Category: Solar

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

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

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

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

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

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

Figure 2: Domestic coal production, imports and international prices

Source: CEA

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Source: PV Infolink, BRIDGE TO INDIA research

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

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

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

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

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

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

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

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

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

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

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

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

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

Figure 1: Virtual power plants configuration and benefits

Source: BRIDGE TO INDIA research

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

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

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

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

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

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

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

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

Figure: Selection criteria for PLI

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

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

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

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

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

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

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

Table: Presence of PSUs in renewable sector

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Source: BRIDGE TO INDIA research

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

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

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

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.

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.

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.