Category: Uncategorized

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.

————————-

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.

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.  

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.

India has been a pioneer in adoption of solar pumps at scale. The government has set a target of installation of 1.75 million solar agriculture pumps and solar systems for another 1 million grid connected pumps by 2022 under KUSUM programme with up to 60% capital subsidy. Progress, however, is lagging with only 272,700 pumps installed by December 2020. To better understand the market, BRIDGE TO INDIA hosted a live dialogue with Mr. Ramakrishna Sataluri, Chief – Products and Marketing at Tata Power Solar on August 10, 2021. The company is one of the biggest players in this market.

The discussion began with a brief outline of the scheme targets and slow progress. Mr. Sataluri believes that the scheme has faced many teething challenges but significant progress has been made over the past years. Unfortunately, lot of momentum was lost with COVID posing challenges in on-the-ground marketing and installation activities. But Mr. Sataluri expressed confidence that with the government fully committed behind the scheme, deadline of 2022 would be extended shortly. He sees the market growing about tenfold to 500,000 pump installations annually by 2025-26.

Chhattisgarh, Andhra Pradesh and Rajasthan have emerged as solar pump leaders during 2019-20.

Figure: Solar Pump installation by state up till December, 2020

Source: BRIDGE TO INDIA research Note: Data may exclude some installations under state schemes.

One of the major changes in the market is the way tenders are issued. Until about two years ago, most tenders were issued by state governments. Each tender had different technical specifications and size was typically small at less than 5,000 pumps. The tenders attracted participation mainly from local players resulting in inconsistent implementation and quality standards. Since appointment of Energy Efficiency Services Limited (EESL) as a central nodal agency, akin to SECI for utility scale solar projects, the tendering process has become more streamlined. EESL is now aggregating demand from various states and tender sizes have increased to as high as 3,17,975 pumps (equivalent to about 1,500 MW solar capacity). According to Mr. Sataluri, many other process changes including getting farmers to register their interest in advance, simplification of eligibility criteria and installation timelines have improved the market’s attractiveness and growth potential. The larger players like Tata Power and Shakti Pumps are also poised to fare better in the new dispensation.

Mr. Sataluri also talked about several core benefits for farmers including consistent supply of daytime power, higher productivity, improvement in groundwater levels, additional income through sale of surplus power to grid and physical safety. There was also a brief discussion on financing aspects. Mr. Sataluri mentioned that banks play a very crucial role but interest from mainstream commercial banks has been limited so far.

Amongst main challenges for the market, Mr. Sataluri cited low margins due to intense bidding process and high working capital. For instance, MNRE has specified benchmark cost for 5HP solar pumps as INR 445,000, however, prices fell to INR 404,000 in the recent EESL tender. He also mentioned that delays in subsidy payments need to be resolved. Improving these aspects including overall implementation and standardisation of documentation is critical for realising growth potential of the market.

MNRE has added three new companies – CEL (module manufacturing capacity 35 MW), Patanjali (70 MW) and Jakson (80 MW) – to the Approved List of Models and Manufacturers (ALMM). Total approved module capacity now stands at 8,350 MW among 26 Indian companies. The first list with 23 companies was released in March 2021. No foreign manufacturers or even domestic cell producers have been approved as yet.

All solar power projects awarded under government tenders with bid submission deadlines falling on or after 10 April 2021 must use only ALMM-listed cells and modules;

Lack of sufficient domestic manufacturing capacity poses risks to generation capacity prospects;

In view of BCD and other support measures announced by the government, ALMM seems an unnecessary hurdle;

To recap, the ALMM policy mandates that all solar power projects awarded under central, state or PSU tenders with bid submission deadlines falling on or after 10 April 2021 are required to use cells and modules approved as on the date of invoice. There is, however, inconsistency in implementation. Some tenders like REMCL 210 MW and MSEDCL 500 MW stipulate that modules may be approved by COD but other tenders (NHPC, GSECL) specify that modules must be approved as on bid submission date.

The delay in approval of foreign manufacturers was so far perceived to be because of delays in organising factory visits and documentation owing to COVID. But the Union Power Minister RK Singh has clarified the government’s intent with an extraordinary statement – “If you want to sell in India, you will have to set up manufacturing here. If you don’t set up manufacturing here, I can give it to you in writing that you will not qualify for entry into that approved list of models and manufacturers.” It is a shocking statement in many respects and shows that the government is prepared to go all out to promote domestic manufacturing even if at odds with stated policy and accepted international trade norms.

The Minister’s statement raises some disturbing questions. There is simply not enough domestic manufacturing capacity – India produced only 5,383 MW modules in the last 12 months as against average annual expected demand of about 16,000 MW. Many companies have shown interest in setting up or expanding current production facilities but this is going to take minimum 3-4 years particularly for cell capacity (about 80% deficit). Any constraint in module supplies would directly hurt generation capacity addition outlook. There is significant procurement risk ahead for developers. We expect that the government would ultimately relent and either give more time to developers for project completion or relax ALMM implementation timelines.

Besides, when the government is already proposing a massive tariff barrier (40% BCD on modules from April 2022 onwards) plus financial incentives for domestic manufacturers, what is the need for ALMM? Complete blockage of imports seems unnecessary and betrays lack of confidence in competitiveness of domestic manufacturing.

Figure: Other government measures to promote domestic manufacturing

A complete ban on imports would also be in contravention to international treaties and faces the risk of tricky trade disputes. India cannot hope for a thriving domestic manufacturing sector without a consistent, transparent and open regime for international trade.

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.

There has been a series of positive developments on storage front in the last three months which should hopefully kickstart a cycle of growth for the business in India.

India’s central power sector regulator, CERC, has allowed energy storage facilities to provide secondary and tertiary services. World over, ancillary services are the primary revenue source for standalone battery storage. In the UK, Dynamic Containment (DC) or frequency response service launched late last year has exceeded 400 MW of assets and its high average price should provide participants with a significant uplift in revenue. Response profile for DC effectively extends the Fast Frequency Response (FFR) service, thereby decreasing response time required from assets. In the European Union, the new automatic frequency restoration reserve (aFRR) is expected to become a noteworthy market for battery storage.

After the June announcement of a new production-linked incentive (PLI) scheme to develop 50 GWh domestic manufacturing capacity for advanced battery storage technologies, the government has also initiated moves to stimulate demand. The Power Minister R.K. Singh announced recently that the government intends to come out with bids for 4,000 MWh of storage for ancillary services. SECI has already issued a notice for development of a 2,000 MWh standalone energy storage capacity. Separately,  NTPC has invited an expression of interest for installation of 1,000 MWh grid-scale storage at its thermal plant sites across the country. NTPC intends to use thermal-cum-storage power to counter challenges posed by intermittency risk of large amounts of renewable energy.

Meanwhile, SECI has finally tied up PPAs for its 400 MW, Round-The-Clock (RTC) renewable power tender. Power would be purchased by DISCOMs in Delhi, Daman and Diu, and Dadar & Nagar Haveli. ReNew Power, the project developer, anticipates the project would require battery storage to supplement 1.3 GW renewable power capacity.

In another move, the Ministry of Power has waived inter-state transmission system (ISTS) charges for battery systems commissioned by 30 June 2025 provided that minimum 70% of their power requirement is met from solar and/ or wind power. ISTS charges for power supplied from such systems shall also be levied gradually: 25% of Short-Term Open Access (STOA) charges for first 5 years of operation, 25% increase every 3 years until 100% charges become applicable.

With limited prospects for new hydro or gas-fired generation, optimal sources to balance renewable power, storage is expected to play a critical role in decarbonisation of the power sector in India. As per the latest report by the US National renewable Energy Laboratory (NREL), storage could represent between 10-25% of India’s total installed power capacity by 2050. So far, the market has been slow to take off due to a number of financial and regulatory hurdles. Recent government and regulatory announcements are therefore highly encouraging.

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

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

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

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

Source: BRIDGE TO INDIA research

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

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

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

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

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

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

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

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

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

Source: BRIDGE TO INDIA research

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

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

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

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

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

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

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