Category: Market Outlook

The Ministry of Power is proposing to gradually move away from long-term PPAs and introduce medium and short-term contracts in the market. A committee has been set up to examine feasibility of changes in PPA tenure and relevant changes in payment security mechanism and other contractual provisions.

Greenfield power procurement is still enmeshed in 25-year PPAs, a relic of the command economy days, when resources were scarce and power sector was heavily licenced. But the conventional long-term PPA approach is no longer fit-for-purpose and the DISCOMs have been voting with their feet. In the last six years, only one 25-year PPA has been signed for a thermal power project (1.3 GW by Adani in Madhya Pradesh in 2020). In contrast, short-term transactions continue to increase to account for 13% share in total electricity generation, up from 11% in 2018. Volumes on the short-term DEEP mechanism also continue to rise – DISCOMs have procured about 67 GW capacity in 2021 so far, most of it in PPAs ranging between 1-30 days.

There are multiple reasons for DISCOMs to shy away from long-term PPAs. After growing steadily at 4-6% per annum up to about FY 2019, power demand has stagnated. DISCOMs are jittery about burden of unnecessary fixed payments having already committed to capacities higher than actual demand. In a study covering 12 states for FY 2020, the Forum of Regulators estimated surplus fixed charges bill at INR 174 billion (USD 2.3 billion).

Figure: Projected and actual power demand, billion kWh

Source: CEA

Other reasons for DISCOMs to lose interest in long-term PPAs include rapid technology changes, steep fall in cost of renewable power, growing consumer preference for self-generation and decarbonisation push. DISCOMs rightly need greater flexibility in procurement decisions. We believe that the government should go one step further and alongside pushing for shorter PPAs, it should endeavour to create more liquidity and depth in the exchanges. Some suggestions include expediting implementation of MBED and ancillary services reforms, launch of new market instruments and derivative contracts, signing PPA for only say, 70% of project capacity, no PPA extensions and reducing PPA tenor over time to 5-10 years.

Replacement of non-transparent, bilateral PPA regime with open exchange-based market could have a transformational impact on the sector. Market forces would enable more efficient decision making for new investments, technology and business models.  One often cited hindrance to a market-oriented structure is hesitation of lenders and regulators to assume market risk. At present, the regulators set tight annual limits for DISCOMs to buy power in the short-term markets – only 0.4% of total power requirement in the case of MSEDCL, the largest DISCOM in the country – adding to the financial burden on DISCOMs. But assurance of long-term PPAs is a fallacy and the power sector is littered with a series of defaults emanating from stranded capacity, payment disputes, litigation and PPA renegotiations. Power projects can be financed on the basis of market principles, just like other expensive infrastructure including roads and ports.

Most developed countries have already moved away from long-term contracts. The government is, however, right to be cautious about such significant reforms. Progress needs to be calibrated carefully to address concerns of all stakeholders. And DISCOMs would need to accept higher power prices if they want reduced demand and technology risks. 

This video presents a summary of major sector developments including tender issuance, auctions, policy and regulatory developments, financial deals and related market trends in August 2021.

The GST Council, an inter-governmental decision-making body headed by India’s Finance Minister, has recommended an increase in levy of GST (Goods and Services Tax) on all renewable energy “devices and parts” from 5% to 12%. The increase is expected to be ratified by the Union Cabinet shortly and become applicable from 1 October 2021. It is part of various changes proposed by the GST Council in an attempt to rationalise rate structure and bolster revenues.

The proposed revision would increase solar project capital cost by 4.5% and power tariffs by about 4%;

The decision runs afoul of push to scale up renewable power capacity amidst a multitude of challenges facing the sector;

There is need for continued financial support for the sector until cost of storage technologies falls by another 30-50%;

The concessional rate of 5% for renewable energy products was introduced in 2018 to support the sector. The proposed 12% rate is still lower than the normal 18% rate applicable on most items of daily use. But it is likely that the 12% and 18% slabs would be merged in near future to further streamline the GST regime at an intermediate rate (say, 15%).

Solar projects are currently subject to a blended GST rate of 8.9% – 5% tax on 70% of project value (notional contribution of goods) and 18% tax on the remaining 30% value. With the proposed revision, the blended rate would go up to 13.8%, effectively increasing capital cost by 4.5%. After the proposed 40% basic customs duty kicks in from April 2022, the combined effective tax and duty rate on solar modules would be an astonishing 72.48%. Meanwhile, industry rumours suggest that an anti-dumping duty could be imposed on solar cells and modules as soon as next month. The Ministry of Commerce has completed its trade investigation and a hearing is scheduled for 5 October 2021.

The argument that renewables are already the cheapest source of power – and more taxes would not dent their competitiveness vis-à-vis other sources – is hollow. Renewables should be compared with other despatchable sources after factoring in all necessary grid balancing and system costs on a like-for-like basis. That analysis still yields an ambiguous result making a strong case for continued financial support for renewable power until cost of storage technologies falls by another 30-50%. Besides, high taxes and duties are no way to support a priority sector with few other options. The decision to hike GST rate runs afoul of push to scale up renewable power capacity amidst all the other challenges facing the sector.

Abrupt tax changes also add to pervading unease in the sector beside creating a cascading set of issues across the value chain. In theory, utility scale projects are protected by ‘Change in Law’ provisions but the compensation process is arduous and not sufficiently restitutive. DISCOMs would get even more reluctant to purchase renewable power. It is worth noting that several compensation disputes pertaining to the original 5% GST levy in 2018 are still ongoing. Distributed renewable market – both rooftop solar and open access – would be hit harder as vendors renegotiate contracts and consumers assess implications for project viability.

There is no doubt that COVID has caused tremendous strain on government finances and there are more pressing priorities relating to healthcare, food and jobs. Indeed, the central government is having to borrow money to offer compensation to states for GST shortfall. Unfortunately, GST hike on renewable equipment, worth incremental annual revenue of only about INR 20 billion (USD 270 million, less than 0.1% of total tax revenue), is unlikely to solve that problem.

In the last three months, five Indian developers have raised a total of USD 1.7 billion through green bonds. Adani Green raised USD 750 million priced at 4.30% with maturity of three years. Acme completed its first issuance with USD 334 million of bonds priced at 4.7% for a five-year maturity. Azure raised USD 414 million, 5-year money at only 3.58%, the lowest rate by an Indian developer. The company will use the monies to refinance green bonds issued in 2017 at a cost of 5.50%. One of the pioneering issues came from Vector Green, who raised USD 166 million in the Indian market at a cost of only 6.40% for three-year bonds.

Hunt for yield by international institutional investors is helping the renewable sector;

Domestic term debt market has also turned benign;

Developers should brace for more challenging financing environment as liquidity starts tightening post COVID;

International institutional investor interest in the sector has soared due to lax monetary regime worldwide and shift towards ESG themed issuers. Investors are hunting for yield as rates in developed countries stay unattractive (German 10-year government yields at -0.28%, USA 1.14%, UK 0.85%). Recent issues have been oversubscribed by up to five times and rates have fallen from about 6.50% three years ago to the recent low of 3.57%.

Total green bond issuance in last 12 months is estimated at USD 4.3 billion, up by 168% over the previous year. Leading developers such as Greenko (total issuance USD 2.8 billion), ReNew (USD 2.6 billion), Adani (USD 1.6 billion) and Azure (USD 850 million) have benefitted immensely from favourable capital market conditions.

Even the domestic term debt market has turned benign. Despite a small number of active lenders, cost of greenfield project financing has fallen to around 9.00-9.25% from about 10.5-11.00% about two years ago. Operational projects with satisfactory track record and strong offtake are able to refinance at about 8.00-8.50%. Government-owned Power Finance Corporation (PFC) continues to dominate greenfield project finance. Other government institutions (IREDA, REC) and some commercial banks including SBI, Axis and HDFC are also active albeit at a smaller scale. Private NBFCs like L&T Infra Finance, Tata Cleantech and PTC Financial Services have become marginal players because of higher cost of funds, high risk aversion and small appetite.

Easy liquidity in the financial markets has provided welcome relief for the sector struggling with aggressive tariffs, rising module and other costs etc. Developers are making aggressive assumptions on financing to make case for lower tariffs in auctions – leverage of 80% or even higher, debt maturity of 20-22 years, cost of around 8.00%. But things have probably got as good as they possibly could, and there are risks ahead. Any tightening of monetary policy, as economies rebound from COVID, would have almost immediate adverse effect on appetite and rates for Indian renewable projects. Similarly, a pick up in commissioning activity and increasing demand for capital are bound to make financing more challenging in the coming years.

Since January 2021, Maharashtra has issued five renewable power tenders with total capacity of 3.3 GW. In the same time, Gujarat has issued seven tenders with total capacity of 1.7 GW. The two states account for a combined 31% share of total tender issuance so far this year. A comparison of renewable power penetration data for 12-month period to June 2021 across states throws some interesting results. Karnataka has the highest penetration at 33%. Andhra Pradesh (23%), Tamil Nadu (21%), Rajasthan (19%) and Gujarat (16%) are the other leading states with penetration significantly higher than the national average of 10.8%. These five states have also met or exceeded their RPO targets. Amongst other larger states, Telangana (10%), Madhya Pradesh (10%) and Maharashtra (9%) are in the middle, while Punjab (5%), Uttar Pradesh (4.7%), West Bengal (3%) and Haryana (1.4%) are the laggards.

Figure: Renewable power penetration and RPO targets in key states, %

Source: CEA, BRIDGE TO INDIA research

Future growth of renewable power in each state is contingent upon three main factors: absolute power demand growth, renewable power penetration and financial ability of DISCOMs. The leading states, other than the exception of Gujarat, are likely to register low-modest growth over next five years. Their DISCOMs are financially weak and there is some evidence that they are struggling to absorb more intermittent power.

Gujarat and Maharashtra are two obvious bright spots. Both states are the hub of industrial activity, accounting for a total 23% share of national power consumption. They are endowed with attractive renewable resource as well as cheap and abundant land. Their DISCOMs are amongst the highest rated in the country, which helps as both states have a distinct preference for issuing their own tenders over procuring power from SECI and NTPC. Both states, historically cautious because of high costs, are stepping up now. Gujarat – current renewable capacity of over 12.2 GW has set a lofty target of installing 30 GW capacity by 2022. Maharashtra – current solar capacity of nearly 7 GW – has set a target of 13 GW solar capacity by 2025.

The dark sheep is likely to be Uttar Pradesh. Renewable penetration is low at 4.7% for multiple reasons – weak governance, terrible financial condition of DISCOMs, limited land availability and no wind resource. State tenders have been routinely undersubscribed over the years. But the state is the second biggest power consumer (10% share of national consumption) and perpetually facing a power deficit. The regulator has taken a tough stance on RPO shortfall and not only levied a penalty of INR 15 billion (USD 197 million) for FY 2021 on the on DISCOMs but also asked them to set aside INR 58 billion (USD 781 million) for renewable power procurement in FY 2022. The state has an attractive window to procure power from other states with inter-state transmission charges being waived fully for all projects commissioned by June 2025.

We believe that Gujarat, Maharashtra and Uttar Pradesh would be pillars of sector growth accounting for up to 50% of new renewable power capacity over the next few years.  

The Ministry of Power has issued draft electricity rules for open access (OA) renewable power. This is the first time that the central government has acknowledged increasing potential and needs of this market.

The draft rules touch upon various aspects of renewable power procurement by C&I consumers including project application and approval process, eligible capacity, alternative procurement routes and business models, banking as well as OA charges. As alternative procurement routes including ‘behind the meter’ installations, green power from DISCOMs and RECs are included in this paper, the name seems to be a misnomer.

EligibilityAll consumers with demand of more than 100 kW may procure any amount of renewable power from open access or other sources (current limit is 1 MW for open access in most states). Consumers may also install ‘behind the meter’ renewable projects without any system size restrictions.

Approval processA single window approval process is proposed for OA projects. Applications would need to be submitted to a central government agency (yet to be nominated), which will monitor application status and ensure approval by appropriate state government entities within 15 days. In case of transmission system constraints, renewable power would get preference over conventional power in approvals.

BankingOA power may be banked on a monthly basis subject to an annual cap of 10% of power consumed from the local DISCOM.

OA chargesAll OA charges and surcharges would be determined by respective regulators, as at present, provided that the Cross-Subsidy Surcharge may not increase by more than 50% in the 12-year period after project commissioning. The rules also exempt renewable power from Additional Surcharge payment.

Green power from DISCOMsConsumers may buy a specified share of their power needs in the form of renewable power from DISCOMs at specified tariff (‘green tariff’) for a minimum period of one year.

HydrogenConsumers may procure green hydrogen to meet RPO commitment.

The proposals are a mish-mash of different ideas at this stage based on feedback from different stakeholders. There is need for more refinement and clarity. But the intent behind a comprehensive C&I renewable policy is desirable. The market has huge potential as witnessed by rising number of companies pledging to net zero commitments and RE100. But it has been stymied by a number of policy-related challenges arising mainly from reluctance of DISCOMs to lose lucrative consumers.

We estimate current installed C&I renewable capacity at 17,817 MW, split across rooftop solar (6,017 MW), OA solar (4,468) and OA wind (7,315). But as the following chart shows, growth has faltered in the last few years.

Figure: Open access solar and wind power capacity addition, MW

Source: BRIDGE TO INDIA research

We estimate total potential of C&I renewable market at 130 GW capacity by 2030 provided the government can foster a conducive environment. The challenge would be to get states and DISCOMs to align with the new policy.

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.

The Union Cabinet has approved yet another DISCOM reform package worth INR 3 trillion (USD 40 billion). The package, titled ‘Revamped reforms-linked results-based distribution sector scheme,’ aims to “…improve operational efficiencies and financial sustainability by strengthening supply infrastructure….” Targets include reducing total network losses of the DISCOMs to 12-15% (current estimate 22%) and financial losses to zero (current estimate INR 0.90/ kWh) by FY 2026. The scheme is proposed to be funded partly by central government grants totalling INR 976 billion (USD 13 billion) conditional upon the DISCOMs meeting annual performance milestones.

The package is essentially an amalgamation of various ongoing schemes;

Various government attempts to resolve DISCOM financial condition have yielded almost no results to date despite a huge financial cost;

Lack of imagination and political will on part of the government to fix the distribution sector is a troubling sign for the industry;

The new package has two main components: i) smart metering, with a 100% rollout target including for agricultural consumers in OPEX mode – an estimated 250 million installations; and ii) network upgradation and expansion comprising substation augmentation, agricultural feeder separation, installation of new lines and equipment. The DISCOMs would also be required to develop and implement plans for reducing technical and commercial losses.

Table: Funding plan

Our primary reaction to this new package is utter disappointment. The package is essentially just an amalgamation of various ongoing schemes – smart metering, rural electrification, feeder separation and network expansion – which have failed to make any impact so far. It does not even attempt to identify and address roadblocks in existing schemes. Smart meters are a good example – they were first mooted in 2013, ambitious targets were announced as part of Integrated Power Development Scheme, National Smart Grid Mission and National Tariff Policy through 2014-2016 and in 2019, the government announced 100% rollout by FY 2023. But actual progress at present stands at less than 10%.

Similarly, targets for reducing total DISCOM network losses and financial losses to 15% and zero respectively have been announced multiple times with barely any progress. Notwithstanding UDAY and recent liquidity package providing total liquidity worth a staggering INR 3.7 trillion (USD 50 billion) on a conditional basis to the DISCOMs, their operational and financial performance continues to deteriorate. The DISCOMs are expected to register their worst ever financial performance in FY 2021, partly due to COVID. 

Figure: Key technical and financial performance indicators for DISCOMs

Source: PFC annual performance reports of state power utilitiesNote: Figures for FY 2020 and FY 2021 are market estimates.

The government seems hopeful that the new package along with the Electricity Amendment Bill, proposed to be passed through the Parliament in the monsoon session, would be sufficient to fix all problems in the distribution business. However, the proposed measures seem unimaginative and ineffective. Failure to resolve the distribution sector is a worrying sign.

There have been some eye-catching growth announcements in the past few weeks. After Reliance stated its plan to establish 100 GW solar capacity by 2030, NTPC, JSW Energy and Tata Power have taken turns to announce their own ambitious plans for the renewable sector. NTPC has upscaled its renewable capacity target from 32 GW to 60 GW by 2032. JSW Energy, one of India’s largest private thermal IPPs and a recent entrant in the renewable sector, plans to add 20 GW renewable power capacity by FY 2030. Similarly, Tata Power has announced that it wants to add 15 GW capacity in the “next few years.”  

Soaring investment appetite is driven both by fading prospects of thermal power and high investor enthusiasm for renewables;

The market’s capacity to absorb new renewable capacity is limited at 12-14 GW per annum;

Sharp mismatch in demand and supply is already pointing to signs of another round of aggressive bidding;

NTPC has set up NTPC Renewable Energy, a wholly-owned subsidiary, to focus exclusively on green energy business. The company aims to invest around USD 3 billion every year to develop 7-8 GW renewable capacity. It is eyeing development of mega renewable energy parks and has acquired land for a 5 GW facility in Gujarat. The sudden enthusiasm for renewable power is of course directly linked to bleak growth prospects of thermal power. The change in business thrust would be transformational for India’s leading thermal IPP, which alongside Adani, JSW Energy and Tata Power has finally acknowledged that it would forsake development of new thermal power plants.

Totting up plans of other large IPPs – ReNew and Adani plan to add another 12 GW and 21 GW capacity respectively by 2025 – we estimate that these six developers want to add a total of about 30 GW capacity on an annual basis. Even discounting for possibility of some of this capacity addition coming through secondary market, these are massive targets.

Figure: Current and planned capacity by 2025 for select developers, MW

Source: Company statementsNote: Planned capacity has been shown with annualised targets for 2025. Reliance’s planned capacity may not be owned by the company.

Meanwhile, more new international (Brightnight, Scatec) and Indian developers (REC, a PSU) have entered the sector recently. The industry is desperately looking for growth egged on by plentiful supply of equity capital and the government’s similarly ambitious target of 450 GW capacity by 2030. Unfortunately, however, the market is not willing to absorb so much capacity. Average capacity addition in the last five years including rooftop solar has been only about 9.5 GW. And we estimate that it may grow to, at best, around 12-14 GW per annum over the next five years.

The sharp mismatch in demand and supply is already telling. SECI’s 1,785 MW Rajasthan tender has been oversubscribed by more than 6x, while Madhya Pradesh’s two Rewa park tenders (550MW and 450 MW) have been oversubscribed by a staggering 15x. Expect more aggressive bidding as the industry forgets any lessons from SB and Mahindra exits.

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.

Reliance Industries Limited (RIL), a diversified conglomerate and India’s largest private company by market cap (valuation: INR 14 trillion, USD 190 billion), has announced stunning plans to enter clean energy sector. The company would invest INR  750 billion (USD 10 billion) in the next three years – INR 600 billion (USD 8 billion) to produce solar modules, storage batteries, hydrogen electrolysers and fuel cells, and INR 150 billion (USD 2 billion) in “value chain, partnerships and future technologies.” In addition, the company aims to “establish and enable” at least 100 GW of solar energy by 2030 primarily through rooftop solar and decentralised solar installations in villages. The company, an international scale oil&gas, telecom and retail player, has also committed to become a net zero emitter by 2035.

The four giga factories would be set up in Jamnagar, Gujarat with infrastructure and utilities support from RIL’s existing facilities. The solar module factory would be fully integrated from polysilicon-to-modules. The company would also set up dedicated teams to provide “end-to-end” project construction and finance solutions to: i) large renewable plants across the world; ii) MSME system integrators for deploying residential and business-scale systems. Other details are not available at this stage. We try to interpret the announcement and its likely impact on the sector.

What is the real game plan?We believe that RIL is going to be primarily focused on manufacturing and offering end-to-end solutions direct to consumers. The 100 GW installation target seems most likely aimed at C&I, SME and residential consumers using the company’s own products, operational and financing ability.

We believe that RIL would stay away from the hyper competitive utility scale project development business except for developing captive capacity for feeding its other businesses. Bulk of the action would therefore come in rooftop solar and off-grid solar businesses. The company could provide a major fillip to these markets by addressing key pain points for consumers and rolling out highly competitive solutions integrated with low-cost financing.

Are the plans credible?Coming from a company with unmatched financial and operational might of RIL, the announcement has to be taken seriously. FY 2021 turnover and net profit stood at USD 64 billion and USD 6.7 billion respectively. The company has successfully created some of the world’s largest integrated oil & gas, infrastructure and telecom facilities from scratch in record times. RIL is also believed to stay very close to ruling central and Gujarat state governments with a uniquely influential role in policy making, very crucial in the heavily policy dependent energy sector.

RIL’s foray into telecom services in 2016 is an instructive case study. The company upended a mature sector by offering complete digital solutions at super low prices backed by an INR 1.5 trillion (USD 15 billion) pan India network with last mile fibre infrastructure. In just four years, it crushed leading incumbents like Vodafone, Aditya Birla and Tata to become the largest industry player with a 35% market share.

But some parts of the plan including 100 GW installation target appear less realistic. Hydrogen and fuel cell manufacturing vision is expected to take longer time in view of the nascent state of this sector. We also believe that the company would struggle to establish a clear toehold in international markets.

Can RIL compete against Chinese giants?RIL may have a competitive edge over its Indian peers. The true challenge would come from across the border. In all target businesses, the world’s top producers are (likely to be) predominantly from China. Despite its strengths in infrastructure, supply chain and financing, RIL would find it difficult to compete with them on technology and production scale. This is where the company’s ability to shape government policy would come handy. It would rely on protectionist moves like BCD on solar modules to overcome cost or technology disadvantage and thrive in the domestic market.

What does it mean for other players?RIL’s entry into module manufacturing should be devastating for all current and aspiring players. The company could realistically set up a 10-15 GW integrated capacity and sell modules at prices 20% below domestic competition to dominate the market. No other player could even come close to competing with RIL on backward integration and scale.

We do not expect any material change in the utility scale project development business. Most rooftop solar and other distributed solar players – combined annual market size of about 2,000 MW – are anyway very small at present. They would mostly benefit from the massive tailwinds created by RIL’s entry into the business.

With its new energy plans, RIL is bowing to pressure from the international financial community and signalling a strategic change of direction away from fossil fuels. Notwithstanding the company’s motivations, its entry into renewables is a game changer for the sector.

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.

The Indian government has issued a new production-linked incentive (PLI) scheme to develop 50 GWh and 5 GWh domestic manufacturing capacity for advanced battery storage technologies and niche storage technologies respectively by March 2024. The government proposes to grant cash incentives aggregating INR 181 billion (USD 2.5 billion) over five years to selected bidders, who would commit to set up manufacturing facility for minimum 5 GWh of advanced battery storage capacity and/ or 0.5 GWh for niche storage capacity. They would need to invest a minimum INR 2.25 billion (USD 30 million)/ GWh in capital expenditure and commence commercial operations within two years. Total capacity per bidder is capped at 20 GWh.

The scheme design is overly ambitious in terms of minimum required size, time scale and performance conditions;

Many crucial details relating to technology specifications, selection process, backward integration, localisation and penalties are not yet available;

Lack of demand visibility is likely to be a strong deterrent for potential bidders;

The scheme comes with two tough riders: i) minimum specific density and number of cycles over battery life (see table below); ii) minimum domestic value addition of 25% going up to 60% within five years.

Figure: Minimum performance specifications for ACC technologies

Source: Notification issued by Department of Heavy Industry

Companies would be selected through a two-stage bid process. Subsidy payments, to be made every quarter over first five years of operations, are proposed to be linked to actual domestic value addition and sales in each quarter. Actual payment would be capped at 20% of total turnover. The payments would also be differentiated based on extent of backward integration into cell manufacturing.

The scheme seems to have been rushed out in a hurry as many crucial details on technology specifications, bidding process, backward integration, localisation and penalties etc. are not available yet. The proposed scheme size and implementation timetable are also highly unrealistic. The government’s battery storage demand projections are wildly optimistic as growth in both EV and power storage businesses continues to stall mainly due to high cost of storage and policy uncertainty. The PLI scheme by itself would make little material difference on either account in the short run.

Battery storage is obviously going to be a critical pillar of energy transformation. The government has been wooing international battery majors to come to India. So far, only TATA Chemicals and a  TOSHIBA, DENSO and Suzuki Motors joint-venture have announced intentions to set up manufacturing facilities. Many interested players are pushing for relaxation in scheme design but we believe that the industry needs strong demand visibility first.

Bid submission date for Indian Renewable Energy Development Agency Ltd (IREDA)’s 5,000 MW solar tender has been extended again to 15 June 2021. This is the third such tender issued under MNRE’s 12,000 MW PSU phase II scheme, which mandates that all power must be sold to government owned entities and PSUs for their captive consumption. Only domestically manufactured cells and modules may be used in such projects.

The decision to reduce tariff and capital subsidy is perplexing as most capital costs have shot up by 20-25% over last year;

Proposed VGF amount is barely adequate to cover extra costs of procuring modules domestically;

Merits of continuing the scheme with a considerable subsidy cost to the exchequer are questionable in view of the proposed BCD and production-linked incentives;

The bid submission extension follows recent amendments to some key provisions of the PSU scheme. Fixed tariff for sale of power has been reduced from INR 2.80/ kWh to INR 2.45/ kWh, flat over 25 years. Maximum viability gap funding (VGF, a capital subsidy) has also been reduced from INR 7.0 million (USD 96,000) to INR 5.5 million (USD 74,000) per MW, while commissioning deadline has been increased to 30 months. The VGF support is provided to cover cost differential of 20-25% between domestically manufactured and imported modules.

The rationale behind reducing tariff and capital subsidy is hard to comprehend. While module prices were on a downward trajectory until July 2020, all input costs have been firming up for nearly a year now. There has been a significant surge of 20-25% in costs for modules, other components, labour as well as freight arising from increasing commodity prices and recent supply chain bottlenecks. Incidentally, capital costs have shot back up to same level as in 2019, when the PSU phase II scheme was launched. We believe that the reduced tariff and VGF amount would not be viable for project developers.

Response to two previous tenders under the PSU scheme has been underwhelming. Only 2,026 MW capacity was awarded in two auctions conducted by SECI for 3,500 MW capacity due to lack of bidding interest.

Figure: Capacity awarded under PSU scheme, MW

Source: BRIDGE TO INDIA research

NTPC is the biggest beneficiary winning nearly 80% of all allocated capacity. The company is intent on aggressively growing the renewable business and should again be bidding a relatively large capacity.

Designed exclusively to support domestic module manufacturers, the PSU scheme has been of little help so far because of relatively small volumes and slow progress. Most of the awarded projects are facing completion delays. Finding willing offtakers and tying up open access arrangements is not proving to be easy even for PSU giants. We also question persisting with the scheme at a considerable cost to the exchequer – this tender has a budgeted VGF outlay of INR 27.5 billion (USD 370 million) – when the government has already announced steep duty barriers and production-linked incentives to support domestic manufacturing.

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 power sector regulator, CERC, has issued draft ancillary services regulations aimed at ensuring smooth operation of the power system. The highlight of the draft regulations is to allow energy storage facilities and demand side resources, for the first time ever, to provide secondary and tertiary ancillary services.

The draft regulations come almost three years after CERC released a discussion paper for redesign of ancillary services mechanism. In the meantime, pilot projects have been undertaken for secondary frequency control through Automatic Generation Control (AGC) and ‘fast’ tertiary frequency control through Fast Response Ancillary Services (FRAS). The definition and scope of primary reserves, triggered by a sudden change in frequency and controlled at individual generation asset level, remain untouched. Proposed secondary and tertiary reserves should encourage new resources to be connected to the grid for innovation in technical and commercial solutions.

Table: Minimum requirements for ancillary services

Note: Tertiary reserve can be used to replenish secondary reserve deployed continuously in one direction for 15 min for > 100 MW as well as to respond to other events specified in the Grid Code.

Rapid growth of renewables, coupled with retirement of fossil fuel power, which has traditionally been providing synchronous inertia to the system, has resulted in growing need for frequency regulation. Such services demand extremely quick response times as well as accuracy, which can be best met with advanced age batteries. Globally, energy storage and demand response have already proven to be ideal solutions for these needs. Moreover, projects in the US, the UK and European Union have demonstrated that such solutions can also capture other value streams creating a value-stack, in effect, kick-starting a growth cycle for energy storage facilities.

CERC has invited comments and suggestions on the draft regulations by 30 June 2021. The proposal to allow energy storage and demand side resources to provide ancillary services is a critical step in the right direction. We expect energy storage to be allowed to provide primary reserve ancillary services at a later date. This timetable might even get accelerated in view of the Ministry of Power’s recent suggestion to states to explore need for setting up large storage systems around cities to mitigate incidents like recent grid collapse in Mumbai.

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.

In Q1 2021, daytime power prices in southern Australia fell repeatedly below zero between 10 am and 3:30 pm. The negative prices came on back of low power demand and increasing renewable power penetration in the country (28% in 2020). In Germany too, where Q1 renewable power penetration crossed 50%, frequency of negative price points has been increasing. In March 2020, the country logged 130 hours of negative prices due to high wind power production, up 44% over March 2019. Similar events are now witnessed with increasing regularity in many other countries across Europe and USA.

Most countries are struggling to cope with intermittency risk of renewable power;

In India, various initiatives to improve grid resilience have made little headway so far due to high policy inertia, low technical expertise and unwillingness to bear extra costs;

Without proactive planning, the problem would escalate disproportionately over time and affect growth prospects of the sector;

With increasing share of renewable power, residual power demand has come to resemble the famous “duck” curve, posing problems for grid managers and conventional power producers. While renewable power usually enjoys guaranteed feed-in-tariffs (FITs) or ‘must run’ status, inflexible coal-fired plants face a tough choice: expensive cycle of daily shutdowns and restarts, or payments to consumers to be able to despatch power i.e., negative prices. The affected countries are responding in different ways – building storage capacity, increasing reliance on flexible gas-fired power, undertaking demand side management, and/ or increasing trading in ancillary services and other grid flexibility services. But renewable power is not getting away scot free either. Germany has imposed restriction on FIT payments, while the Netherlands has said that it would not pay incentives to solar and wind power plants if power prices turn negative. In the UK, ‘constraint payments’ to wind power plants are becoming controversial.

In India, with relatively low renewable penetration of about 10%, the problem seems somewhat distant. There is a view that launch of green power exchange and the option of exporting surplus power across states or even neighbouring countries would provide sufficient system flexibility. But high price of old contracted power and transmission system constraints are formidable barriers. DISCOMs in RE-rich states – penetration in Karnataka, Andhra Pradesh and Tamil Nadu has already touched 40%, 22% and 21% respectively – are turning to curtailment with various estimates suggesting annual incidence as high as 15% in some states. Meanwhile, the ominous ‘duck’ curve is bound to get significantly worse in the coming years (see chart below).

Figure: National power demand to be met from coal-fired plants on a summer day, GW

Source: NLDC, BRIDGE TO INDIA researchNotes: 2030 scenarios assume unchanged gas-fired power supply and 100% diversion of hydro power output to peak demand hours.

There have been multiple pilots, research studies and consultation exercises over the years to examine feasibility of demand side management, flexible thermal power generation and cheaper gas-fired power. But there is no tangible progress. Reasons include high policy inertia, low technical and management expertise, poor quality data and unwillingness to bear extra costs.

Table: Status of key measures to improve grid resilience

Source: BRIDGE TO INDIA research

Lack of urgency on this front should worry all stakeholders. Absent proactive planning, the problem would escalate rapidly. DISCOMs are already getting reluctant to buy more renewable power affecting growth prospects of the sector.

Japan’s SoftBank is in the process of exiting Indian renewable sector, selling most of its 80% stake in SB Energy to CPPIB, the Canadian pension fund. Remaining 20% stake in the company would continue to be held by Bharti Enterprises. SB Energy has a SB Energy has a 4.9 GW portfolio including 3.5 GW capacity under development. As per news reports, the 80% equity stake has been valued at USD 525 million, subject to satisfactory due diligence and fulfilment of all bid conditions. Separately, Mahindra group, owner of a 1,222 MW solar project portfolio and a leading EPC player, has announced outright sale of the business to Brookfield for about USD 500 million.

The two exits portend diminishing investment case for Indian renewables;

Attractive fundamentals of the sector are diluted by growing policy uncertainty, execution risks, reluctance of utilities to sign PPAs, delayed payments and weakening growth prospects;

While utilities and industrial investors turn conservative, financial investors are doubling down on the back of record low interest rates and strong ESG mandates;

Both exits make eminent sense. SoftBank, originally planning to set up 20 GW capacity in India, has found it very difficult to scale up the business in face of aggressive competition, low returns and execution challenges. The Indian renewable business was sub-scale and sub-optimal in its multi-billion USD technology-dominated global portfolio. The deal valuation, believed to be below book value of investments, points to SoftBank’s high-cost structure and extremity of the various challenges faced by the company. The sale process, delayed by several documentation and regulatory issues, is still ongoing.

The Mahindra group, meanwhile, has also taken a strategic call that the utility scale business was not attractive from a scale and profitability perspective. Interestingly, the group has decided to focus instead on residential rooftop solar and C&I renewable businesses, where it has marginal presence right now. The management believes that it can build a more attractive B2C business with its strong consumer brand and distribution reach.

Historically, most large M&A transactions in the sector have been motivated by a desire to churn capital and release money for further investments (see table below). In contrast, exits of SoftBank and Mahindra portend diminishing investment case for Indian renewables.

Table: Notable renewable sector exits

Source: BRIDGE TO INDIA researchNotes: The data excludes joint-venture transactions. Portfolio size includes projects under construction.

Leading global and Indian investors have poured into the sector attracted by promises of government support, huge growth prospects and quasi-sovereign offtake. But the reality is marred by growing policy uncertainty, execution risks, reluctance of utilities to sign PPAs, delayed payments, weakening growth and flagging risk-adjusted returns. Intense bidding and falling tariffs have only exacerbated the pain.

And yet while utilities and industrial investors retreat from the sector, financial investors – pension funds, sovereign wealth funds, private equity and infrastructure funds – continue to pile into the sector. For CPPIB, SB Energy acquisition would be their third major investment in Indian renewables after a USD 391 million investment in ReNew and a USD 600 million JV with Piramal group for setting up a renewable INVIT. Brookfield, a leading global owner of renewable assets, is also hungry for more assets. After acquiring 300 MW of operational assets from SunEdison in 2018, the fund manager has made bolt-on acquisitions of Axis Energy and Emami Power (total 253 MW) besides becoming active in the primary market.

Global liquidity pools are currently overflowing on the back of record-low interest rates and strong ESG mandates. But such capital can be fickle and it is important that the government heeds demands of investors before events turn sour.

As things stand today, safeguard duty (SGD) of 14.5% on solar PV cells and modules is set to expire on 29 July 2021. While the Ministry of Commerce trade investigation is still supposedly ongoing, another extension is looking unlikely. Basic customs duty (BCD) of 25% and 40% on cell and module imports respectively is set to kick in from April 2022 onwards. We are now therefore looking at the possibility of an eight-month duty free window from 30 July 2021 to 31 March 2022.

The duty-free window would offer relief to project developers with substantial project pipeline coming up for implementation;

Constrained supply from China and high module prices in H2/ 2021 are potential spoilers;

The industry faces a tough choice – import modules duty free at higher cost or wait until prices soften next year and deal with tedious ‘change in law’ claims;

The duty-free window is meant to be a little concession to project developers ahead of the steep duty looming ahead. The industry is wary of duty burden for substantial solar project pipeline – 26.6 GW as of December 2020 (setting aside about 18 GW of auctioned projects with unsigned PPAs) – coming up for implementation. While most of this pipeline enjoys ‘change in law’ protection, the settlement process is messy, time taking and financially onerous for DISCOMs. The government is also mindful that domestic manufacturers do not have sufficient capacity to cater to this demand.

Figure: Import duty timeline

Source: BRIDGE TO INDIA research

The duty-free window should logically lead to a huge import surge. Both developers and end consumers, particularly C&I consumers, would accelerate project tables and bring demand forward to avoid duty burden. Similar policy-linked windows have led to major one-off surges in capacity addition in the US, Europe and Vietnam, amongst other countries. But we expect the effect in India to be somewhat muted for multiple reasons. With COVID flaring across the country, tremendous uncertainty lies ahead on pace of contract execution, financial closures and site activity. Large, well-capitalised developers like Adani, ReNew, Tata, Azure and Ayana have the financial capacity to stockpile modules but we believe that they would look to bring only 50-70% of their demand forward both to spread financial burden and physical execution.

The other problem is rising module prices and constrained supply from China particularly in H2/ 2021. Mono-crystalline module prices have been firming up now for five months and are expected to stay in the USD 0.23-0.24/ W range for the whole year because of soaring input costs and strong global demand, expected to touch a record 180 GWp this year.

The price sensitive Indian market faces a tough choice – import modules duty free at higher cost before March 2022 or wait until prices soften next year and deal with tedious ‘change in law’ claims. We expect total potential import demand at around 20 GW through March 2022 but only about 60% of this may be fulfilled because of various constraints.