with unviable projects, developers have tended to put pressure on suppliers and contractors, and compromised on project quality in the process. But there was also a sense that with the industry gaining more experience and increasing presence of credible players, there is an increased awareness in the sector for superior operational performance and higher longevity of assets.  

IFC’s Zia Nariman commented that financing terms have been softening over the past few years. Interest rates have fallen to 8.5-9.0% for greenfield projects in comparison to over 11.0% just over two years earlier. Refinancing in operational phase can further bring down cost by another 50 bp or more. IFC is currently looking at sanctioning funds for projects with tariffs ranging between INR 2.37 and 2.43/ kWh. She expressed confidence that as IFC works with the most experienced and credible developers, their clients would able to absorb any project specific risks as part of their overall portfolios.

Overall, the panel maintained that bids in these tenders were unexpectedly aggressive and below optimal levels by about 10-12%. Given the rapid fall in costs, falling tariffs are entirely natural but the pace of decline is expected to fall in future. For more insights on the topic, watch the full webinar recording here.

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.

BRIDGE TO INDIA hosted a webinar on January 28, 2021 to discuss solar module technology landscape. The panel included Ms. Chris Liu (Technical Head, LONGi), Mr. Ivan Saha (Chief Technology Officer, ReNew), Dr. Nikhil Agrawal (AGM Technology, Mahindra Susten) and Mr. Sai Charan Kuppili (Technical Director, Jinko).

Module technology is undergoing significant changes with more efficient cell technologies such as N- and P- type mono, Topcon and heterojunction besides bigger wafer and module sizes as well us use of bifacial modules. Adoption in the Indian market, traditionally a laggard in using new technologies, is also accelerating. According to the panellists, the market has almost entirely transitioned to mono-PERC modules this year particularly because multi-crystalline modules are being phased out in China. Use of bifacial technology, backed by successful pilots by the larger developers, is also on the rise.

Ms Liu mentioned that bifacial technology has been making rapid advances because of its higher output and its use would become very common over next 1-2 years. But a 100% transition to bifacial modules is not likely. She believes that this technology would be selected by developers based on project specific considerations including location and ground conditions (soil texture, moisture content and albedo).

Mr Saha added that the company has already been running small-scale pilots with different module technologies to gain first-hand experience of different module types. The other panellists agreed that new technologies are accepted more readily in India now but delay in BIS approvals continues to be a challenge. However, that might not necessarily be a bad thing as per Dr. Agrawal, who explained that extra time provides a useful opportunity to developers and contractors to analyse various performance parameters and gain valuable knowledge about new technologies.

According to Jinko’s Sai Charan Kuppili, levellised cost of electricity (LCOE) trumps all other considerations when project developers make module purchase decisions. He mentioned that bifacial modules yield output gains of minimum 7% without trackers and up to 14% with trackers.

Because of tight polysilicon supply and shortages of other raw materials like glass, module prices have been volatile in the past few months. Though the supply constraints are gradually easing, the module manufacturers expect prices to remain firm over the next two-three quarters.

You can view the webinar here.

BRIDGE TO INDIA hosted a webinar on January 28, 2021 to discuss solar module technology landscape. The panel included Ms. Chris Liu (Technical Head, LONGi), Mr. Ivan Saha (Chief Technology Officer, ReNew), Dr. Nikhil Agrawal (AGM Technology, Mahindra Susten) and Mr. Sai Charan Kuppili (Technical Director, Jinko).

Best wishes for a very good new year to all our subscribers! Everyone is hoping to put 2020 behind them, the year that caused even more pain than 2019. Here, we look at key expected developments and pivotal events in the new year. Caveat: we assume, as widely expected, no further COVID shocks and a sharp economic recovery. Power demand to bounce back Based on various market estimates for GDP growth, we estimate power demand to grow by around 5-6% over last year. The demand uptick, together with steady improvement in RPO compliance, would create more demand for renewables and force DISCOMs to speed up procurement.

Record capacity addition We estimate total solar and wind capacity addition at about 16 GW, an all-time record high. Expected split between utility scale solar, distributed solar and wind is 11.0:2.5:2.5 respectively.

Figure: Renewable power capacity addition

Source: BRIDGE TO INDIA research Note: Distributed solar includes rooftop solar, solar pumps and off-grid solar

Basic customs duty (BCD) imminentFinal announcement on BCD is imminent possibly coming as part of the budget on 1 February 2021. Our understanding is that there would be a time-adjusted structure ramping up over 3-4 years with lower duties for cells and higher duties on modules. Assuming that the duty level increases by 10% every year for 3-4 years, the duty would negate benefit of any fall in module prices.

Manufacturing to remain in slow laneDomestic module manufacturing plans are stuck, awaiting progress on the 12 GW manufacturing tender (DISCOMs are refusing to accept tariff of INR 2.92), BCD, and the recently announced production-linked incentives (PLI) scheme. We believe that the resolution of the manufacturing tender would take a long time given the intractable issues posed by potential renegotiation and blending of power from other tenders. Similarly, we expect a bidding process for allocation of PLI by MNRE, which would drag out the timetable even further.

Significant fall in module pricesGlobal demand for modules is expected to jump to 145-150 GW this year, up about 25% over 2020. However, cell and module production capacity are increasing at an even faster rate touching a staggering 350 GW by end of the year. The massive overcapacity should result in prices falling steadily through the year, down about 12% over 2020 closing price of USD cents 0.21 per Watt.

TariffsIf BCD is announced shortly, auction tariffs would likely stay north of the recent lows for some time.

ISTS waiver extension odds at less than 50%ISTS waiver is currently available to projects completed by June 2023 and while, it has been extended two times in the past, another extension seems unlikely. Lack of an extension would mean that projects auctioned from around July 2021 onwards would start incurring ISTS charges leading to a shift back to state specific auctions (and consequential increase in tariffs by up to INR 0.75). The change would have critical implications for tender design and, land and transmission availability across the country.

Andhra Pradesh renegotiation It has been a remarkable 18 months since Andhra Pradesh initiated the exercise to renegotiate and/ or terminate all renewable PPAs. A resolution has been pending in Andhra Pradesh High Court, but some developers have requested intervention from the Supreme Court. We expect final resolution, already delayed inordinately, to come sometime during the year.

Key events to look out for in the year:

Financial condition of DISCOMs and progress on the INR 1.2 trillion liquidity package

Power sector reforms

Final legal resolution of Andhra Pradesh PPA renegotiation exercise

Bidding guidelines for the PLI scheme

Auction for the 2,500 MW renewable-conventional hybrid tender

New unified bidding guidelines for solar, wind and hybrid projects

There is no doubt that the new year would turn out to be better than the last year. Record levels of capacity addition should soothe nerves of investors and supply chains. But the most critical step ahead is finding a permanent resolution to chronic financial troubles of DISCOMs. Delay in reform of the distribution business poses a fundamental risk to the entire power sector.

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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.

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

BRIDGE TO INDIA hosted a webinar on Thursday, 3 December 2020 to discuss rooftop solar policy status at national and state levels. Participants included Mr. Chintan Shah (Director Technical, IREDA), Mr. Arijit Mitra (Head of Distributed Generation, LONGi Solar), Mr. Pramod Kalyanshetti (CCO, Mahindra Susten), Dr. Anuvrat Joshi (Head BD India, Cleantech Solar) and Mr. Damian Miller (CEO, Orb Energy).

Most of the discussion revolved around regressive changes in net-metering policy across many states. States have been gradually withdrawing net-metering from C&I consumers and/ or scaling back banking benefits. For example, Uttar Pradesh disallowed net-metering for C&I consumers and Karnataka revoked net-metering for OPEX model recently. As a result, rooftop solar market has been stagnant or even declining since 2018 despite being one of the cheapest sources of power at the point of consumption. Capacity addition in 2020 is estimated at only 990 MW, down 35% over previous year.

Figure: Indian rooftop solar policy landscape

Source: BRIDGE TO INDIA research

All the panellists agreed that policy inconsistency and instability have hurt market prospects. Mr. Joshi mentioned that “overnight U-turns” by state regulators have been troublesome and good intentions for policy change have not been followed up with actions on ground. Another panellist added that it is challenging even to track frequent policy changes across states. The developers agreed that Gujarat, Karnataka and Tamil Nadu have been more challenging states for C&I consumers. However, states like Maharashtra and Kerala provide a useful policy template for other states to follow.

Financing rooftop solar systems has been a persistent bottleneck for the sector. Mr. Shah from IREDA offered a major piece of positive news. MNRE has been working with IREDA to arrange lines of credit aggregating USD 100-125 million from development banks particularly for residential and SME consumers. Depending on market response, the lines could be scaled up to USD 500 million or more in future. As lack of a nationwide branch network has restricted IREDA’s presence in the market (financed only 40 MW of rooftop solar projects so far), they are aiming to channel this financing to system aggregators and other lenders with stronger distribution network.

There was also a brief discussion on impact arising out of BCD imposition, which could be a setback for the market. The government has announced plans to impose the duty from April 2022. A potential 40% duty on modules would raise cost of rooftop solar power by 20-25%. But most developers seem relatively optimistic and feel confident that the market would be able to manage any downside impact with the benefit of learnings from safeguard duty imposition. Change in law provisions have become quite standard in contracts and are well accepted by both consumers and suppliers. Moreover, the panellists opined that even after the proposed duty, rooftop solar would continue to be highly cost beneficial to consumers. Mr. Arijit from LONGi argued that the government should first empower domestic supply chain and only then seek to introduce such duties.

Overall, there is a major disconnect between rooftop solar targets and policy environment. The sector needs a consistent and uniform policy framework to achieve its potential.

The Telangana State Electricity Regulatory Commission (TSERC) recently released final regulations for demand-side management (DSM). The initiative is designed to encourage and incentivise consumers to alter their power consumption pattern, both in terms of level and timing of demand. State DISCOMs are required to establish DSM cells and undertake load research and develop baseline data for assessing DSM potential. They are also required to formulate annual DSM plans, which would be used by TSERC to establish targets for load reduction and cost savings.

Demand response programmes can reduce power procurement costs, and ultimately consumer tariffs, by shaving peak requirement;

Based on various studies around the world, a reduction of 2-4% in peak load may be possible in India;

Policy solutions such as demand response are extremely cost and time effective, and can play a vital role in increasing renewable power penetration in the grid;

Maharashtra notified the first-ever DSM regulations in India in 2010. In total, 18 states have now notified DSM regulations including major power consuming states such as Punjab, Haryana, Delhi, Uttar Pradesh, Gujarat, Karnataka and Tamil Nadu.

DSM entails primarily two different kinds of programmes – energy efficiency and demand response. Energy efficiency programmes are relatively easier to implement, and offer direct and larger benefit. By comparison, demand response programmes, require more intricate knowledge of consumer behaviour and demand patterns. The objective is to decrease customer demand during times of high system demand or emergencies by offering them a rebate or lower energy costs.

There are many potential benefits of DSM. Lower power demand has obvious direct financial and environmental benefits. Demand response programmes can further reduce power procurement costs, and ultimately consumer tariffs, by shaving peak requirement, which is typically much more expensive than off-peak power. A US study shows that utilities were able to reduce their peak demand by around 2%. In India, many DISCOMs have completed pilot studies with encouraging results. A Tata Power Delhi study in 2015 showed potential demand response opportunity in India of between 4-8 GW.

Figure: Peak demand reduction from demand response measures in the USA, % of peak demand

Source: US Energy Information Administration, Annual Electric Power Industry Report 2017

As seen in the chart below, Indian power demand typically peaks in late evenings (when solar power is not available) and power prices tend to spike up as seen in the chart below. Reduction of peak load therefore can have substantial financial benefits.

Figure: Total power demand in Uttar Pradesh and traded power prices on 30 April 2019

Source: Uttar Pradesh SLDC, Indian Energy Exchange

Other benefits of demand response include improvement in grid resilience and stability besides possible deferral of expensive generation, T&D system upgrades. These benefits are particularly desirable in increasing share of renewable power in the grid and alleviating dependence on fossil fuels.

Unfortunately, progress has been patchy on the implementation front. Demand response still remains a relatively new concept in India. Pilot initiatives have not been scaled up due to lack of awareness, resources and skills at the DISCOM level. This is a shame because India will urgently need to ramp up efforts to absorb more renewable capacity in the grid as substantial new capacity comes online in the next few years. Policy solutions such as demand response, time of day tariffs and ancillary services are extremely cost and time effective, and should be prioritised over expensive T&D system upgrades.  

It has been a little over three months since renewable power trading commenced on Indian Energy Exchange. Trading has been active for solar and non-solar renewable power separately under two different contracts – intra-day, for delivery within 3.5 hours, and day-ahead, for delivery next day. Longer-term contracts – daily, for delivery between 2-10 days ahead, and weekly, for delivery from Monday to Sunday – commenced only this week.

Trading volume has stayed low at about 2,000 MW daily, about 2.5% of total renewable power output;

Buyers are unprepared to pay a huge premium over conventional power restricting sales appetite of DISCOMs with surplus contracted power;

Trading should pick up by gradually as significant new generation capacity comes online in the next year;

There are some clear trends visible from a look at the trading data so far. As expected, trading volume has stayed low at about 2,000 MW daily, about 2.5% of total renewable power output, or just 3% of total power traded during the same period and 35% of RECs traded during the same period last year. Solar power has enjoyed majority share (88%) in the traded volume because of greater predictability. Average price for solar and non-solar power was INR 3.47/ kWh and INR 3.77/ kWh respectively, significantly higher than conventional power traded price of INR 2.72/ kWh.

Buying interest has exceeded selling interest by a factor of more than 3x, coming in mainly from renewable power deficit DISCOMs. Top four buyers include DISCOMs in Haryana (28%), Kolkata (CESC, 20%), Mumbai (Tata Power, 10%) and Delhi (BSES Rajdhani, 7%) together accounting for two-third of total volume. Large corporate consumers like Vedanta, Dalmia Cement, Jindal Steel and Tata Steel have also been active trying to meet their RPO requirements. The real surprise is that on the seller side, Telangana has accounted for 73% of traded volume with Karnataka (9%) being the only other DISCOM to have sold power. Smaller IPPs had a share of around 15% in the traded volume.

Figure: Renewable power traded volume and price

Source: Indian Energy Exchange

Selling interest is low both because of lack of merchant capacity and low prices. IPPs do not have any untied capacity. Main selling interest is therefore coming from DISCOMs with excess supply of power but in most cases, average cost of their contracted power is in excess of INR 4.50/ kWh and presumably, they are not prepared to sell at a loss. Onerous forecasting and scheduling requirements are also inhibiting volume growth. No schedule revision is allowed under intra-day and day-ahead contracts. Revisions are allowed for daily and weekly contracts but with at least two days advance notice.

Exchange trading of renewable power is a positive development but volumes are expected to stay low. Next year could see a marginal improvement as power demand revives and significant new generation capacity comes online.

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

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.

On 23 November 2020, SECI conducted an auction for a 1,070 MW vanilla solar tender where a new tariff low of INR 2.00 (USD cents 2.7)/ kWh was discovered. The low tariff was bid by Saudi Arabia’s Aljomiah (200 MW), a new market entrant, and Sembcorp (400 MW). NTPC was the other successful bidder, winning 470 MW capacity, with a tariff of INR 2.01/ kWh. The tender was oversubscribed heavily with bids totalling 4,350 MW submitted by Sprng, SJVN, Solar Arise, Vector Green, Tata Power, Juniper, Axis Energy, Ayana, Jakson, Amp Energy and O2 besides the three successful bidders.

Bidding interest for vanilla solar projects is very high as many small-mid size developers who have recently raised money are not keen on complex hybrid schemes;

Tariffs have fallen sharply only because of anxiety of the winning bidders to scale up;

The low tariffs will distort expectations of other DISCOMs and increase risk of cancellation or renegotiation of projects with tariffs higher than INR 2.50/ kWh;

As seen in the last two SECI solar auctions, bid intensity has suddenly shot up over the last few months. A look at the names of participating bidders shows that the tender received interest mainly from small-mid size developers (other than the exception of Tata Power and NTPC). Most of these developers have either recently raised money and/ or are in advanced stages of completing construction of their pipeline projects and hence, are keen to win more capacity. The developer interest was also particularly strong in this tender because of firmed up offtake (from Rajasthan) and straight forward execution for vanilla solar projects in Rajasthan. The developers are concerned both about weak power demand – SECI has nearly 18,000 MW of allocated projects without back-to-back demand from DISCOMs – and execution challenges associated with complex hybrid schemes.

Solar power tariff has fallen by 15% in five months. There is no good reason for such a sharp fall other than anxiety of the winning bidders to scale up. Projects under this tender will be connected to state grid with risk of higher downtime and curtailment in comparison to projects connected to the national grid. Module prices have been volatile, firming up over last four months, and betting on significant fall within the execution timeline is dangerous. The only mitigation in comparison to other projects being developed in Rajasthan is that power would be consumed within the state; the state development fund charge of INR 200,000/ MW per annum – equivalent to about INR 0.14/ kWh in tariff terms – will therefore not be applicable.

Our financial calculations show project level equity IRR of sub-10%, deep water territory. The following chart shows interesting bid price differential for different developers. We believe that the prudent tariff for the tender was in the INR 2.25-2.40 range.

Figure: Bid capacities and tariffs

Source: BRIDGE TO INDIA research

The implications of the unrealistically low tariff are not palatable both for the winners in this tender and for winners of other recent tenders. It distorts expectations of DISCOMs and increases risk of cancellation or renegotiation of projects with tariffs higher than INR 2.50/ kWh.

The Ministry of Power has amended competitive bidding guidelines for procuring ‘round-the-clock’ (RTC) power by blending renewable power with power from other sources. Minimum share of renewable power remains at 51%. Main change pertains to relaxation in source of other power – bidders are free to procure non-renewable power from any source as against being restricted to only coal-fired power. There is also no longer any restriction for renewable and non-renewable plants to be in the same Regional Load Desptach Centre (RLDC) area. However, the bidders are required to specify only one non-renewable source together with share of non-renewable power as well as generating stations with uncontracted capacity upfront.

Despite relaxation in power sourcing, thermal power seems like the obvious choice for blending with renewable power;

Steep increase in penalties and requirement to match L1 tariff would be major source of irritation for developers;

DISCOMs would be better served by procuring renewable and non-renewable power separately on their own;

There is no change in the minimum CUF or availability requirement of 85% annually as well as for four peak hours every day (as specified by the respective RLDC). But penalty for not fulfilling these requirements or providing specified renewable power output every year has been increased steeply from 25% to 400% of applicable tariff for the respective shortfall.

Projects up to 1,000 MW are required to achieve financial closure and COD within 18 and 24 months respectively (24 and 30 months respectively for projects greater than 1,000 MW). Bidders will be required to submit a four-part tariff bid – tariff for renewable power, fixed charges and variable charges for fuel and transportation costs for non-renewable power. Surprisingly, there is no separate component for non-renewable O&M costs. Projects would be allocated on the basis of weighted average levellised tariff, computed as per CERC guidelines. Winning bidders are required to match L1 tariff, which would be a source of irritation for the developers.

Overall, the changes are largely positive for developers. Despite relaxation in source of non-renewable power, thermal power would be the obvious choice both for availability of spare capacity and cost competitive reasons. Unfortunately, the scheme remains beyond scope of pure play renewable IPPs. Renewable power alone with storage would not be able to compete with conventional power. And a tie-up with an external entity is implausible as no developer would be able to assume third party risk over 25 years. That leaves only a handful of IPPs straddling both renewable and thermal power sectors – mainly NTPC, Adani, JSW and Sembcorp – potentially interested in the scheme.

From a DISCOM perspective, getting round-the-clock power with specified share of peak power and renewable power is desirable. But we maintain that they would be better off in procuring renewable and non-renewable power separately on their own. It is not clear why they need developers to supply blended power through a highly restrictive tender process.

SECI has already issued a 5,000 MW RTC tender. Bid submission date has been repeatedly extended due to various changes sought by developers. Revised guidelines should allow the tender to finally go ahead. Another extension is expected for incorporation of revised guidelines. Small number of potential bidders means that the tender is unlikely to attract competitive bids.