Category: Market Outlook

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.

MNRE has expanded scope of the ALMM policy by bringing open access and rooftop solar projects under its purview. As per an order released last week, all open access and net-metering based projects applying for approval from 1 April 2022 onwards may procure only modules approved under ALMM policy.

The ambiguous order has created confusion in the already struggling distributed renewables market;

So far, MNRE has approved only 10.9 GW of module manufacturing capacity and nil cell manufacturing capacity under the policy;

ALMM is a flawed policy concept as it restricts competition, promotes inefficiency and increases costs for consumers;

MNRE has clarified in the past that only Indian manufacturers would be approved under ALMM. But utility scale solar projects bid before 9 March 2021 – 42,491 MW of pipeline – would continue to import modules as they are exempt from both ALMM and BCD. The policy scope has therefore been widened to open a new demand source for domestically manufactured modules.

There are, however, some major discrepancies in the MNRE order. The meaning of “apply for open access” is not clear since open access projects require multiple approvals from different agencies. The lead time of 2.5 months given to such projects is also inadequate as some projects may have already procured, or be in advanced stage of procuring, modules particularly as the Basic Customs Duty is expected to kick in on all imports from April 2022 onwards. Finally, rooftop solar systems are installed in many alternative configurations (gross metering, net billing, or non-grid connected) without net metering benefit. Exclusion of such systems from policy coverage seems to be an oversight. The MNRE order has left a trail of confusion and we expect to see a series of amendments and clarifications in the coming months.

There is another fundamental issue with the new order. So far, MNRE has approved 38 module manufacturers with total manufacturing capacity of 10.9 GW under the ALMM policy. No cell manufacturing capacity has been approved yet. In any case, total estimated domestic cell manufacturing capacity of 3.5 GW is highly insufficient to meet market demand. Commencement of commercial operations by new cell and module manufacturers is expected to take minimum 2-3 years. It is therefore not possible for project developers to comply with the ALMM policy during this period.

Table: Approved module manufacturers under ALMM policy

Source: BRIDGE TO INDIA research

The government has already undertaken a series of measures to promote domestic manufacturing – BCD, domestic content requirement for PSUs, agricultural solar and residential rooftop solar, Production Linked Incentives, manufacturing-linked project development tender, and tax rebates. In the backdrop of such extensive multi-faceted support, the ALMM policy is irrelevant. Moreover, the government’s intent to deny approvals to foreign manufacturers or creation of a walled garden, is akin to a tax on consumers. It restricts competition, promotes inefficiency and increases costs for consumers. If the policy continues to be implemented in its current form, it also runs the risk of international trade litigation and retaliatory measures by other countries.

Here’s wishing all our subscribers a very happy new year. We hope that the new year brings good health and better tidings all around. Last two years have been tough for the sector with sharp cost rises, COVID, extensive project delays, muted power demand, worsening of DISCOM financial position and Supreme Court order on moving high voltage transmission lines underground. Our early estimate for total capacity addition in 2021 is 11.2 GW, split between utility scale solar – 7.8 GW, rooftop solar – 1.8 GW and wind – 1.6 GW, 30% below our projection for the year. As we look to the new year, good news seems to be in short supply unfortunately as third wave of COVID rages around and cost pressures look set to continue. Here’s how we expect the new year to unravel.

Levy of Basic Customs Duty (BCD)A final announcement on BCD is expected as part of budget release on 1 February 2022. While there is still some uncertainty in the timetable with MNRE being sympathetic to developer demands for delaying imposition of duty, we understand that the duty is set to be levied, as expected, from April 2022 onwards. If that happens, the distributed solar business – both rooftop solar and open access – would take an immediate hit. Utility scale solar projects, already stuck because of the Supreme Court’s transmission order, would also be impacted adversely because of negative cash flow impact.

Only gradual relief in module and other input pricesThe softening process in module supply chain has already begun. But there is still considerable uncertainty on power supply situation in China and global demand is expected to pick up sharply with 2022 shipment estimates ranging between 170-220 GW. Any decline would most likely therefore be slow and relatively small. We expect mono-PERC module prices to ease off to about USD 0.25 levels by end of the year. Meanwhile, other commodity prices are expected to stay firm.

Feeble capacity addition Capacity addition prospects would depend greatly on timeline for clarity on transmission lines in Rajasthan and Gujarat. Many projects have already got force majeure relief on account of module supply disruption. We estimate total 2022 renewable capacity addition at about 10 GW, down 10% YOY.

No major change on auction and tariff frontSECI finally began to clear backlog in unsigned PPAs towards the end of last year. Barring the 5 GW CPSU tender and 2.5 GW conventional hybrid tender, where we anticipate relatively little progress, total project allocation in 2021 stood at 15.4 GW, down 42% YOY. We expect pace of new auctions to stay relatively lukewarm and bid tariffs for central government offtake projects to stay in the INR 2.10-2.40 range. A key event to look out for in the year would be progress on the 1 GWh standalone storage tender by SECI.

‘Make in India’ boostClarity on BCD and proposed expansion of PLI scheme to cover all bidders would provide big boost to domestic manufacturing efforts. It would be a major change to see industry nucleus shifting away from project development to manufacturing although we expect only about 8-9 of the 16 bidders to finally go ahead with their proposed plans because of overcapacity and viability/ financing concerns. Battery and electrolyser manufacturing schemes are expected to be take much longer to take off.

Tightening in financial markets The US Fed has just signalled liquidity tightening in response to high inflation and booming economy. Globally listed renewable stocks have already tumbled. Financing conditions are expected to become significantly more challenging with higher cost of capital across the board.

End to PPA renegotiation efforts It has been nearly 30 months since Andhra Pradesh sought to renegotiate and/ or terminate all renewable PPAs. The case has been stuck in the High Court for multiple reasons but due for final hearing in January. It is widely expected to be resolved in favour of the developers. We believe that Punjab’s renegotiation attempt should also fail after a successful legal challenge by the developers.

Sector reforms After dithering over many years, can the government gain political will needed to implement much needed sector reforms? The Electricity Act amendments are still awaiting Cabinet approval and even though the DISCOM financial position is becoming unsustainable, we expect another year of muddling through.

As 2021 draws to an end, we look at major developments that shaped the renewable sector. It was a nervy year, beginning with a severe second COVID wave followed by an unexpected disruption in module supply chain sharply hitting project viability and execution. These are our top developments of the year and their impact on the sector.

Module prices shoot upFor the first time ever, module prices increased month on month through the whole year. After the lows of US cents 18/ W last year, mono-crystalline module prices went up steadily to US cents 25 through June and then shot up to US cents 30 as Chinese government clamped down on power consumption and shut factories. Expiry of safeguard duty in July eased the pressure only partly. Profitability of projects under construction was hit hard leaving developers with a tough choice – complete construction now with higher cost, renegotiate contracts where possible, or delay completion to next year at the risk of facing delay penalties.

Domestic manufacturing takes offBorder conflict with China and COVID strengthened the government’s resolve to boost domestic manufacturing. After years of dithering, a series of decisive moves on ALMM, BCD and PLI were announced to support manufacturing. The government appears keen to give a nod to all 18 bidders in the PLI scheme with an aggregated bid capacity of 54.8 GW. India could finally have 30-35 GW of cell and module manufacturing capacity and 3-4 fully integrated manufacturers in the next five years.

Reliance makes a smashing entryFollowing up on its mega announcement in June, Reliance made a series of striking deals heralding its entry in the clean energy sector. The company would bring down costs for consumers and help accelerate overall sector growth with its unparalleled financial might, access to latest technology, scale, complete backward integration and large captive market. Manufacturing and installation businesses are set for a massive disruption.

Big target gets bigger: 450 GW of renewable capacity by 2030At COP, the Prime Minister committed to ramp up non-fossil fuel based power generation capacity to 500 GW by 2030 and achieve net-zero emissions status by 2070. The revised target sits incongruously with on-the-ground scenario in terms of project execution (demanding), power demand (weak) and DISCOM finances (perilous). There is pressure now on the government to act explaining recent policy moves to extend IST waiver and liberalise C&I renewable market.

Foreign investors pile inLarge market size, liberal investment regime, hunt for yield and growing ESG investment theme have made India’s clean energy sector a magnet for capital providers. Easy liquidity conditions and falling cost of capital helped mitigate various operational and financial obstacles. There were notable new investments in the year by Total (Adani), Thailand’ PTT (Avaada), Scatec (Acme project), Augment (CleanMax), Norfund (Fourth Partner), SHV (SunSource), Copenhagen Infrastructure (AMP) and Omers (Azure), amongst others. ReNew successfully completed its US listing with a USD 610 million fund raise, while there were green bond issuances totalling USD 3.5 billion by Adani, ReNew, Azure, Continuum, Hero and Acme.

The DISCOM problem remains intractableFinancial condition of DISCOMs deteriorated even further as costs climbed up but state governments refused to hike tariffs. All key reform measures including the USD 12 billion liquidity injection scheme, a new USD 40 billion operational reform scheme, privatisation, delicensing and Electricity Act amendments failed to make any meaningful progress. Outstanding payments to power producers are near record highs with at least six states falling behind on payments to power producers by more than a year. Punjab became the second state after Andhra Pradesh to renegotiate tariffs on all operational renewable projects.

Table: Key developments in 2021 and their impact on value chain

It has been a momentous year for the sector. Despite major setbacks, the outlook is better than ever before and pace of energy transition continues to get stronger. We wish you a merry festive season and a very happy new year! Hope you have a restful break. We look forward to seeing you in 2022.

The Ministry of Power has offered a series of concessions on waiver of Inter-State Transmission System (ISTS) charges and losses. The most significant concession involves extending the waiver to open access projects – both third-party sale and captive use. The 100% waiver for ISTS charges over 25 year project life would now apply to all solar, wind, pumped hydro and battery storage projects completed by 30 June 2025 irrespective of end use of power or project allocation process. For projects completed past this date, the charges would be levied in a staggered manner based on project COD (see table below). ISTS losses (about 3-4%) would also be waived in full for projects auctioned by 15 January 2021. Minimum renewable power input threshold for pumped hydro and battery storage projects to claim ISTS charge waiver has been reduced from 70% to 51%.

Table: Timeline and quantum of ISTS charges for renewable projects

Source: Ministry of Power notification

As per another amendment, projects where scheduled COD deadline has been extended beyond 30 June 2025 due to force majeure or unavailability of power evacuation infrastructure shall also be eligible for 100% transmission charges waiver. Moreover, the waiver of short-term open access charges for storage projects would now apply to both charging and discharging (only charging cycles, as per earlier notification).

Hitherto, only competitively bid projects selling power to DISCOMs were eligible for ISTS charges waiver. The concessions follow directly from the government’s keenness to spur renewable power growth in face of various slowdown risks facing the industry. DISCOMs have been reluctant to sign PSAs because of concerns around demand uncertainty and high landed cost of power. Some projects auctioned last year are yet to find willing buyers. Having consistently resisted demand for ISTS charge waiver for open access projects in the past, the government has now given in in the hope that industrial consumers can fill the demand void.

While some analysts are arguing that the waiver is a game changer for the sector, we believe that the move would have limited overall impact. One, it is likely to increase resistance from state governments and DISCOMs to open access project approvals even further. Two, the ultimate reduction in landed cost for open access power, net of ISTS losses and additional levies imposed by power producing states, would be relatively miniscule at about INR 0.20/ KWh, or just about 3-4% of total cost. Three, there is no provision of banking in the ISTS network. The real benefit would be restricted to few states like Haryana and West Bengal, where setting up large scale intra-state projects is not considered viable because of scarcity/ high cost of suitable land.

The waiver would favour utility scale project developers over their C&I specialist competitors. Someone setting up say, a 500 MW, project in Rajasthan as part of SECI tenders will find it much easier and cheaper to bolt on additional capacity for C&I consumers.

Addition in open access renewable capacity, currently estimated at 11,910 MW (solar 4,595 MW, wind 7,315 MW), has faltered in the last few years. But it would be far more preferable if the government focused on pushing through recent proposals to streamline project approval process and provide visibility on grid charges rather than providing financial incentives. Growth of ISTS waiver-based capacity would exacerbate execution challenges in hot spots like Rajasthan and Gujarat, and risks inviting opposition from states reluctant to bear the cost of these waivers.

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.

COP26 concluded on 13 November, 2021 with bitter disappointment. The conference was expected to provide a firm roadmap for cutting carbon emissions after the tentative goals agreed in Paris in 2015. But there were no binding commitments on emissions or phasing out fossil fuels, nor any conclusion on global emission standards or any agreement on climate financing from the developed countries.

A deal on carbon trading is being touted as one of the few significant achievements. The new unified ‘rules-based’ global carbon market is meant to allow countries and companies to partially meet their climate targets by buying credits from other countries (arising from their larger than expected emission cuts or carbon sinks). However, it is a complicated deal and seems far from perfect. About 320 million credits, each equivalent to a tonne of CO2, issued since 2013 may still be traded – diluting effectiveness of the initiative. India could be a major beneficiary because of its large accumulated stock of credits but the scheme implementation and enforcement framework is still far from clear.

As a growing economy with rising emissions and heavy dependence on coal, India was under heavy pressure to make concessions at the conference. The Prime Minister made five promises:

Expand total non-fossil fuel based energy capacity to 500 GW by 2030

Meet 50% of energy requirement from renewable sources by 2030 (previous target 40%)

Reduce total carbon emissions by 1 billion tonnes from now until 2030

Reduce the economy’s emissions intensity by at least 45% by 2030 over 2005 levels (previous target 33-35%)

Achieve net-zero emissions status by 2070

While many stakeholders have at least publicly lauded these statements, we find the vagueness and non-effectiveness of these promises disconcerting. Reference to ‘energy’ in the first two promises is a definite mis-statement – the reference ought to have been to ‘power’ instead. More significantly, India is set to undershoot the 2022 renewable power capacity target of 175 GW by a significant margin. Before coming up with ever more ambitious goals, there should have been a clear assessment of various issues plaguing the sector and a comprehensive plan for addressing those. In absence of such methodical planning, the promises appear hollow.

The deadline of 2070 for reducing net emissions to zero is worthless and insincere. Fifty years is simply too long a period to have any material benefit when the environmental need is so dire. GHG emissions must fall by 45% from 2010 levels by 2030 for global warming to be contained within 1.5°C above pre-industrial levels. In contrast, UNFCC predicts emissions to rise by 14% in the business-as-usual trajectory. The available emissions allowance to stay within 1.5°C temperature rise of 400 billion tonnes is being eroded by more than 10% every year.

It is often argued that alongside other developing countries with a relatively small quantum of historic emissions, India has a right to keep burning fossil fuels for its economic growth. But the situation is grim. Rather than delaying its net zero commitment to 2070, it would have been preferable if India had adopted a target of say, 2050, contingent on the developed countries fast tracking their commitments to 2035, and definitive financial support.

India has lost a valuable opportunity to take a leadership role in climate negotiations and prepare its businesses and citizens for a low carbon economy.

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, IREDA opened bids received under Production-Linked Incentive (PLI) scheme for solar module manufacturing. Jindal (bid capacity 4 GW, PLI bid of INR 13.9 billion), Shirdi Sai (4 GW, INR 18.8 billion), Reliance (4 GW, INR 19.2 billion) and Adani (4 GW, INR 36 billion) are the top bidders based on their technical score – computed using assigned rating matrix for level of vertical integration and total manufacturing capacity. First Solar (bid capacity 3.3 GW, PLI bid of INR 17.5 billion) was the only other company to bid with full backward integration. Since total subsidy budget is capped at INR 45 billion (USD 600 million), Jindal, Shirdi Sai and Reliance are the three eligible winners under the prescribed bucket filling methodology.

The tender was heavily oversubscribed with many new companies seeking an opportunistic entry into the manufacturing business;

Announcement of final winners is expected to be delayed pending government decision to expand the scheme;

Effective subsidy payout of about 6-7% of first five year revenues may not be sufficiently attractive for marginal bidders in view of strict performance conditions;

The tender was heavily oversubscribed (5.4x), receiving bids aggregating 54.8 GW from 18 participants. Interestingly, none of the three top bidders and six others have any prior experience in solar manufacturing. Most existing manufacturers (TATA Power, Waaree, Vikram, Premier, Emmvee and Jupiter) have bid only for cell-module capacity. There are only two international bidders – First Solar and CubicPV, both US-based.

Figure: Bids received under PLI scheme for solar module manufacturing

Source: BRIDGE TO INDIA researchNote: PLI bid amounts are not available for CubicPV and Jupiter Solar.

Announcement of final winners and PLI allocation is expected to take about three months as MNRE is believed to be seeking approvals to expand the scheme budget by up to three times. The intention is to accommodate all wafer and polysilicon manufacturing bids aggregating 32.3 GW capacity with total PLI bid amount of INR 152 billion (USD 2 billion) to realise complete self-sufficiency in module manufacturing. Some increase in budget should definitely be possible since government is very keen to scale up manufacturing and there are unused funds available from other PLI schemes. We continue to believe that overall fundamentals of the scheme are not attractive particularly for smaller bidders. Total effective subsidy payout (see box below) is estimated at only about 20% of capital investment with an average payment period of about 4 years after investment, or about 6% of revenues in the first five years of operations. In turn, the bidders are required to comply with strict conditions on implementation timetable, domestic value addition and technology with stiff penalties for failure to do so. The need to demonstrate equity funding availability (INR 24.2 billion, or USD 323 million, for a 4 GW polysilicon-module manufacturing bid) within three months of award is also expected to be challenging for many bidders.

Reliance, Adani, First Solar and L&T are the four most serious contenders. A few others are expected to review their decision after final government decision on scheme size and likely PLI allocation. But most others are likely to ultimately decide that it is not viable for them to set up new manufacturing facilities.

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.

Following up on its mega announcement in June, Reliance Industries (Reliance) has completed a series of acquisitions and investments heralding its entry in the clean energy sector. The company has: a) acquired 100% stake in Norway-headquartered solar panel manufacturer REC for an enterprise value of INR 58 billion (USD 771 million); b) bought a 40% stake valued at INR 28 billion (USD 372 million) in Sterling & Wilson, one of the world’s largest solar EPC and O&M companies; and c) announced strategic tie-ups with technology companies spanning grid storage, silicon wafer and electrolyser manufacturing.

REC is an integrated polysilicon-module manufacturer with a production capacity of 1.8 GW per annum. The company, one of the first to commercialise PERC and heterojunction technologies (HJT), is regarded as a pioneer in module manufacturing. Inability to compete with Chinese manufacturers on cost – manufacturing operations are split between Norway (polysilicon) and Singapore (cells and modules) – has restrained growth. But with trade protectionism rising and wide-ranging concerns about reliance on Chinese imports, business prospects are looking up. REC is considering plans to set up a 2 GW manufacturing plant in France and a 1 GW plant in the US.

The India-based Sterling & Wilson has expanded aggressively into 24 countries around the world including Middle East, Americas, Europe, SE Asia and Australia. Its business portfolio includes over 11 GW of commissioned and pipeline solar EPC capacity, 8.7 GW of O&M capacity and recent forays in wind-solar hybrid, storage and waste-to-energy sectors.

Other investments/ tie-ups entail relatively young companies with breakthrough technologies under development:

USD 144 million investment in Ambri, a US-based grid energy storage company working on alternatives to lithium-ion technology with more resilient batteries that can store power for up to 24 hours;

USD 29 million investment in Germany’s NexWafe, with a proprietary technology to produce ultra-thin low-cost monocrystalline silicon wafers by going directly from gas phase to finished wafers;

Cooperation agreement with Denmark’s Stiesdal, to make hydrogen electrolysers using Stiesdal’s innovative technology at a significantly lower cost than other prevalent methods and collaborate in development of other technologies for offshore wind energy, fuel cells, and long duration energy storage.

This week, Reliance also gave a first peek into its tangible plans. It is planning to set up a fully integrated 20 GW module manufacturing plant and commission a 3 GW solar power generating capacity for producing 400,000 tonnes of green hydrogen for captive use at its Jamnagar refinery and petrochemical complex. The company has already sought transmission connectivity for a 500 MW solar project.

The scale, breadth and pace of these deals are breath-taking. Reliance has (rightly) identified access to best-in-class technology as a key plank of its business plan. And it is using its deep pockets for acquisitions and strategic tie-ups to cut the lead time required to become an end-to-end player. All boxes to guarantee success – financial might, access to latest technology, scale, integration, large captive market, larger domestic market and favourable policy – are ticked off.

Reliance’s entry into the clean energy sector will bring down costs for consumers and accelerate overall growth. But its plans must be unnerving for some of the existing players. The company seems poised to disrupt manufacturing and installation businesses.

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.

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.