Category: Market Outlook

BRIDGE TO INDIA estimates that new rooftop installations in 2021 touched a record high of 2,196 MW, up 62% over previous year. As of December 2021, total rooftop solar capacity is estimated at 8,988 MW, 18% of total solar capacity in the country. The increase came mainly from the residential segment, which contributed 746 MW in new installations (34% market share), an YOY increase of 108%. These numbers are highly encouraging, coming after 2 years of market decline, and in face of several acute challenges including 7% annual capex increase, modules shortage and net metering policy uncertainty in many states.

Strong residential demand The residential market, one of the most under-penetrated segments of the renewable sector, has been gaining momentum over last couple of years with steady improvement in implementation of MNRE’s revamped subsidy scheme. Recent relaxation of the scheme whereby consumers can choose any installer rather than being restricted to installers empanelled by state governments or DISCOMs should also help going forward. MNRE has so far sanctioned subsidy for 3,162 MW capacity (scheme target 4,000 MW), out of which 1,252 MW capacity has already been installed. Gujarat leads in total tender issuance (2,200 MW) as well as total installations (992 MW). It recently issued a 1,000 MW tender, the largest residential rooftop solar tender so far. We expect the market to accelerate further with total capacity crossing 10 GW by about 2027-28.

Figure 1: New installations by consumer segment, MW

Source: BRIDGE TO INDIA research

CAPEX trumps OPEX in the C&I marketGrowth in the corporate market has been muted in comparison. The larger consumers and solution providers seem to have shifted focus to open access projects in push for volume. And while high capex cost is a deterrent for many consumers, self-financed market is growing robustly. Share of the OPEX model has now been falling for three straight years.

Figure 2: C&I installations by business model, MW

Source: BRIDGE TO INDIA research

No sign of consolidation in the marketThe market remains keenly fragmented across regions, consumer segments and business models. Larger utility scale players like ReNew, Azure and Statkraft have exited the OPEX business but there seem few players able to grab the opportunity. Exceptions include Fourth Partner and Amplus in the OPEX business, and Tata Power, which has made impressive gains in both business models.

Figure 3: Leading players by installed capacity in 2021

Source: BRIDGE TO INDIA research

Hostile policy environment is affecting growthMaharashtra continues to be the leading state for C&I installations (254 MW capacity addition in the year), followed by Gujarat (173 MW), Rajasthan (138 MW), Andhra Pradesh (122 MW) and Karnataka (107 MW). The impact of regressive policy actions can be clearly seen in slowing market growth in Uttar Pradesh and Karnataka.

Figure 4: Annual capacity addition in major states, MW

Source: BRIDGE TO INDIA research Note: Data excludes residential installations.

The short-term market outlook is clouded by many factors. Firm module prices and BCD may deter customers although there is some evidence of leading installers having stockpiled modules. Need to comply with ALMM, deferred by six months to October 2022, is also a major source of uncertainty. Our estimate is that the market would grow by about 10-15% over last year, led again by the residential segment.

CERC, India’s central power sector regulator, has revised regulations pertaining to the Deviation Settlement Mechanism (DSM) for solar and wind power projects. The regulator has both tightened the deviation bands and increased penalties for deviations. Consequences for over-injection are considerably worse with developers not to be paid anything for more than 10% extra output. Penalty for under-injection has been restructured and linked to ancillary service charges for secondary and tertiary services instead of PPA tariff.

CERC has justified making the regulation more stringent by claiming improvement in forecasting accuracy and low penalties for individual power producers due to aggregation of schedules at pooling station. Effective date of the new regulation is yet to be notified.

Table: Deviation bands and penalties under previous and revised regulations

Notes: 1. In practice, penalties are imposed on power producers on top of their entitlement for power sale payments on the basis of power scheduled quantum. Effective penalty figures in this table are presented on a net basis after accounting for payment due for scheduled power. 2. In FY 2022, weighted average ancillary service charge was INR 6.91/ kWh.

It is worth recalling that all renewable projects are required to forecast and schedule their power output in 15-minute intervals on a day-ahead basis. They may revise the schedule up to 16 times a day subject to one revision for each time slot of 1.5 hours. The objective of these regulations, which apply to all renewable power projects, DISCOMs and consumers connected to the national grid, is to minimise scheduling deviations in order to maintain grid stability and security.

Following the new CERC regulation, the states are expected to revise their respective regulations. Most state regulations follow deviation bands defined by CERC and levy penalties of INR 0.50-1.50/ kWh depending on the amount of deviation. However, some states including Gujarat, Haryana, Madhya Pradesh and Tamil Nadu have defined tighter bands. Gujarat has adopted the tightest bands at 7% for solar power and 8-12% for wind power. Andhra Pradesh even tried to remove deviation bands altogether with a proposed flat penalty of INR 2.00/ kWh for all deviations exceeding 4.89%. But following strong opposition from the developers, the state regulator withdrew draft regulation and introduced 10% tolerance bands.

The new regulation is considerably more penal for over-injection and hence, inadvertently promotes over-scheduling. An analysis of a 250 MW solar power project in Rajasthan shows a sharp increase in penalty impact under new DSM bands. Average annual penalty amount is expected to increase from about 0.15% of revenues to 1.65% of revenues for the same schedule. However, a shift to over-scheduling can bring down annual penalty amount to about 0.5-0.8% of revenues. This amount should come down further over time as the industry adapts to new regulations and forecasting ability improves.

Another unintended consequence of the new regulation and deliberate over-scheduling by renewable IPPs would be increase in real-time and ancillary services trading volumes since actual renewable power output is likely to be lower than the scheduled amount.

ArcelorMittal, one of India’s largest steel producers, has signed an agreement with Greenko to procure a 250 MW inter-state round-the-clock (RTC) open access (OA) renewable power project. Power would be supplied from a combined 975 MW wind-solar power plant integrated with a pumped storage project in Andhra Pradesh. The project is expected to be commissioned by H1 2024 by Greenko in EPC mode at an estimated cost of USD 600 million. It would allow ArcelorMittal to achieve over 20% renewable penetration for its 10 million tonne manufacturing plant in Hazira, Gujarat. Earlier this month, Adani also announced a separate agreement with Greenko to procure 6 GWh pumped hydro capacity from Greenko projects in Madhya Pradesh and Rajasthan to enable consumption of 1 GW RTC renewable power at its manufacturing facilities in Gujarat. It is worth noting that landed cost of RTC renewable power is expected to be materially higher than cost of power from all other sources.

Large companies are coming under increasing pressure to accelerate their decarbonisation plans;

100% ISTS waiver for OA projects commissioned by June 2025 is expected to result in massive surge corporate renewable market over the next three years;

Domestic equipment suppliers and EPC contractors are expected to be the main beneficiaries;

The two deals validate Greenko’s unique strategy of proactively developing pumped hydro projects across India in anticipation of RTC power demand particularly as battery storage viability remains a few years away. Separately, Reliance Industries has obtained transmission connectivity approval for a 500 MW open access renewable power project for its Jamnagar refinery. The company is believed to be considering a multi-fold expansion of this project in the next few years. These developments reflect a fundamental shift in the corporate renewable market, which could be attributed to three factors. One, corporates making pledges to achieve net zero emissions status and consume 100% renewable power are coming under increasing pressure to accelerate their decarbonisation plans. Their primary focus, when considering renewable power procurement, has changed from just reducing cost of power procurement to increasing share of renewable power consumption and reducing carbon emissions. They are prepared to procure RTC renewable power even if it means an increase in cost of power. Larger corporates are also pushing their suppliers, including small businesses and SMEs, to increase adoption of renewable power across the supply chain. The two other factors are extension of inter-state transmission charges waiver to open access projects commissioned by June 2025 and a realisation that renewable power cost is not going to decline forever. Capex spike, increase in GST rates and looming 40% BCD on modules have nearly wiped out cost advantage of renewables over grid power in many states.

Figure 1: Landed cost comparison for industrial consumers connected at 33 kV, INR/ kWh

Source: BRIDGE TO INDIA researchNote: Grid power cost includes variable energy charges, surcharges, taxes and duties.

The behavioural shift is opportune at a time when the OA renewable market has been struggling in face of state level policy resistance and cost uncertainty.

Figure 2: OA capacity addition, MW

Source: BRIDGE TO INDIA research

Market activity is expected to see a massive surge over the next three years with 100% captive model likely to dominate. Main beneficiaries are expected to be domestic equipment suppliers and EPC contractors.

Thirty two months after the Andhra Pradesh government’s flagrant attempt to renegotiate over 7,500 MW of renewable power PPAs, the state High Court has finally restored status quo. The High Court has, in an order dated 15 March 2022, directed the DISCOMs to honour contracted tariffs and clear all outstanding dues within six weeks. It has also definitively ruled that once projects have been duly allocated under a transparent process, tariffs may not be unilaterally revised by the state government, DISCOMs or even the state regulator. It has further directed the DISCOMs to not curtail power from renewable producers unless there is a risk to the grid.

BackgroundIn July 2019, the then newly formed government in the state had sought to: i) reduce tariffs of all renewable projects; ii) cancel ‘must run’ status of renewable projects; and iii) cancel all renewable power procurement initiatives in pipeline. Subsequently, the High Court issued an order in September 2019 asking the DISCOMs to pay an interim tariff of INR 2.43/ kWh and 2.44/ kWh to solar and wind power producers respectively as against average contracted tariff of INR 4.30/ kWh.

Affected project developers The impasse has been a major strain on finances of developers to the tune of INR 72 billion (USD 948 million) in aggregate pushing smaller developers to the brink of default. Total project portfolio, selling power to DISCOMs in Andhra Pradesh is estimated at 7,569 MW (split between solar – 3,907 MW and wind – 3,662 MW). Greenko (1,616 MW operational capacity), ReNew (777 MW), Adani (604 MW), Mytrah (364 MW) and Tata (305 MW) are the worst affected private developers.

Figure: Leading project developers in Andhra Pradesh, MW

Source: BRIDGE TO INDIA research Note: Capacity excludes open access projects.

Implications for the sector The High Court decision is being widely reported as a “significant positive” for investment sentiment in the sector. However, as we maintained in 2019, there was no justifiable basis for the state to renegotiate tariffs and it was only a matter of time before legal sanctity of contracts was held. The exercise was a mere political gimmick and an outrageous attempt to buy some respite for the financially struggling DISCOMs (rated B and C respectively by the Ministry of Power).

On the contrary, the fact that it took the High Court nearly 2.5 years to resolve such a black-and-white case is a blemish on the Indian legal system. Moreover, there remains considerable uncertainty for the affected developers. The DISCOMs will have to find an estimated INR 72 billion (USD 935 million) for past compensation and INR 27 billion (USD 350 million) for annual incremental payments to power producers. Being unable to clear all dues to power producers within six weeks as directed by the High Court, they may seek more time from the High Court or drag the process by appealing to the Supreme Court.

It is not even certain that other states would learn from the Andhra Pradesh precedent. After all, Andhra Pradesh chose to renegotiate PPAs despite failure of all such precedents. In the long run, the permanent cure lies in restoring financial health of DISCOMs by improving their governance and granting them operational autonomy. However, so long as state governments see an opportunity to curry favour with the masses by offering them cheaper power, they will keep meddling in the sector.  

It is early March and peak power demand this month has already hit 195 GW as against 186 GW last year. Peak demand over last five years has grown at a CAGR of 4.6% outpacing total power demand CAGR of 3.4%.

Figure 1: Peak and total power demand

Source: CEA, BRIDGE TO INDIA research

These are official peak demand numbers reported by CEA, which also reports a rising peak deficit of 2.9 GW in the current financial year as against a deficit of about 1.4 GW in the last 3-4 years. Actual peak deficit is almost certainly much higher as DISCOMs routinely resort to load-shedding in response to rising demand. Increasing peak demand has led to greater volatility in hourly prices in the day-ahead-market on the exchanges. Morning and evening peak power prices are now routinely hitting and crossing INR 8/ kWh as shown in the following chart. Indeed, the day-ahead prices touched a new high of INR 20/ kWh on 4 March 2022.

Figure 2: Average hourly prices in the day-ahead market, INR/ kWh

Source: Indian Energy Exchange, BRIDGE TO INDIA research

There has been a similar increase in round-the-clock (RTC) prices on the exchanges over last 5 years. RTC prices in first week of March 2022 touched INR 5.41/ kWh against INR 4.07 and 2.46 seen one and two years earlier respectively.

There are several factors explaining demand-supply imbalance and price spikes. Growth of renewable capacity, concomitant with the sharp slowdown in thermal capacity addition over the last few years, is the biggest factor at play. Surplus power available for sale on the exchanges has almost completely dried up. Imported coal prices have shot up to over USD 100/ ton, an increase of over 2x in the last year, rendering affected plants unviable. And domestic coal production capacity does not seem fully geared up yet to cater to 100% demand.

The deficit is expected to get worse in the next few months as we hit peak summer. And prognosis for the next few years does not look good. A simple extrapolation of demand-supply suggests that peak deficit could reach 30-40 GW levels in the next five years. Expected renewable power capacity addition of around 60 GW, almost all without any storage capacity in the same period, would exacerbate peak power deficit and price volatility.

There are already some calls for developing new thermal power projects to ease supply pressure. The government would do well to resist such pressure and examine alternate remedial measures like incentivising addition of storage capacity, demand side management and move to market based pricing of power. Meanwhile, soaring peak power prices should provide sufficient financial reasons to DISCOMs to overcome their financial concerns and commit to RTC renewable power. It is worth noting that SECI’s first peak power tender (1,200 MW solar-wind-storage hybrid capacity, peak power price of INR 6.12-6.85/ kWh) is still not fully contracted, more than 2 years after the auction date.

CERC, India’s central power sector regulator, recently issued a regulation expanding scope of ancillary services and including large consumers and energy storage as potential service providers. The regulation covers mainly energy balancing services, also called frequency control, which have been split by CERC in three segments based on response time – primary, secondary and tertiary. The regulation does not yet cover other services like reactive power support and voltage control. NLDC, the national grid operator and designated nodal agency for the services, shall estimate demand for ancillary services on day-ahead and real time basis.

Ancillary services are expected to play a critical role in growth of renewable power by improving grid security and stability;

Trading is expected to commence in 2023 post issuance of guidelines by NLDC and launch of appropriate market instruments by the power exchanges;

Retrofitting old plants and upskilling plant and grid operators can help by improving market capacity;

Primary ancillary services, launched for the first time, shall be fully automated and provided by power plants on an instantaneous basis. Secondary ancillary services, entailing response time of less than 30 seconds and minimum duration of 30 minutes, may be provided by power plants and consumers connected directly to the transmission grid (including those with energy storage) with a capacity/ demand greater than 1 MW. Such services shall be triggered if difference between scheduled and actual power flow exceeds 10 MW at regional level. Compensation shall include variable supply cost for power plants and a fixed charge, quoted on a monthly basis, for consumers in addition to an incentive of INR 0.10-0.50/ kWh depending on service quantum. Secondary ancillary service shall be implemented using automatic generation control (AGC) – a system that allows grid operators to send signal to power plants to change their generation profile. As of January 2022, AGC had been installed at 51 power plants.

Tertiary service may be offered by power plants and consumers with response time of 0.5-15 minutes and response duration of an hour. This service shall be triggered if quantum of secondary service exceeds 100 MW for more than 15 minutes. NLDC will seek this service on day-ahead and real-time basis on the exchanges at market clearing prices.

Next steps include: i) issuance of guidelines by NLDC for power plants and consumers to participate in the market; and ii) launch of appropriate market instruments by the power exchanges post stakeholder consultation and CERC approval. Trading is therefore expected to commence sometime in 2023.

Ancillary services market became operation in India in May 2017. The current scope of services is quite simple, akin to just secondary reserve service under the latest regulation. As of January 2022, only 82 inter-state connected power plants – coal or gas fired – with aggregate capacity of 72 GW were allowed to offer this service. Market volume has been stagnant over the years but increased significantly last year.

Figure: Ancillary market volume and value in India

Source: POSOCO, BRIDGE TO INDIA research

The term, ‘ancillary services,’ refers to a vast array of services such as operating reserves, frequency control and voltage control provided by bulk energy producers and consumers to maintain grid security and stability. Expanding scope and design of such services has become extremely crucial in view of rising distributed power generation, variable renewable power supply and transmission capacity constraints. Together with demand side management, ancillary services are expected to play a huge enabling role in growth of renewable power.

Ancillary market design and requirements vary significantly across the world. Response time for secondary and tertiary services ranges from 5-15 minutes in most European countries and 6 second to 5 minutes in Australia. The UK recently added a fast reserve service with response time of less than 1-2 seconds due to increasing deployment of battery storage systems.

The market is expected to become deeper and larger over time with growth of new instruments, expansion to include intra-state markets and participation by newer technologies. Lack of readiness among power producers is a potential challenge, which needs to be overcome with retrofitting old plants and upgradation in skill sets of plant and grid operators.

The Ministry of Power has issued a green hydrogen policy. The policy was much anticipated post Indian government’s commitments at COP 26 as green hydrogen is seen as a very promising route to decarbonisation. The policy focuses mainly on provision of renewable power for hydrogen production. DISCOMs ‘may’ sell renewable power to hydrogen producers at a price equivalent to actual cost plus ‘small margin.’ For open access procurement, the policy has provisions for 15-day single window connectivity approval, one month banking and ISTS charge waiver for 25 years for projects commissioned by June 2025. It also envisages location of hydrogen production plants in renewable energy zones or dedicated manufacturing zones developed by the government as well as setting up storage bunkers at port sites.

The policy fails to address most key areas for development of a green hydrogen ecosystem;

Providing cheap renewable power, a critical requirement for reducing cost of green hydrogen, would be a major problem;

Immediate priority should be to nurture domestic technology and infrastructure development capabilities through R&D investments, subsidies and tax breaks;

Overall, the policy fails to address most key areas for development of a green hydrogen ecosystem – technology, manufacturing capacity, infrastructure for transportation and storage, demand creation and cost reduction. In the run up to the policy release, the government had made various provisional announcements – green hydrogen purchase obligation of 20-25% for fertiliser and petroleum sectors by 2030, Viability Gap Funding (VGF) for heavy mobility sector and a PLI scheme for setting up 10,000 MW per annum electrolyser manufacturing capacity. The Ministry of Power had also talked about setting up a target to develop 5 million tonnes per annum of production capacity by 2030 and an aim to reduce cost of green hydrogen by about 80% to INR 75/ kg (USD 1/ kg) in the next four to five years. The policy is notably silent on all these aspects. Most substantial elements of policy – relating to grid power cost and open access power procurement – fall under the purview of state government agencies, which remain fiercely resistant to growth of open access market. It seems unlikely that they would change their stance for green hydrogen. So what gives? Playing catch up on solar and battery manufacturing, the government is under pressure to scale up green hydrogen. But the challenge of supporting a nascent technology with limited production capacity worldwide and high cost must not be underestimated. It is a classic chicken-and-egg problem. Setting consumption targets for industrial users can be counter-productive in absence of route to economical procurement. We believe that instead of adopting ambitious targets, the government should focus on nurturing an all-round ecosystem through R&D investments, subsidies for pilot projects and seeding infrastructure development.

Leading corporates are increasingly adopting RE 100 pledges to decarbonise their businesses in response to demands from investors and consumers. There are now eight Indian companies alongside many international companies operating in India that have signed up to RE100 pledge.

Rooftop solar and open access are the only two mainstream choices for renewable power procurement;

Corporate renewable can be a critical pillar for sector growth and decarbonisation of the economy;

Consumers can make incremental progress by dovetailing their demand pattern with renewable power output profile and exploring solutions like energy efficiency, storage and solar thermal power;

But the consumers simply have no pathway to 100% RE in the current market and policy framework. Available choices remain limited mainly to rooftop solar and open access, which account for 93% of total corporate renewable business at present. And both these routes face severe restrictions. While rooftop solar is constrained by availability of suitable onsite space, open access remains partially or wholly inaccessible due to denial of approvals or project capacity/ banking restrictions in most states. For an average consumer with 24×7 operation, these two routes can therefore meet typically only about 30% of total power requirement. In Karnataka and Gujarat, where open access wind is viable and project approvals are forthcoming, renewable power share may go up to about 50-60%. All other available options – green power exchange, renewable energy certificates (RECs) and green tariffs – are either too expensive or riddled with cost, liquidity, policy and reliability constraints. These routes can therefore be used only as part of a supplementary sourcing strategy on an opportunistic basis.

Figure: Estimated capacity of different procurement routes, December 2021, MW

Source: BRIDGE TO INDIA research Note: REC capacity has been estimated based on trading volume in FY 2020.

Most of the problems stem from the convoluted grid tariff structure and the need to preserve financial interests of DISCOMs. However, it is becoming increasingly untenable to deny access to renewable power for these archaic reasons. By delaying reform and denying access to renewable power, the policy makers are not only perpetuating sector distress but artificially suppressing growth of the renewable sector and delaying progress on decarbonisation. They are also potentially blocking Indian businesses from staying competitive in the global marketplace, where replacement of fossil fuel sources is seen as an essential business competence.

MNRE has shown some belated willingness to support the corporate renewable market by waiving inter-state transmission charges and liberalising open access route. But these measures are largely cosmetic in absence of more pressing sector reforms and DISCOM support for growth of this market.

In the meantime, the old dictum, ‘necessity is the mother of invention,’ could be helpful for consumers and project developers alike. Consumers can make incremental progress by managing their demand pattern, wherever possible, and exploring solutions like energy efficiency, storage and solar thermal power. There is also an opportunity for a more robust engagement effort with the central and state governments on policy advocacy. The project developers have an attractive opportunity to move beyond commoditised solutions and offer more complex, higher value solutions.

We present five charts summarising key developments in the renewable power sector in 2021.

Soaring module prices and other costsMono-crystalline module prices surged to USD cents 30/ Wp before falling marginally by year end, a rise of 21% over previous year due to rising component prices and shutdown of factories in China. Higher costs affected project viability leaving project developers in a dilemma – import modules at higher prices now or wait for prices to fall and run the risk of basic customs duty payment from April 2022 onwards.

Figure: Module price and total EPC cost

Source: BRIDGE TO INDIA researchNote: Module prices are shown on a CIF basis before domestic duties and taxes. EPC cost includes GST and all duties as applicable at the end of each quarter.

Capacity addition stagnantWe estimate total 2021 capacity addition at 11.2 GW, split between utility scale solar – 7.8 GW, rooftop solar – 1.8 GW and wind – 1.6 GW, 30% below our estimate due to various execution challenges including higher costs, transmission and duty uncertainty.  

Figure: Capacity addition, MW

Source: BRIDGE TO INDIA research

Domestic manufacturing pushThe year saw a series of decisive policy moves to support domestic manufacturing. The PLI scheme received huge interest from 18 bidders for an aggregate capacity of 55 GW. We estimate total installed capacity of polysilicon, cells and modules to touch 30,000 MW, 40,000 MW and 55,000 MW respectively by 2025.

Figure: List of qualified bidders

Source: IREDA

Slowdown in tender activityWhile new tender issuance stayed robust during the year at 33 GW, 40% increase YOY, project allocation fell by 21% to 19.5 GW in response to low willingness of DISCOMs to contract capacity.

Figure: Tender issuance and allocated capacity, MW

Source: BRIDGE TO INDIA research

Offshore debtProject developers raised a total of USD 4.8 billion in offshore debt, a 309% increase over previous year. All-time low yields in western economies (German 10-year government bonds yield at -0.28%, USA 1.14%, UK 0.85%) attracted institutional investors to the sector. Leading developers including Adani (total issuance in 2021 – USD 2.1 billion), ReNew (USD 1 billion), Azure (USD 577 million), Continuum (USD 560 million), Hero (USD 363 million) and Acme (USD 334 million) have benefitted immensely from benign capital market conditions.

Figure: Offshore debt fund raising by project developers, USD million

Source: News reports, press releases and BRIDGE TO INDIA research

The government has approved basic customs duty (BCD) for cells and modules as well as an enhanced budget of INR 240 billion (USD 3.2 billion) for production-linked incentive (PLI) for domestic manufacturers. As per the budget announcement made this week, 25% and 40% BCD would be levied on cells and modules respectively from 1 April 2022 onwards. Both measures were widely expected and finally clear way for a dramatic transformation of the solar sector in India.

We expect total module manufacturing capacity to touch 55,000 MW by 2025;

BCD would add to overall cost pressures in the sector and reduce cost advantage of solar power;

The challenge for the government would be to wean manufacturers away from trade barriers and subsidies over time;

Enhanced PLI budget means that all 15 remaining bidders in the scheme with total bid capacity of 48,600 MW can now be accommodated in the scheme. The move is being hailed across the industry but we question the need for financial incentives when manufacturers have significant protection from imports through BCD and ALMM. The incentive is a waste of taxpayer money. Moreover, it risks distorting the market by creating massive capacity glut. We estimate total installed capacity of polysilicon, cells and modules to touch 30,000 MW, 40,000 MW and 55,000 MW respectively by 2025, far in excess of domestic demand. Some smaller bidders may, however, struggle to raise required funds within the tight deadlines – only 1.5 years for cells-modules. Based on an analysis of the investment requirement vs PLI bids, Adani, First Solar, ReNew, Waaree, Tata Power and Vikram would be the biggest beneficiaries.

Figure: PLI bid capacities and amounts

Source: IREDA’s list of qualified bidders

India’s renewable sector, having so far focused on adding more generation capacity with ever lower tariffs, is set for a drastic change with pivot towards manufacturing. Total manufacturing investment over next three years is expected to touch INR 600 billion (USD 8 billion). Despite oversupply and financial incentives, prices for domestically produced modules are expected to remain higher than for Chinese module prices by up to 10%. It also seems fair to assume that fall in Indian module prices and tariffs would be much more gradual going forward. The challenge for the government would be to wean manufacturers away from trade barriers/ subsidies and ensure that they remain competitive with leading international manufacturers on technology and cost.

Impact on project developers and consumersThe government has refrained from providing any BCD exemption for under construction projects, which will now see capital costs going up by a further 16%. Change in law compensation would ultimately cover utility scale project developers for the additional cost. But there is no clear compensation formula specified in most state tenders resulting in a significant hit because of: i) additional working capital requirement arising from delay of up to 2 years in claim approval from regulators; and ii) inadequate carrying cost allowed in determination of incremental tariff. We estimate total project pipeline impacted by BCD at 38,575 MW with Adani and Azure accounting for the biggest share because of their combined 12,000 MW win in the manufacturing-linked tender.

Figure: Estimated project pipeline affected by BCD imposition, MW

Source: BRIDGE TO INDIA research

BCD would have far more negative impact on the corporate renewable market, where effective cost for consumers would increase by about INR 0.50/ kWh eating into shrinking cost advantage of open access solar.

Other budget announcements The government has also extended operations commencement deadline for new manufacturing companies to avail concessional corporate tax of 15% by a year to March 2024. Beyond the pro-manufacturing announcements, there was little of note in the budget for the sector. Storage has been included within definition of ‘infrastructure’ sector, which may mean marginally better access to financing. The government also announced a plan to issue sovereign green bonds and extended BCD exemption on electrolysers to FY 2024.

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.