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After resisting growth of net metering and open access markets, DISCOMs seem to be now turning their focus on ‘behind the meter’ (BTM) installations, a key engine of growth for the rooftop solar market in the last few years. Maharashtra and Gujarat DISCOMs are asking consumers seeking open access project approvals to switch BTM systems to gross metering mode effectively making them financially unviable. Some Rajasthan DISCOMs have even started levying electricity duty, cross subsidy surcharge (CSS) and additional surcharge (AS) on BTM systems with the same end result.

Switching from BTM to gross metering mode reduces effective saving potential of rooftop solar installations drastically from variable grid tariff (INR 8.48-13.08/ kWh and INR 6.80-7.39/ kWh in Maharashtra and Gujarat respectively) to gross metering tariff (INR 3.00/ kWh and INR 1.75/ kWh in Maharashtra and Gujarat respectively). The reduction renders all such systems, almost without exception, as financially unviable. The levy of electricity duty, CSS and AS totalling INR 3.35 – 3.52/ kWh in Rajasthan has the same end result. These measures are particularly harmful for OPEX-based installations, which are being forced to shut down in many cases.

As net metering policy became increasingly restrictive over the last few years (see figure), BTM installations became the default mode for setting up large rooftop solar systems – often over 1 MW in size. We estimate that a total of 2,211 MW rooftop or other onsite solar capacity has been installed in this mode spread mainly across Maharashtra, Rajasthan, Gujarat, Madhya Pradesh, Karnataka and Tamil Nadu. In the absence of any formal policy clarity (eligibility criteria, technical requirements, approval process, applicability of grid charges and surcharges etc), consumers and OPEX solution providers market have conveniently taken the view that there was no restriction on BTM systems for 100% self-consumption and no requirement to bear any grid charges. Historically, the only formal requirement for such systems has been to obtain approval from local safety inspector depending on prevailing policy in addition to installation of a simple relay to prevent injection of power into the grid.

Figure: Net metering connectivity size limit for C&I rooftop solar systems

Source: BRIDGE TO INDIA researchNote: In Karnataka and Madhya Pradesh, net metering is not available for OPEX business model. Tamil Nadu and Uttar Pradesh offer only net billing and gross metering to C&I consumers. West Bengal provides net metering to C&I consumers but with a system size limit of only 5 kW.

The changes in policy stance are blatantly ad hoc and creating confusion in the industry. That these changes are being applied to older installations without any prior warning and forcing them to shut down is outrageous. Elsewhere too, DISCOMs continue to deny or delay project approvals, impose ad hoc certification or reporting requirements and levy charges in defiance of official policy framework. The regressive actions by DISCOMs are another reminder of high policy risk in the corporate renewable market.

After having seemingly binned the Electricity Act, 2003 amendment bill last year, the government has sprung a surprise by reviving it. A new draft has been tabled in parliament but immediately sent to a standing committee for wider consultation amid opposition from other political parties, state governments and other stakeholders. The central feature of the bill, as last time, is proposed delicensing of the distribution business. The proposal is to allow new players to enter distribution business and supply power to end consumers by riding distribution networks of incumbent DISCOMs for a fee. The new players shall seek approvals from state regulators but based on criteria specified by the central government rather than state governments.

The Bill has several other provisions relating to streamlining of tariff determination process, ensuring full cost recovery by DISCOMs, constitution of state regulators and more power to regulators pari passu with civil courts. These provisions are broadly similar as last time but there are two main changes. The first one relates to requirement for all power purchasers to maintain adequate security of payment prescribed by the central government. If the power purchasers fail to maintain the prescribed payment security, power would not be scheduled and despatched to them. The other main change is enforcement of a uniform RPO trajectory across the country although financial penalties for non-compliance are proposed to be reduced by more than 50% to INR 0.25-0.35/ kWh in first year and INR 0.35-0.50/ kWh in subsequent years.

Main objective of the Bill clearly (and rightly so) is to restore financial condition of DISCOMs, which has been deteriorating steadily putting all sector initiatives at risk. The innumerable financial support and reform packages announced to date have been to almost no avail. ICRA estimates that total DISCOM debt has increased from INR 4 trillion (USD 50 billion) to INR 6 trillion (USD 76 billion) in the last five years while there has been no improvement in payment status to IPPs.

However, the proposed delicensing solution has a fundamental flaw. The incumbent DISCOMs would continue to own and be responsible for all legacy PPAs, distribution network and associated costs. Running a full service distribution business and providing a parallel service to new competitors introduces a severe conflict of interest. Managing that conflict – sharing of power supply, granting network access and maintaining a cross subsidy balancing fund on an equitable basis – is going to be a herculean challenge. It remains to be seen if integrity of this process can be maintained particularly as the state governments see a natural incentive in DISCOM mis-governance and using cheap power to lure voters.

The government has mistakenly abandoned the other two potential routes of making DISCOMs financially viable – privatisation and separation of content and carriage. Each route is fraught with unique challenges but the delicensing solution is almost too complex to be workable. Failure to implement with due rigour would be a recipe for endless regulatory disputes and confusion. Given the magnitude of the problem and its widescale implications for economy, we believe that the government needs to build a consensus on sector reform and possibly change course.

Since announcing the goal of achieving net zero emission status by 2070 in November 2021, the government has taken first tangible step in that direction. A bill has been introduced in the Lok Sabha to amend the Energy Conservation Act, 2001 to mandate use of non-fossil fuel based energy sources and establish carbon credit market in the country. It defines applicability threshold as all industrial, commercial and residential consumers with a minimum connected load of 100 kW or contract demand of 120 kVA. The bill is mainly a directional policy document; detailed rules would be issued separately.

Key highlights of the bill:

i. Energy consumption targets would be set for different types of consumers;ii. Financial penalties would be imposed on entities failing to meet targets;iii. Manufacturing or import of specific equipment failing to meet energy consumption standards would be banned; andiv. Regulatory jurisdiction will lie with state electricity regulators.

In India, there are already two different schemes indirectly targeting decarbonisation by industrial and commercial entities. All thermal power consumers are required to procure a minimum specified share of power from renewable sources or buy Renewable Energy Certificates (RECs). The Perform, Achieve and Trade (PAT) scheme requires specific businesses in energy intensive industries to comply with energy efficiency standards or buy Energy Saving Certificates (ESCERTs). As the following table shows, the REC and ESCERT markets are tiny in scope, coverage and market value.

Table: Comparison between REC, ESCERT and carbon trading certificate

Source: IEX, BRIDGE TO INDIA research

The new carbon trading scheme is expected to be significantly larger in comparison. It would also inevitably have significant overlaps with both REC and ESC schemes. For example, if a company increases renewable power consumption and reduces its emissions as a result, will it be entitled to both RECs and carbon credits? It is vital for policy clarity and market efficiency that the three schemes are merged into a single scheme. A unified approach with a consistent emission based denominator would also act as useful guidance to energy consumers evaluating investment decisions in alternate decarbonisation technologies.

There are currently 32 carbon markets – covering 17% of global GHG emissions – operational around the world. In 2021, traded volume and value jumped sharply to 15,811 million MT (plus 24% YOY) and EUR 759 billion (164%) respectively. Europe accounts for 90% of total activity because of stricter enforcement and more mature market. Prices in different markets range between EUR 16-65 per tonne or about INR 1.30-5.20/ kg.

Figure: Total value of global carbon markets, EUR billion

Source: Carbon Market Year in Review 2021, Refinitiv

A detailed study of different global carbon markets should offer useful lessons for Indian policy makers. Designing the scheme, setting targets, defining standards, trading protocols, and developing inspection and monitoring capability will require careful consideration. The government would also need to play a critical enabling role in developing technology, skilling and financing expertise for decarbonisation efforts.

This video presents a summary of major sector developments including tender issuance, auctions, policy and regulatory developments, financial deals and related market trends in June 2022.

The Ministry of Power has issued an order specifying national RPO trajectory until FY 2030. The target, originally set at 21.00% for FY 2022, has been modified and extended to 43.33% for FY 2030. Separate sub-targets have been introduced for new large hydro, wind and storage projects. Solar has been clubbed with other technologies like biomass and waste-to-energy and, older large hydro and wind projects in a separate sub-category.

Table: RPO trajectory until FY 2030

In a neat sleight, the government has included older large hydro projects in the Other RPO category immediately raising March 2022 compliance level from 12% to above the target level of 21%.

Separate targets for large hydro and wind, both struggling in recent years, emphasise importance of boosting these sectors. Any shortfall in Other RPO category may be met from excess power consumed from large hydro projects commissioned after Mar-19 or wind projects commissioned after Mar-22, but any shortfall in WPO may be met only from excess power from large hydro projects commissioned after Mar-19. CERC has been asked to issue regulations for a new hydro REC instrument with suggested price cap of INR 5.50/ kWh escalating at 5% annually. But other REC instruments would also need to be redesigned in accordance with the newly constituted targets.

Taking note of the 2030 target of 500 GW renewable capacity, it seems that the RPO trajectory has been framed with the assumption of national power demand growing at 6% annually and implied CUF for new large hydro, wind and other projects of 30%, 25% and 20% respectively. A more realistic scenario of at 4.5% annual demand growth and CUF of 40%, 35% and 24% for large hydro, wind and other projects results in total renewable capacity of 387 GW by March 2030 (see figure).

Figure: Required capacity addition based on new RPO trajectory

Source: BRIDGE TO INDIA research

A separate storage target is desirable. But the 4% target – equivalent to total storage capacity of 88 GWh by March 2030 – is significantly lower than previous government estimates. And there is surprisingly no mention of enforcement or penalty mechanism.

While it is good to see the government finally providing some clarity on sector roadmap since announcing the 500 GW target back in November 2021, some fundamental issues remain unaddressed. One, how to get the states to accept these targets. Historically, RPO trajectories of 25 states have remained below the national target. Second, how to improve enforcement. We believe that 27 of the thirty states have failed to meet their own (lower) RPO targets and in most cases, the failure goes unpunished. Proposed amendments to the Electricity Act include a provision for penalties of up to INR 0.50/ kWh for non-compliance but there is no clarity on timeline. Finally and most importantly, how to speed up capacity addition. Progress is painfully slow because of poor demand, severe execution bottlenecks and soaring costs. Total capacity addition in 2022 and 2023 is expected to come in at about 21 GW, about 65% below required levels.

The MNRE Secretary announced at a recent conference that the government has decided to do away with e-reverse auction stage for wind power projects. Projects are proposed to be allocated on the basis of a single-stage written bid submission by developers. The move comes in response to persistent lobbying by the industry to relax the competitive bidding process. A formal announcement from MNRE is awaited shortly. Project developers hate competitive bidding process for obvious reasons. But all pleas to the government to move to feed-in-tariffs have been rejected again and again. The other suggestion, of the government issuing a clear annual time-table plan for auctions to mitigate FOMO concerns – sensible but operationally impracticable unfortunately – has also been rejected several times. The government has reluctantly offered a small concession because it is getting worried about slow pace of progress. Around 4 GW of wind projects have already been abandoned by developers on back of rising costs and execution challenges. Wind capacity addition has ground to a near halt – falling to 1.1 GW in 2021 and an average of 1.6 GW over last four years against about 3-4 GW per annum prior to 2018. For context, the 2030 target of 140 GW wind capacity warrants capacity addition of over 11 GW per annum. The decision to do awa with auctions is ad hoc and unlikely to change anything. First, the problem of unviable bids is not unique to wind projects. All sectors including thermal power, solar, roads and ports with competitive bidding process have faced similar issue of overly aggressive bidding. Solar projects have historically seen a relatively better success rate only because of sharper than expected fall in equipment costs. Now that module and other execution costs are going up, solar faces the same issue. We believe that as much as 18 GW of solar projects face abandonment risk over next year. Second, the industry view that the auction stage puts undue pressure on them to bid aggressively is hardly credible. Third, auctions actually allow bidders to go in with conservative bid levels in the first stage and then finesse their bids in the second stage. If the auction stage is removed, the bidders will have only one shot at success making more desperate bids likely. The real problem is twofold – weak demand against too much capital, and an overly loose bidding process. The first problem is of a systemic nature and not the focus of this note. The latter has got progressively worse over time. Bid security and performance security amounts have fallen to grossly inadequate levels of less than 1% and 3% respectively. Indeed, even that requirement has been relaxed in the aftermath of COVID. Eligibility criteria have been deliberately diluted progressively to drive bidding interest and low tariffs. There is no sanctity to execution timetable. The process from auction date–letter of award–PSA and PPA execution–regulatory approval can often take more than a year. And when things go wrong, say delay in land procurement or increase in costs, the government is sympathetic on giving time extensions. Many projects have got repeated time extensions totalling to 1.5 years on account of COVID, land unavailability (at the right price), module supply disruption, transmission delays etc. There is little penalty for errant developers. If a project ends up being unviable, the successful bidder can simply surrender it and bid for a new one (heads I win, tails you lose!). The competitive bidding process has become a farce as a result. It is encouraging deviant behaviour instead of enforcing bid discipline. The rules need to be tightened on both sides – government and offtakers, on one hand, and project developers, on the other – to lend sanctity to the process.

The Ministry of Power has issued new Electricity Rules offering yet another debt package to DISCOMs to help clear delayed payments to power producers and transmission companies. The proposal is for DISCOMs to reschedule and clear all outstanding amounts in equal monthly instalments spread over 1-4 years depending on total quantum of liability. If the DISCOMs abide by the scheme and make all rescheduled payments on time, their entire accumulated late payment surcharge (LPS) liability, currently estimated at INR 198 billion (USD 2.5 billion), shall be waived. The “rules” are voluntary for DISCOMs, who are required to provide their acceptance to the scheme within 30 days.

In case the DISCOMs fail to make any monthly payment as per the revised schedule, they would be required to pay the full LPS amount and may be barred from accessing short-term open access and exchange markets. PFC and REC, government owned financial institutions, are expected to provide state governments with additional debt financing to support repayments under this scheme. The most striking component of the new scheme is that the cost of LPS waiver is expected to be borne by the power producers and other obligors. It is not clear how the government has pre-supposed their willingness to forego these payments.

The new scheme is the tenth such policy package by the central government to rehabilitate the perennially distressed DISCOMs in last eight years (see figure below). Despite over USD 50 billion of aggregate relief over this period, financial position of the DISCOMs has been deteriorating steadily. As per an ICRA estimate, their total debt and overdue payments are expected to have increased to INR 6 trillion (USD 76 billion) and INR 1.3 trillion (USD 16 billion) by March 2022. All proposed reforms have failed because of refusal of the state governments to come on board. Even where the DISCOMs and state governments have agreed to a series of conditional operational efficiency and prescribed reforms (example, UDAY scheme), they have simply failed to make permanent headway.

Figure: Proposed DISCOM reform packages since 2015

Source: BRIDGE TO INDIA research

Failure of the central government to permanently fix the distribution business permanently is a mystery. By moving from one half-baked scheme to other, it is showing a lack of political commitment and/ or a worrying underappreciation of the malaise. We believe that poor operational and financial preparedness of the DISCOMs is critically impacting overall health of the power sector and growth of renewable power. Moreover, by proposing to give DISCOMs more time to make delayed payments and asking power producers to bear the cost of LPS waiver, the government is setting a very bad precedent.

Note: Next edition of the India Renewable Weekly shall be issued, after a two-week summer break, in the week commencing 17 July 2022.  

This video presents a summary of major sector developments including tender issuance, auctions, policy and regulatory developments, financial deals and related market trends in May 2022.

A committee constituted by the Supreme Court (SC) has released technical specifications and certification requirements for installation of bird diverters on overhead transmission cables. The move came after CEA noted that bird diverter installation had been extremely slow and of poor quality. According to NLDC, first bird diverter on ISTS lines was installed in April 2022.  An interim order issued by the Supreme Court in April 2022 had mandated installation of bird diverters on all transmission lines by 20 July 2022 and allowed exemption from laying underground lines only on a case-by-case basis.

In April 2021, the Supreme Court had ordered renewable project developers to move all existing and new transmission lines underground within a year in inhabited areas of the near-extinction Great Indian Bustard and Lesser Florican birds. The affected areas stretch across parts of Rajasthan and Gujarat, prime locations for renewable projects. Where conversion from overhead to underground is not “feasible”, the court ordered mandatory installation of bird diverters. In response, MNRE and the Ministry of Environment, Forests and Climate Change (MOEFCC) applied to the court in November 2021 seeking relief from the court’s decision due to concerns about its impact on project execution and viability. CEA submitted a detailed techno-commercial study to the Supreme Court concluding that laying underground cables would be 4-20x costlier than overhead lines depending on voltage level. It also raised concerns about unavailability of underground cable lines in India, higher transmission loss and adverse impact on environment.

The Supreme Court order is ambiguous as it does not define feasibility threshold for moving transmission lines underground. Cost of installing bird diverters is relatively miniscule at around INR 1.5 million (USD 20,000)/ km of transmission line. But there are various operational challenges in installation of bird diverters including procurement lead time, need for statutory approvals (in some cases, the lines need to be switched off) and maintaining installation quality. Drone-based installations, usually faster than other approaches, are not allowed in many of the affected areas because of security concerns.

Next court hearing for taking stock of progress is scheduled on 20 July 2022. An urgent resolution of this issue is essential as nearly 2 GW of projects are held up in advanced stages of construction. The developers, already reeling from soaring execution costs, are not keen to incur any additional cost. If ordered to lay underground lines, they are likely to challenge the committee’s decision in the Supreme Court. MNRE has extended scheduled COD of all projects awarded by central government agencies including SECI, NTPC and NHPC to 30 days after the final judgement date. But more extensions may be needed.

Growth of renewable sector has led to increasingly frequent conflicts about its social and environmental impact. So far, these issues have been generally swept away in the rush to execute projects and accelerate progress. In most states, requirements for environmental permits or carrying out social and environmental studies have been completely waived. Unless the government takes a more sensitive approach to needs of local people and habitats for sustainable growth of the sector, such disruptions are likely to recur with greater intensity.

The US government has decided to defer import duties on ASEAN solar cells and module imports for two years notwithstanding its make local policy and an ongoing Department of Commerce investigation into circumvention of duty by ASEAN manufacturers. The decision was influenced mainly by fears of a sector slowdown amid intense pressure from the solar industry, already reeling from sharp price rises and supply side disruption. The two year window is intended to ensure sufficient supply of modules while domestic manufacturing capacity ramps up. In stark contrast, in very similar circumstances, the Indian government is maintaining a firm stance on no imports.

We estimate India’s current cell and module manufacturing capacity at about 4 GW and 15 GW respectively. But more than 50% of this capacity is technologically obsolete and cost inefficient. Total production last year was only about 2,460 MW and 4,935 MW respectively. Many companies have announced ambitious manufacturing plans but bulk of new capacity is expected to come online only by late 2023 onwards. Appetite for module imports, following BCD imposition, is limited as evident from sharp decline from a monthly average of 1,200 MW over last two years to 68 MW over last two months. Even project developers entitled to ‘change in law’ compensation for BCD are not keen on imports because of high upfront cost and inherent uncertainty in pursuing claims against offtakers. That leaves a big gap in module availability vis-à-vis demand.

Figure: Module manufacturing capacity and demand, MW

Source: BRIDGE TO INDIA research

Developers are trying to cope with the supply shortage in multiple ways. Reliance, Adani, Tata Power, ReNew and Avaada – five of the biggest consumers – are entering or expanding their module manufacturing capacity. Azure has tied up with Premier Energies to secure 600 MW of module supply annually. Some are finding ingenious ways to avoid BCD on imports. A Free Trade Agreement (FTA) with ASEAN countries allows duty-free import of cells subject to 35% local value addition. However, this is not expected to provide any material relief because of limited capacity in ASEAN. Moreover, with the US waiving all duties on ASEAN imports, these manufacturers would prefer to supply modules in the profitable US market (40 cents/ W) rather than in the price-sensitive Indian market. Meanwhile, a couple of project developers are believed to have tried importing modules under a bonded warehouse scheme to defer duty payment.

Consequently, we believe that solar capacity addition would be suppressed by about 6-8 GW over 2022 and 2023. All parts of the sector are expected to be affected but rooftop solar and other distributed markets may see a relatively bigger hit.

The Ministry of Power (MOP) has released final open access renewable rules clearing the path of corporate consumers to buy renewable power using open access and other routes. The rules are broadly consistent with the draft version issued in August 2021 except for two changes. Limit on amount of banked power has been revised from 10% of annual consumption to 30% of monthly consumption from DISCOMs subject to payment of banking charges as determined by the regulator. Second, reference to behind-the-meter (BTM) generating systems as an option to meet RPO targets has been removed.

The rules, coming in response to extensive policy advocacy efforts by the industry and consumers alike, seek to end DISCOM resistance to the open access market. There are three critical provisions. The first one relates to widening consumer eligibility for open access to all consumers with connected load of 100 kW, down from 1 MW at present in most states. The second provision is removal of all arbitrary caps on project size and total quantum of renewable power procurement. Currently, states impose multiple formal and informal renewable power caps linked to absolute system size, connected load, contract demand and distribution transformer capacity. The third provision is harmonisation and transparency in open access connectivity application process across states with a national registry and assured approval to all projects within 15 days of application date.

The rules are being hailed as a revolution. On paper, that’s correct. They improve growth potential of the open access market, long suppressed by DISCOMs, by a factor of more than 10x (average annual capacity addition in last 3 years: 1.3 GW). It is worth noting that SME consumers account for 51% of total industrial power demand.

Figure: Open access renewable capacity addition, MW

Source: BRIDGE TO INDIA research

But we need to wait to see how states react to the changes. Our concern is that the MOP has completely disregarded core concern of DISCOMs, who need corporate consumers to maintain profit margins and business solvency. A unilateral policy announcement without any consultation with states faces a high risk, as we have seen all too often, that the states may simply disregard the rules. There is also some ambiguity over authority of the central government to issue such rules. It is unclear if they are binding on states since all open access implementation decisions fall under the purview of local policy and regulatory jurisdiction. Our initial discussions with MNRE and couple of state government officials suggests that actual on-the-ground progress is likely to be gradual.

Progress would also be affected by transmission capacity constraints. The 15 day project approval timeline seems impractical as state transmission companies and DISCOMs need more time to complete load flow analysis and consider additional infrastructure requirements for new generation capacity. Moreover, small consumers will generally struggle to deal with intricate financial and operational requirements of open access procurement.

Notwithstanding these concerns, liberalisation of the open access market, coming after last year’s announcement of ISTS charge waiver, is highly encouraging. Focus now should be on implementation and getting states on board.

Open access and rooftop solar can potentially meet only about 40-50% of a corporate consumer’s power requirement due to a temporal mismatch between supply and demand. Consumers keen to increase share of renewables in their consumption mix to achieve decarbonisation goals must therefore find alternative sources. Unfortunately, some of the key options to address intermittency risk of renewable power are not deemed viable. Banking power with the grid is increasingly not possible as DISCOMs and state regulators make such provisions more restrictive. Deployment of battery storage at scale is still not cost effective particularly with growing shortage of key raw materials and increase in prices. In light of these developments, role of the green power exchange to meet consumer demand becomes potentially very significant. It can also be a useful option for consumers not keen on or unable to sign long-term PPAs.

Green power trading has grown significantly in the last two years. Coal shortage and increase in price of thermal power are providing further impetus to this market. The Ministry of Power move to exempt ISTS charges for all power traded on exchanges until June 2025, yet to be approved by CERC, is also helpful in this regard. This market has attracted strong buying interest from both DISCOMs and consumers (Vedanta, Jindal Steel, SAIL among the top participants).

Different market segments Amongst the different instruments – ranging from intra-day to weekly delivery – for trading power on the exchanges, the Green-Day Ahead Market (G-DAM) for next day delivery is the most active (see chart below). Demand and traded volume have been higher (24%) than the Green-Term Ahead Market (G-TAM) which enjoys priority in transmission capacity allocation and longer trading duration. Within G-TAM too, bulk of trading volume is seen in day-ahead and intra-day markets due to shorter forecast horizon and low risk of deviation penalties.

Figure: Trading volume and prices on green power exchange in April 2022

Source: Indian Energy ExchangeNote: Indian Energy Exchange accounts for about 95% share of total renewable power traded on the exchanges.

Lack of liquidityDespite steady pick up in trading volumes, total green power trading volume is still relatively small. Only 3% of total renewable power output (5.5 TWh) renewable power was traded on the exchanges in FY 2022. This is mainly due to lack of untied capacity. Selling interest is confined mainly to a few DISCOMs that have contracted renewable power in excess of their RPO requirements and projects with generation surplus to their PPA requirement.

Volatile power pricesTrading power on exchange exposes consumers to price volatility. Traded prices increased sharply from INR 5/ kWh in Feb 2022 to more than INR 9/ kWh in March 2022 due to jump in demand and limited thermal supply. It is worth noting that prices are lower around mid-day than at other times. Consequently, consumers looking to sell any surplus solar power during the day and buy power at other times to match their demand profile face a negative price differential. This difference is bound to get worse as more solar capacity gets added in the country.

Green power trading market is expected to grow and mature over time. Perhaps the most encouraging aspect is that many project developers are looking to build projects on a pure ‘merchant’ basis or with short-term PPAs. To benefit from this option, consumers must develop better in-house capability to predict their forward demand and trade power on the exchanges.

ReNew announced acquisition of a 528 MW wind and solar portfolio spread over eight states earlier this week. This transaction, eighth such acquisition by ReNew, takes its total portfolio to over 12.8 GW including projects under construction. In another significant transaction, JSW has entered exclusive discussions to acquire Mytrah’s 1,898 MW wind-weighted portfolio. The two transactions are indicative of how local project developers are consolidating their position in an otherwise heavily crowded market.

The project development business is structurally wide open with low entry barriers and easy access to capital. New players continue to enter the fray and enjoy reasonable success as seen by track record of O2, UPC, Rising Sun, Solar Pack, Powerica, Hinduja, AMP, IB Vogt, NHPC, SJVN and Evergreen amongst others. Astonishingly, there have been 42 unique winners in tariff auctions greater than 100 MW since 2019. Notwithstanding the intense competition, we see nine local developers breaking out and establishing a dominant position.

Six developers including Adani, ReNew, NTPC, Azure, Greenko and Tata – with total portfolio of over 6 GW each – are the runaway leaders. Their aggregate share of total operational capacity is only 31% but the share jumps to 54% for pipeline capacity. Three other developers – Avaada, Ayana and JSW – are somewhat behind with portfolios of around 2-3 GW each but they also enjoy strong momentum.

Figure 1: Portfolio capacity and share of six leading project developers

Source: BRIDGE TO INDIA research

International developers, other investors lie lowAll top nine developers are India-based IPPs with a mix of ownership including Indian conglomerates (Adani, Tata, JSW), platforms backed predominantly by financial investors (ReNew, Greenko, Azure, Avaada, Ayana) and public sector (NTPC). International developers have struggled to sustain the business in view of low returns, aggressive bidding, high offtake risk, policy uncertainty and execution challenges. Most other developers are forced to go slow too for same reasons, while some others are intent mainly on a short-term portfolio rotation strategy.

Portfolio mix The portfolio strategy of top developers is quite varied. NTPC and Tata have been the most aggressive in new auctions since 2019, while Adani (5.8 GW acquired capacity), Greenko (3.7 GW) and ReNew (3.0 GW) have been relatively more active on the acquisition front. For Adani and Azure, bulk of their auction wins have come from the 12 GW manufacturing-linked tender.

Most notably, the leader group is happy to accept DISCOM offtake risk despite increasing concerns about their financial status. Portfolios of ReNew, NTPC, Greenko and Tata are heavily weighted towards direct DISCOM offtake. Adani and Azure stand out in this regard with 80% and 82% of their portfolio contracted with central government entities. ReNew, Greenko, Tata and Azure have significant plans to ramp up corporate renewable business.

Figure 2: Portfolio breakup of leading developers

Source: BRIDGE TO INDIA researchNote: Portfolio size excludes open access projects under construction. NTPC’s 3.7 GW project wins under CPSU scheme are shown under state DISCOM offtake.

Looking ahead, we expect the dominance of the nine leading developers to gain even further momentum as scale provides crucial ability to withstand short-term market shocks. Their combined share is expected to settle at around 60%.

In the last three years, there have been a total of 33 M&A or private equity transactions exceeding USD 100 million in size in the renewable IPP business. Total investment value of these deals is estimated at USD 12 billion indicating strong lure of the sector. Investors include companies of all hues including oil & gas major (Total, Shell and GPSC), PE funds (Blackrock, Actis, Brookfield, KKR, Mubadala), pension funds (CPPIB, CDPQ, OMERS) and IPPs themselves.

Table: Key M&A and private equity transactions since May 2019

Source: News reports, investor presentations, BRIDGE TO INDIA research

With some notable exceptions (Adani Green, Tata Power), valuations have typically hovered around 9x EBITDA. We estimate that these valuations are equivalent to SPV level post-tax equity IRRs of sub-9% for the incoming investors. At a fundamental level, this return is inadequate even for a ‘de-risked’ portfolio with central government offtake and 1-2 years of operational track record. We are in uncharted territory particularly with long-term resource availability and operational performance risks. But easy liquidity has depressed returns across the market and pushed up valuations on purely technical grounds. Whether this is a satisfactory level of return depends on many other factors.

A case could be built for paying entry premium in a fiercely competitive and rapidly growing sector with multi-decadal growth prospects. In particular, the financial investors – the most dominant investor class – are happy to just get a seat on the table. Investors also seem willing to pay a premium for organisational learning and expertise in building and operating projects besides accounting for accretive option value arising from emerging businesses like storage and green hydrogen.

On the flip side, utility scale project development is a highly commoditised business with open source, easily accessible technology and operational expertise. Moreover, with new business won mainly through fiercely competitive auctions, the possibility of earning premium returns is likely to remain remote. On the contrary, returns are being progressively squeezed. Ability of relatively new players like Ayana (total portfolio including under construction assets 2,367 MW), O2 (1,330 MW), AMP (969 MW), Axis (854 MW), UPC (620 MW), Aljomaih (450 MW), Evergreen and Solarpack (300 MW each) to ramp up the business neatly buttresses these arguments.

We believe that the valuation cycle has peaked. As central banks tighten liquidity and supply side restrictions eat into returns, investment sentiment is set to moderate over the next few years.

Two weeks ago, I had an opportunity to visit the 750 MW solar PV cell and module plant owned by Premier Energies in Hyderabad. Construction of this plant, India’s second largest, was completed in a record 15 months and full operations commenced in July 2021. It is worth noting that this is the first greenfield PV cell plant to have been completed in India since commencement of operations by Mundra Solar’s’ 1.2 GW plant in 2017.

Premier Energies entered solar manufacturing business in April 1995 with a 3 MW module assembly plant, also located in Hyderabad. The 750 MW cell-module plant, costing INR 4.8 billion (USD 63 million), was financed 75% by debt from IREDA. Equity contribution came in from internal funds and INR 2 billion investment from GEF Capital, a global private equity fund. The company is now expanding capacity with a new 1.25 GW mono-PERC cell-module line with a capital expenditure of INR 7.6 billion (USD 100 million) on the same site. The new line is expected to be operational by December 2022.

Figure: Select images of the manufacturing plant

Source: Premier Energies

The cell-module line, costing about 50% of total capital cost, was imported from China while all utility and ancillary equipment were designed and procured locally. Sustainability was a key consideration with the company designing all process equipment to ensure zero liquid discharge, 100% rainwater harvesting and waste management. As much as 95% of total water used is recycled back in operations.

Unfortunately, the company is still nearly fully dependent on imports of all key components including wafers, backsheets, EVA sheets, glass, aluminium frame, encapsulants and junction boxes because of limited production capacity and high cost of domestic suppliers. Imports are estimated to account for about 40% of the total sale value of a module.

The 750 MW plant can be deemed a great success. It is now operating 24×7 at about 80% capacity utilisation level with 1,200 people employed in full-time roles. The plant has produced about 200 MW and 350 MW of cells and modules so far. The semi-automated cell line, currently producing multi-crystalline cells, is now being upgraded to produce mono-PERC cells with wafer sizes of up to 210 mm. With the government’s strong focus on ‘Make in India’ and various demand creation measures, the cell capacity is completely sold out for the next 12 months. The module line is producing both multi-crystalline and mono-PERC modules using imported cells. The company now produces both mono- and bi-facial modules ranging between 300-550 W in size. It is even considering a backward foray into wafers to win a bigger share of manufacturing business slice.

Some of the cell output is sold to other domestic module manufacturers, while module sales are split about 50:40:10 between sales under Premier Energies brand name, OEM sales to other companies and exports respectively. The company has considerably reduced its EPC business to completely focus on the manufacturing business. It has successfully capitalised on the domestic manufacturing opportunity by making necessary investments at an opportune time ahead of its much larger competitors.

This video presents a summary of major sector developments including tender issuance, auctions, policy and regulatory developments, financial deals and related market trends in January 2022.

Soaring costs and aggressive competition for new projects have made it a tough time for project development business. Module costs have edged down from the exceptional highs of around USD cents 0.30 in November to USD cents 0.27 but are still up about 16% over prices a year ago. Shipping freight rates, aluminum, copper and steel prices are also relentlessly firm. Total solar EPC cost, excluding safeguard duty, is up 18% YOY at INR 32.62/ Wp. As against this, tariffs for SECI offtake projects have increased by only 9% YOY for projects in Rajasthan.

Rupee debt funding cost has fallen to all-time low of 7.50-8.50% for high quality renewable projects;

Squeezed between rising costs and strong competition, project developers have reduced their return expectations;

Construction and financing cost risks are getting underpriced in the process;

Imposition of BCD from April onwards is going to be another financial challenge for projects where there is no clear formula for change in law compensation. Then there is the issue of project delays and/ or additional cost of adding bird diverters to transmission lines in protected areas in Rajasthan and Gujarat as per the Supreme Court order.

Figure: Auction tariffs vs EPC cost for solar projects

Source: BRIDGE TO INDIA research

Against this backdrop, fall in lending rates by government-owned institutions, Power Finance Corporation (PFC) and Rural Electrification Corporation (REC), has come as a major relief. The two institutions announced a 40 bp reduction in January for lending to renewable projects. Together with some public sector banks, they are providing up to 20-year funds at an all-in cost of around 8.50% and 3-5 year funds at a fixed cost of around 7.5%. This is probably the cheapest cost project finance debt seen in the last ten years.

Fall in debt cost has allowed developers to improve effective leverage to well over 80% for operational projects and relieved pressure on equity returns. Investor return expectations have also come down. In particular, PSU developers like NTPC, SJVN and NHPC are operating with equity returns of about 10% for greenfield projects. Some other quasi-sovereign developers and international utilities too have reduced their return expectations to around 11-12%. Other developers, accounting for about one half of the project development business, have no choice but to accept the market reality.

For operational projects with SECI offtake and ISTS-connectivity (quasi-sovereign offtake, no construction risk, no curtailment risk), 11-12% return – implying a risk premium of about 5% for long-term government debt – could be argued to be reasonable on a risk-adjusted basis. On the other end of risk matrix, for unbuilt projects with offtake by poorly rated DISCOMs (Tamil Nadu, Uttar Pradesh, Haryana and Bihar, for example) and state transmission connectivity, return expectations would be much higher at about 18%.

The trouble is that there is no buffer available in these return levels for the substantial construction price and time risk. Second, almost inevitably, debt market rates would go up as central banks start tightening monetary policy in response to rising inflation and growth. If EPC cost comes down by about 15% in the next 12 months, most of the pipeline projects bid at around INR 2.20/ kWh would be viable. Otherwise, as seen with the 600 MW Acme-Scatec project, many of these projects risk being shelved.  

NTPC completed EPC auction for 3 x 245 MW solar projects based in its Nokh solar park in Rajasthan last week. The tender attracted strong interest from a mix of existing (L&T, Sterling & Wilson, BHEL, Jakson) and new players (Amar Raja, Premier Energies, Rays Power Infra, Axis Energy, BVG and NTPC GE Power, an NTPC-GE JV). L&T, Amar Raja and Jakson have emerged as the three winners. Interestingly, NTPC excluded modules from EPC bid scope for the first time in this tender, which otherwise includes complete project design, engineering, procurement, construction and O&M for a period of three years.

NTPC is following large private developers in pruning EPC scope in a bid to keep costs low and maintain control on execution timelines and quality;

Most leading EPCs have struggled to earn profits in the face of static business volumes and spiralling execution costs;

The market remains fiercely competitive with many new players in the fray;

Facing significant delays and cost uncertainty on many under construction projects, NTPC is trying out a mix of alternate procurement approaches (only BOS-EPC, land plus BOS-EPC, individual BOS procurement). It is slowly but surely following large private developers (examples, ReNew, Adani, Azure, Avaada), who rely mainly on self-EPC in a bid to keep costs low and maintain strict control on execution timelines and quality. In any case, commoditised nature of services and severe commercial pressure mean that even where project developers outsource EPC, they leave little margin on the table.

With business volumes largely static and execution costs shooting up, the solar EPC business is undergoing a transformation. Profit margins, 2-3% in the best of times, have disappeared. Sterling & Wilson Solar, a leading solar EPC contractor both in India and worldwide, reported net loss of INR 3.6 billion (USD 48 million) in H1/ FY 2022 (see table). As per the company’s press release, “Gross margins (were) impacted significantly on account of unprecedented increase in execution costs and increase in modules, commodities and freight costs.” The company also had bank guarantees equivalent to INR 4 billion (USD 54 million) encashed by three customers because of execution delays.

Table: Financial results of Sterling & Wilson Solar, INR million

Source: Sterling & Wilson Solar investor presentations

Amid all the market turmoil, some established players have exited the EPC business (Mahindra, Juwi), while others have become more selective. But as the NTPC bid results show, new players continue to be attracted by high growth prospects. KEC (a transmission and electrical services contractor) and Ashoka Buildcon (roads and civil construction EPC) are two other prominent names eyeing an entry.

Figure: Market share of EPC contractors, Jan 2020-Sep 2021 (total 7,597 MW)

Source: BRIDGE TO INDIA research

Overall, business fundamentals appear unattractive because of relatively low growth, intense competition and low margins.

Listed renewable IPP stocks have taken a battering in the last few months. ReNew stock touched a low of USD 5.65 this week after listing on NASDAQ in August 2021 at USD 8.50, a fall of 33%. Azure stock fell from a high of USD 48.39 in January 2021 to USD 15.55 this week, a fall of 70% in one year. Both stocks are down between 36-44% over the broader indices in the last four months. Another prominent listed stock, Sterling & Wilson, has done relatively better but that could be partly attributed to Reliance announcing a 40% investment stake in the company in October 2021. Nevertheless, the stock is still down 48% over its issue price, in just two years since its IPO.

Falling module prices and interest rates policy have inured investors to growing risks in the sector;

Monetary tightening poses a major short-medium term risk for project developers and capacity addition prospects;

The government must find a way to correct course on power distribution and policy fronts to ease the impact of financial volatility;

The biggest reason for the price crash is proposed monetary tightening by the US Fed in response to inflation concerns. Financial markets have been kept afloat in the aftermath of COVID by the extraordinary monetary stimulus provided by central banks. But as inflation escalates owing to supply side disruption and demand pick up, and rates tighten, yield expectations are going up. Investment sentiment towards renewables has also turned negative for a couple of other reasons. Future of the fiscally expansionist US Build Back Better Bill, which earmarked USD 555 billion in federal government spending towards renewable energy and clean transport incentives, seems uncertain. The Bill is being pruned down over affordability concerns. The market is also anxious over module cost spikes caused by supply side disruption in China and various direct and indirect trade barriers. As a consequence, international renewable stocks have fallen precipitously across the value chain. But the Indian stocks seem to have fallen by a relatively higher proportion. Valuations are more reasonable now at about 8-9x EV/ EBITDA but the if the market sentiment remains negative, prices may stay depressed for some time.

Figure: Relative stock price movement against US and Indian indices (2021)

Source: BRIDGE TO INDIA research

We have maintained for some time that investment sentiment in the sector has been fired by twin engines of falling module prices and interest rates. Despite a plethora of policy and viability risks, these two factors have sustained investment appetite and boosted valuations. A negative outlook on both fronts therefore has dreadful implications. The disconnect between investment euphoria and ground level reality seems to be disappearing. Many developers including Tata Power, NTPC, JSW Power and Sembcorp, amongst others are aiming to list their renewable businesses in the near future. Valuation compression could make raising capital extremely difficult and threaten plans to scale up activity by 3-4x in the coming few years. Although the government is bound to ignore stock price movements, depressed valuations should be food for thought for the policy makers. By correcting course on distribution side reforms and providing policy certainty, the government can ease the impact of financial volatility.

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PS The other major listed renewable stock, Adani Green, mysteriously remains immune to market movements. Since September 2021, the stock has gained 80% to reach market cap of USD 41 billion, which defies all logic.

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

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

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

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

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

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

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

Figure 4: Capacity addition under REC mechanism, MW

Source: REC Registry of India

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

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

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

Key terms of the tender are listed below:

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

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

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

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

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

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

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

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

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

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

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

Last week, SECI concluded auction for procuring 2.5 GW round-the-clock (RTC) power. The tender mandates that at least 51% of power shall be supplied by a combination of solar and wind sources including storage while the balance may come from any one non-renewable source. Winners include Hindustan Thermal (250 MW, tariff bid of INR 3.01), Greenko (1,001 MW, INR 3.18), ReNew Power (600 MW, INR 3.19), Power Mech (550 MW, INR 3.30) and JSW (99 MW, INR 3.45).

The tender, originally issued in March 2020, went through a series of changes in response to industry demands and issuance of competitive bidding guidelines for RTC power. There were stiff conditions for the bidders:

Minimum 85% CUF or annual availability as well as a requirement to despatch power during any four ‘peak’ hours in a day as designated by the Regional Load Despatch Centre (RLDC) – with a penalty of 400% of applicable tariff for not fulfilling either of these conditions;

Constant share of RE:non-RE power and no change in source of coal (domestic/ imported), if applicable, throughout the 25-year PPA term; and

Commencement of power supply within 2 years – RE power should come from new greenfield plants (solar and/ or wind) while conventional power may be supplied from existing plants.

Tariff bids were required to have four components – fixed components for RE and non-RE power respectively, and variable components for fuel and transportation cost of non-RE power. Curiously, the bidders were also allowed to quote different fixed components for different years. Projects would be allocated on the basis of weighted average levellised tariff, computed as per CERC guidelines subject to bidders matching L1 bid. We understand that SECI has asked all bidders to match the lowest bid and submit revised tariff matrices. This process is expected to take at least a month before project capacities can be finally awarded.

As the following chart chows, the tender was oversubscribed 4.6x with many thermal power producers in the fray.

Figure: Winners of SECI 2.5 GW RTC auction

Source: BRIDGE TO INDIA research

In the previous RTC tender (400 MW, awarded to ReNew in May 2020, fully contracted by Delhi, Daman & Diu, and Dadra & Nagar Haveli DISCOMs), the winning bid had a levellised tariff of INR 3.56. Since then, prices of modules and wind turbines have shot up by 10-30% and the government has proposed a considerable hike in taxes and duties. It is therefore hard to understand how bids of INR 3.01-3.45 can be viable.

The range of winning bids is fairly large and we expect all bidders to be unable to match the L1 bid. As bid security requirement is now dropped in all new tenders, there is unfortunately no way to hold bidders accountable. We therefore see a big question mark over prospects of any projects going ahead under this tender. Tendering process needs more rigour to retain legitimacy.

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 described as the perfect storm. A mix of global economic rebound after COVID demand slump and trade disruptions has sent energy prices skyrocketing. International prices for coal (USD 150/ tonne), natural gas (USD 5.7/ MMBTU) and crude oil (USD 75/ barrel) have surged by as much as 15% in the last month to reach annual highs.

Figure: Prices of coal, crude oil and natural gas, USD

Source: BRIDGE TO INDIA research

In parts of China, power consumption is up over pre-pandemic levels by as much as 15% and is set to escalate further with onset of winter. Supply situation has worsened due to curbs on Australian coal imports and heightened safety protocols after a series of industrial accidents last year. Recent attempts to rebalance the economy away from fossil fuels and a new commitment to cut carbon intensity, by more than 65% from 2005 levels by 2030, have aggravated the crisis. China has begun rationing energy to provinces and is setting them consumption reduction targets. According to a leading Chinese module manufacturer, manufacturing operations have been curtailed at over 1,000 companies since last month – hampering output across the solar value chain.

Struggling to cope with curtailed power supply and higher costs, solar manufacturers are both cutting back production volumes and raising prices. Silicon prices have risen by 147% month-over-month, while polysilicon prices have moved up by a further 40% in the same period. EVA sheets, in short supply, have seen a 33% price increase over previous month. Manufacturers are quoting mono-crystalline module prices at USD cents 28/ W, up more than 10% since July 2021, although supply timetable is far from clear. China-India freight costs have jumped up even further to USD 9,000 per container, up over 10x in just over a year.

Figure: Spot prices of mono-grade polysilicon, wafers, cells and modules, USD

Source: PV Infolink, BRIDGE TO INDIA research

Five leading Chinese module manufacturers have issued an unprecedented call asking their customers to delay project timelines. Indian project developers have received force majeure notices intimating them about delayed shipments and higher prices on already signed contracts.

We estimate that Indian developers are planning imports of about 6-8 GW over the next six months ahead of BCD implementation. It is a desperate situation for these developers – escalating costs, no clarity on timelines, delays adding to further costs and, risks of penalties and additional duties. The crisis seems likely to last until Q2 2022 with huge uncertainty ahead on project execution timelines as well as costs. Blindsided by these developments, the developers are planning to seek relief from government on both fronts.

Some analysts have blamed China for the negative turn of events, but we believe that there are many other factors including economic and policy volatility, trade barriers and energy transition contributing to the crisis. Boosting domestic solar manufacturing capability would help but renewable sector should, in general, be better prepared for greater uncertainty ahead.