Category: Policies & Regulations

Indian states are rushing to block net metering connectivity for rooftop solar systems. After the Ministry of Power’s policy guidance to restrict net metering to system sizes up to 10 kW, Karnataka and West Bengal have already announced net metering system size caps of 10 kW and 5 kW respectively. Rajasthan is believed to be mulling similar restrictions. More states are expected to follow suit.

The new curbs effectively mean that net metering would henceforth be available only to small residential consumers;
The restrictions would significantly affect smaller C&I consumers and slow total adoption by up to 20%;
We expect levy of CSS and grid charges to be the next policy battlefront for rooftop solar;

Many states including Haryana, Uttar Pradesh, Gujarat, Maharashtra and Tamil Nadu have previously imposed other restrictions on net metering connectivity for C&I consumers as seen in the chart below.
Figure: Net metering restrictions in key states
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Source: BRIDGE TO INDIA research
One heartening aspect of these policy changes is that the older installations have been left unaffected. We understand that in Uttar Pradesh, Tamil Nadu and West Bengal, systems completed under older policies would continue to avail net metering benefit.
We expect net metering for C&I consumers to be largely phased out across the country in the next two years. Since gross metering is not a viable proposition – tariffs payable by DISCOMs (INR 2.00–4.00/ kWh) are not remunerative – new installations by C&I consumers are increasingly being set up in an alternate grid-interactive configuration whereby power export to the grid is completely blocked. All power output is either used by the consumer or lost, for example, on holidays or at other times when consumption is less than power generation. This approach has been used extensively over the years to get around other size restrictions on net metering (1 MW absolute cap plus other cap of 50-100% of connected load). This configuration is reasonably attractive as even with loss of some power output, say 10%, effective cost of power from a rooftop solar system is below INR 4.00/ kWh, nearly 50% of grid tariff for most C&I consumers. But it requires consumers to undertake careful system sizing and demand profile analysis to minimise output loss.
While larger C&I consumers would be able to effectively mitigate loss of net metering possibly with slight system downsizing, the change would be harder for small and medium size consumers, where adoption has already been relatively low. Overall, we expect total market volumes to reduce by 10-20%. Shrinking market volume is evident in Uttar Pradesh, where C&I rooftop solar capacity addition fell by 58% in two years after removal of net metering in January 2019 as against a fall of about 35% in states with no policy change. Logically, net metering removal should lead to growth in adoption of battery storage as seen in other countries, but high cost would be a deterrent over next 2-3 years.
Resistance of state distribution utilities to rooftop solar is not new. As cost of solar power has fallen and volumes grown, net metering and other incentives have been gradually withdrawn in most markets. Levy of grid charges is expected to be the next significant policy front for rooftop solar. Gujarat and Karnataka have already proposed to levy CSS and other grid charges on rooftop solar installations, and other states are expected to follow suit.
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We finally have it. After almost a year of uncertainty, MNRE has announced that PV cells and modules shall be subject to basic customs duty (BCD) of 25% and 40% respectively from April 2022 onwards. MNRE has also clarified that only bids submitted until 9 March 2021 shall be offered BCD related ‘change in law’ compensation. Final Finance Ministry notification for effecting the duty is yet to be released.

The one-year implementation interregnum is expected to serve dual purpose – give interested entities lead time to set up manufacturing facilities as well as respite to projects under construction from additional costs. The period is, however, too short on both counts and should have ideally been at least two years.

Imposition of BCD is in breach of the Information Technology Agreements signed by India under WTO framework.The government seems aware that the decision may be challenged by China, US and other countries but is banking on dispute resolution process to take many years. Nonetheless, MNRE decision provides much needed clarity to the sector. We give below our summary assessment of various related issues.

BCD is expected to stay in place for minimum 4-5 yearsLack of clarity about period of duty imposition is not a surprise as end date for BCD is typically not announced upfront. But it is acknowledged that safeguard duty (SGD) failed to have any beneficial impact on domestic manufacturing because of its limited time span. The government has already informally indicated that BCD would stay in place for at least 4-5 years.

SGD extension almost certainLast year, SGD was extended until July 2021. We expect another extension at the prevailing 14.50% rate until March 2022 notwithstanding the fact that the Commerce Ministry’s trade investigation is still not complete.

Steep duty would dim solar’s shine 40% duty level is excessive as the cost disadvantage for domestic manufacturers is believed to be no more than 20-25% and the government has already outlined production-linked incentives and demand enhancement for domestically manufactured modules.

The cost impact would be compounded by 10% Social Welfare Surcharge raising effective level of duty to 44% and increasing solar tariffs by about INR 0.52/ kWh. The extra cost would not be welcome by DISCOMs particularly when they are already reluctant to purchase vanilla solar power. The duty improves relative cost attractiveness of wind power and solar-wind hybrid power. 

Higher cost would also dampen long-term growth prospects in rooftop solar and open access solar although there would be a temporary demand boost around H1/ 2022 to avoid BCD burden.

Terrible news for pipeline projects While ‘change in law’ provisions are enshrined in most PPAs now, proposed compensation increase of INR 0.005/ kWh tariff for every INR 100,000/ MW increase in project cost is not adequate. The formula does not consider ‘carry’ cost of BCD for 25 years and leaves project developers out of pocket by about INR 0.05/ kWh.

On the flip side, the DISCOMs would be even more reluctant to sign PPAs for nearly 18,000 MW of project capacity tendered in the past year – at tariffs ranging between INR 2.36-2.92/ kWh – because of extra ‘change in law’ cost.

Surge in capacity addition expected in H1 2022Most developers would be keen to import modules for under development projects before BCD comes into effect subject to module price outlook and availability from tier 1 suppliers. H1 2022 could be a really busy time with utility scale solar capacity addition of as much as 10,000 MW.

Little improvement in competitiveness of domestic manufacturing We maintain that BCD does little to improve cost competitiveness of Indian manufacturing. Small scale, lack of domestic supply chain and dependence on imported technology (plus upstream components) means that India’s self-sufficiency hopes would remain elusive for the foreseeable future.

We expect 10-12 GW of module manufacturing capacity to be developed over the next three years. Interest in cell and other upstream manufacturing is expected to be much lower because of higher capital cost and technology risk (and lower duty).

The Ministry of Power has tabled a draft Electricity Amendment Bill in Lok Sabha. The foremost provision in the draft Bill relates to liberalisation of power distribution business. The government is proposing to end DISCOM monopoly by allowing any new player to enter the business anywhere in the country. The draft Bill also includes a few other assorted provisions designed to tackle various procedural issues in the sector.

The draft Bill requires DISCOMs to share their power sourcing arrangements and distribution network with the new players;

Crucial details concerning regulatory design for sharing of legacy PPAs, network costs and tariff pooling across consumer segments are missing;

Other provisions covering RPO compliance, tariff approvals by regulators and payment security fund maintenance by power purchasers are piece-meal in nature;

As per the draft Bill, state regulators would define business criteria for new players keen to enter distribution business. Subject to fulfilment of these criteria, (deemed) approvals shall be given necessary approvals to operate within 60 days of application date. Incumbent DISCOMs would be required to share their power sourcing arrangements as well as distribution network with the new players. There is no explicit universal service obligation requirement for the new players. Instead, the Bill proposes creation of a universal service obligation fund managed by a state-government nominated entity. Presumably, the idea is that any tariff recovery over ‘Average Cost of Supply’ from C&I consumers, for example, would be transferred to this fund for sharing with other distribution companies.

Entry of private players would enable consumers to choose their power supplier on the basis of better service or lower price, or a combination of both. The government is hoping that loss of consumers would, in turn, force state government-owned DISCOMs to up their game and improve overall efficiency in the sector. In theory, it is a sound economic argument. We have seen several instances of liberalisation in banking, aviation, telecoms and even power generation, amongst other sectors, over the last thirty plus years. But the public sector entities have almost always been left behind in all such cases and there are few examples of revitalised incumbents. Cue strong opposition from opposition parties, state governments, DISCOMs and even some consumer bodies.

The devil would be in detail. Successful liberalisation of distribution sector would require intricately designed regulatory mechanisms for sharing of legacy PPAs, network costs as well as tariff pooling across different consumer segments. Lack of reliable operational data could also be a stumbling block.

Other proposals are more assorted in nature. Failure to comply with RPO targets would result in financial penalties increasing over time – INR 0.25-0.50/ kWh in the first year, INR 0.50-1.00/ kWh in the second year and INR 1.00-2.00/ kWh in the first year. To reduce offtake risk, a provision mandates that power supply to offtakers would not be scheduled until all payment security fund requirements have been fulfilled as per the agreed contract. There are provisions requiring state regulators to process retail tariff petitions and power purchase petitions by DISCOMs within 90 days. Another provision suggests that if a state regulator is unable to operate satisfactorily because of inadequate staffing, the central government may, “in due consultation with the state government,” entrust its functions to another regulatory agency.

The draft Bill is notable as much for many exclusions as it is for final inclusions. Key reform measures including direct payment of tariff subsidies by state governments, separation of content from carriage, privatisation of DISCOMs, a new contract enforcement authority and hydro power procurement obligation, mooted just last year, have been binned. Tariff reform has also been given a miss.

Before we get to the execution stage, there is the all-important matter of getting the Bill through the Parliament. Curiously, the draft version has not yet been released publicly (BRIDGE TO INDIA has seen a copy) possibly in anticipation of fierce resistance from different stakeholders. The recent precedent of farm laws, which were rushed through the Parliament without full debate and are now stuck, is not encouraging.

This video presents a monthly snapshot of key policy and regulatory developments in India’s renewable power sector.

Gujarat has announced a new solar policy for the next five years. The policy breaks away from many conventional features in similar state policies. On the positive side, the state has removed all project sizing restrictions for all consumers and investors irrespective of end use for power. OPEX projects are allowed grid connectivity unlike earlier. But the state has dealt a huge blow by imposing all grid charges including transmission and wheeling charges, Cross Subsidy Surcharge (CSS) and Additional Surcharge (AS) on OPEX projects and then also introducing a new penal definition of “captive” projects. Similarly, banking has been allowed with severe limitations and cost.

The decision to do away with project capacity caps and provide full freedom to consumers and investors is welcome;

Imposition of all grid charges on OPEX projects and change in definition of “captive” projects makes third party sale model a non-starter;

States are devising ever new ways of suppressing distributed renewables, particularly the C&I market, to protect DISCOMs;

Most states impose multiple size ceilings linked to distribution transformer capacity, power consumption, and connected load of consumers on top of an overarching system size cap of 500 kW or 1 MW on rooftop solar systems under net metering policies. The decision to do away with project capacity constraints is therefore highly welcome. It provides freedom to consumers and investors to size solar projects depending on their assessment of project viability and power consumption profile.

Another seemingly positive change is that projects developed under OPEX model can now avail grid connectivity unlike under the earlier policy. However, such projects shall bear all grid charges including CSS and AS making the model a non-starter. This is the first time that these charges are being applied to rooftop solar installations anywhere in the country. The change has adverse implications as most consumers have an overwhelming preference for OPEX model particularly in times when they are financially stretched and keen to conserve capital.

The new policy does away with conventional definition of net or gross metering. Instead, it allows banking for all projects but subject to severe restrictions (daily or monthly basis depending on connection voltage for C&I consumers and only within specified day hours) and payment of INR 1.10-1.50/ kWh banking charge by C&I projects.

One of the most contentious provisions relates to new definition of “captive” projects. Only wholly owned projects will be considered as captive projects – in contravention to the Electricity Act, which specifies ownership threshold at only 26% for captive projects. There are profound implications of this provision. The open access market has moved almost entirely to third-party model with 26% equity ownership by consumers to avoid CSS and AS. The legal sanctity of the change is questionable. But it means that third-party sale projects are now unviable (see chart below). If other states follow Gujarat’s lead, open access market would face grim prospects.

Figure: Landed cost of open access solar power, INR/ kWh

Source: BRIDGE TO INDIA ResearchNote: This chart shows landed cost for an HT power consumer, connected at 33 kV, and served by PGVCL, one of the state DISCOMs. Grid tariff includes only variable energy charge and electricity duty. It does not include fixed charges.

The policy again demonstrates how states are devising ever new ways of suppressing distributed renewables particularly the C&I market to protect DISCOMs. It breaks new ground by imposing various charges on rooftop solar installations and coming up with a new definition of “captive” projects. Given the magnitude of some of these changes, we expect a legal challenge to the policy creating an extended period of uncertainty for the state’s renewable market. 

India’s central government recently approved some changes to promote large hydro power (capacity > 25 MW). The changes include designation of large hydro as renewable power, a sub-limit for new hydro power purchase obligation (HPO) within RPO (targets yet to be determined) and measures to make it more affordable. There is also a provision for budgetary support for enabling infrastructure, roads and bridges, up to INR 15 million/ MW depending on project size.

The changes are desirable as they could reduce upfront cost of hydro power by 20-25%;

Because of complex land acquisition, geological, environmental and resettlement challenges, the sector has become unattractive to private investors and financiers;

Market-based pricing of power, creation of a vibrant ancillary services market as well as greater public sector investment are crucial for growth of the sector;

Designation as renewable power may bring some notional benefits (‘must run’ status, marginally lower cost of funding, accelerated depreciation) but the measures to reduce upfront cost of power are more important. Changes include increasing normative project life to 40 years (earlier 35 years), increasing debt repayment period to 18 years (12 years) and escalating tariffs annually by 2%. We believe that these changes, together with budgetary support, could bring down upfront tariffs by 20-25%.

Being a flexible source, large (reservoir-based) hydro power has always been talked about as an ideal balancing source for renewables. It can ramp up and down quickly, can provide peaking energy and ancillary services support to stabilise the grid. Its other main advantage is no need for any international technology or fuel source. In other words, it offers high energy security. In theory, India has an untapped potential of almost 100,000 MW of hydro power and that explains why the Indian government is so keen to support this power source.

But the benefits are outweighed by some formidable disadvantages. Hydro power is costly – capital cost ranges between INR 70-90 million/ MW – and has a long gestation period of around 8-10 years. Time and cost overruns are highly common because of complex land acquisition, geological, environmental and resettlement challenges. Over 12,000 MW of projects have been stuck in the pipeline for many years because of these challenges. Cost of power for some of the recently completed projects has come out higher than INR 8.00/ kWh. Water resource is also becoming more unpredictable.

Consequently, hydro power is deemed uncompetitive with other power sources. Private investors and banks are extremely reluctant to finance such projects. According to the International Energy Agency, global capacity addition fell from 31 GW in 2008 to 24 GW in 2017. India’s hydro capacity has been nearly stagnant. Total installed capacity of 45,400 MW has barely grown in the last ten years with average annual capacity addition of just 987 MW

It is unfortunate that the unique benefits of hydro power are not valued and monetised as such, making it uncompetitive, in particular, with solar and wind power. Market-based pricing of power, creation of a vibrant ancillary services market as well as greater public sector investment are crucial for growth of the sector. But the severe operational and environmental challenges make us believe that hydro power is likely to remain a marginal source even in a best-case scenario.

In January 2019, Government of Andhra Pradesh issued a new solar policy superseding the solar policy issued in 2015. The state aims to add 5,000 MW of solar power capacity in next five years.  Solar park capacity addition target for next five years is increased to 4,000 MW from 2,500 MW. The major change is the state’s abrupt pull back on open access. The state has decided to withdraw almost all incentives available to open access solar:

Electricity duty and cross subsidy surcharge (CSS) are no longer exempted;

Distribution losses are no longer exempted for projects injecting power at 33 kV or below;

Wheeling and transmission charges are exempted for connecting to national transmission grid, but exemption is withdrawn for intra-state open access projects;

Purchase of unutilized banked energy is capped at 10% of total banked energy during the year, price is reduced to 50% (100% earlier) of average pooled purchase cost (APPC);

Other relatively minor changes include support of the state nodal agency, NREDCAP, in acquiring government land for project developers. The government also proposes to give preference for power purchase, evacuation connectivity and energy banking to projects developed by local solar equipment manufacturers and related ancillaries.

Under the earlier policy proposed to be valid until March 2020, CSS was exempted for 5 years and electricity duty, transmission and wheeling charges and distribution losses were exempted for 10 years for projects connected at 33kV or below. The new policy makes the state unattractive for open access. It increases landed cost of solar power for industrial consumers by INR 2.38/ kWh and INR 0.95/kWh for third-party sale and captive consumption respectively.

Andhra Pradesh was considered a high potential state for open access due to its attractive policy regime, relatively easy land availability and strong solar eco-system. We had estimated open access solar capacity in the state to increase from 154 MW in December 2018 to about 500 MW by March 2022. That appears highly unlikely under the terms of new policy.

The policy reversal is clearly to appease state DISCOMs, who continue to struggle financially despite financial support from UDAY scheme. In 2017, Madhya Pradesh withdrew most incentives for open access solar projects, followed by Karnataka in 2018. Haryana is still struggling to implement the policy first announced in 2016 and has recently issued an order withdrawing exemptions of OA charges for third-party sale projects. As we maintained in our recent report on open access solar, the market is being held back by policy challenges with frequent changes and negative attitude of DISCOMs and other state agencies.

BRIDGE TO INDIA has released its quarterly market report – India Solar Compass Q4 2018. The report contains detailed analysis of solar capacity addition, tender issuance, leading market players, prices and other market trends for the last quarter as well as our estimates for the next two quarters.

Only 1,446 MW capacity was added in Q4 2018 – 990 MW utility scale solar (68%) and 456 MW (32%) rooftop solar. Utility scale solar capacity addition has been sluggish since Q2 2018 and was down 46% over Q4 2017. In contrast, rooftop solar is growing strongly and is up 47% y-o-y. Total installed solar capacity has reached 28,057 MW in the country, split between 24,202 MW utility scale solar and 3,855 MW rooftop solar.

A few other highlights from the report:

There was an unprecedented spike in tender issuance with 51,118 MW of new tenders in the year (15 GW issuance in Q4 alone);

Floating solar, solar-wind hybrid and storage tenders picked up pace in 2018;

Project pipeline reached 17,658 MW as on December 31, 2018;

Module prices fell to USD 0.20/ W in Q4, down 44% over previous year but a substantial part of this fall has been offset by safeguard duty, GST and fall in Rupee-USD rate;

Adani (1,958 MW), Acme (1,801 MW) and Tata Power (1,300 MW) were the top three project developers in 2018;

The market place continues to be very competitive with extensive churn in player rankings. For utility scale projects commissioned in 2018, GCL (704 MW), Risen Energy (668 MW) and Trina (531 MW) were the leading module suppliers, while Sungrow (1,114 MW), ABB (1,110 MW) and Huawei (982 MW) were the top three inverter suppliers. Self-EPC continues to be preferred heavily with nearly 50% share of the total market. Sterling & Wilson maintained its lead (894 MW), followed by Mahindra Susten (357 MW) and L&T (210 MW).

We expect a significant pick up in construction activity in 2019, however module prices are expected to stay firm or even harden marginally.

A quick look at the profile of winning bidders in utility scale wind and solar auctions over last three years throws some pointed results. The role of international investors – utilities, developers and financial investors (pension funds, sovereign wealth funds, PE funds) – is becoming more critical. Their combined share has gone up steadily from 32% in 2016 to 65% in YTD 2019. Indian investors – large and small – are being squeezed out of the market as project sizes increase and risk-return equation becomes unfavourable.

International utilities and pension and sovereign wealth funds have been attracted by the large size of Indian RE market but they remain cautious investors;

With many Indian investors unwilling or unable to compete in the sector, the number of winning bidders has gone down by 70% in the last three years;

India needs to attract new pools of capital for meeting the needs of its energy sector;

In a capital-intensive sector, the dominance of large international investors is not altogether surprising. Capital cost per MW has fallen sharply (for solar) but that has been accompanied by significant increase in project sizes. Average bid size has more than doubled from 71 MW in 2016 to 153 MW in YTD 2019.

There are other factors explaining this shift. International utilities (Engie, EdF, Enel, Fortum, CLP, Sembcorp) and pension and sovereign wealth funds (CDPQ, CPPIB, GIC, ADIA, CDC) have been attracted to the world’s fastest growing energy market and a desire to invest in alternative energy. In an intensely competitive bidding market, they have been able to grow their presence by accepting low returns (and low risk). The PE investors, on the other hand, have taken an aggressive development approach with a 3-5 year exit strategy as exemplified by Actis (Ostro Energy) and AT Capital (Orange Power).

So far, so good. But the evolving nature of the market is also partly attributable to unwillingness or inability of even the largest Indian investors (Tata Power, Aditya Birla, Mahindra, Reliance, Jindal) to compete with their international counterparts. In other words, the project development business is losing depth. The number of winning bidders has gone down by 70% in the last three years. We believe that this trend is unsustainable and should be a worry for the policy makers. International investors are highly risk averse and could be spooked by rising instances of DISCOM payment delays, policy reversals, PPA renegotiation attempts and tender cancellations. A shallow market is also more prone to external shocks including currency movements, war and international trade restrictions.

There are 23,687 MW of tenders in the bidding pipeline. The aim is to build out over 100,000 MW of RE capacity and allied infrastructure necessitating investments over USD 70 billion in the next five years alone. India needs to attract new pools of capital for transforming its energy sector and achieving its geo-political objective of higher energy security. That requires shifting focus from reducing tariffs to offering a better risk-return profile to investors. 

MNRE recently issued a notification to create an “Approved List of Models and Manufacturers” of PV cells and modules in India. The notification states that all solar projects set up under any form of government scheme or programme would be required to procure cells and modules from the approved list. It would be effective from April 2020 onwards and approvals would be valid for only two years with renewal subject to demonstration of satisfactory performance of the respective products.

Detailed implementation guidelines are still awaited but the process outlined so far seems excessive and unworkable;

The relatively simple set of quality standards introduced in August 2017 are yet to become fully effective due to lack of procedural clarity, inadequate testing facilities and high cost;

It is hard to see how the notification would achieve its stated objectives of improving product reliability and energy security in the country;

The notification would affect almost the entire solar industry in India as it covers all schemes and programmes implemented by any central or state government agency or public sector entity. Recent tenders issued by SECI have already incorporated a condition asking bidders to ensure compliance with the new notification. To get on the approved list, the manufacturers would first need to get required BIS certification for each model of cells and/ or modules proposed to be used in India. The second step would entail a prescribed application to MNRE, followed by physical inspection and audit of the concerned manufacturing facility(ies) to ensure sufficient manufacturing capacity and expertise. The manufacturers would be required to provide extensive information to MNRE on a monthly basis covering purchase of raw materials, production and sale of goods as well as supporting bank statements and compliance certificates. The approved models and manufacturing facilities would be further subjected to random quality testing and site inspection respectively to ensure compliance.

The scope of the notification and proposed procedures seem overbearing to say the least. We shudder to imagine implementation nightmares and consequent effect on the supply chain. The relatively simple set of quality standards introduced in August 2017 have caused widespread chaos in the industry due to lack of procedural clarity, inadequate testing facilities and high cost. After some five extensions, the standards are yet to become fully effective.

The notification, a bewildering exercise in scope and methodology, raises serious concerns. We doubt if MNRE or any other public sector entity has the capacity to complete physical and financial audits of manufacturers worldwide. Will the companies even be willing to provide all the necessary information? Equally importantly, it is hard to see how the notification would address concerns around “product reliability” and “larger energy security” in the country. If anything, it seems like a convoluted exercise in protecting domestic manufacturing.

After years of anticipation, grid scale storage tenders have finally started picking pace in India. Seven tenders with a total storage capacity of 84 MWh (with 78 MW of solar PV capacity) have been issued in the last one year. These tenders have been issued by SECI, NTPC and NLC predominantly in remote areas of Jammu & Kashmir, Lakshadweep, Himachal Pradesh and Andaman & Nicobar Islands. There is huge market interest in storage tenders but participation in tenders is still limited because of specific eligibility conditions requiring minimum construction or operational experience and/ or domestically sourced content. Mahindra Susten, L&T, BHEL, Hero, S&W, IBC Solar, Exide have been amongst the most active bidders so far. There has also been some concern from the private sector that storage specifications are not clearly defined. But we believe that this aspect is improving slowly as awareness of storage technologies is improving gradually and procurement authorities are beginning to define specifications in more detail. 

There have also been two new wind-solar hybrid tenders (160 MW and 600 MW) issued in Andhra Pradesh with optional storage component. India’s current grid-scale commissioned storage capacity is only 10.75 MWh. AES and Mitsubishi inaugurated a 10 MW, 10 MWh facility in Delhi. Other relatively small systems are located in remote villages in West Bengal (1.73MW), north-east (6.85 MW) and Lakshadweep islands (2.19 MW). The market holds huge potential particularly as the growing share of variable renewable energy – up from 5.6% in 2014 to 10.6% in 2018 – creates a formidable challenge in maintaining grid stability. Because of environmental and commercial concerns associated with traditional storage systems including pumped hydro, we believe that battery-based energy storage systems would dominate the market. The Government of India has been planning to issue a National Energy Storage Mission along the lines of National Solar Mission with specific targets for capacity deployment, local manufacturing and policy support. It is expected that announcement of NESM – due imminently – would provide a major boost to the market.

Last week, India’s Cabinet Committee on Economic Affairs finally issued its approval for two signature policy schemes announced by the government more than a year ago. The two schemes – SRISTI, covering rooftop solar and KUSUM, covering agriculture solar – are ambitious. The target is to add total distributed solar capacity of approximately 36,000 MW and 25,750 MW with a capital support of INR 118 billion and INR 344 billion (total USD 6.5 billion) respectively by March 2022.

The two schemes are an unrealistic and outdated mix of capital subsidies, feed-in-tariffs and financial incentives;

There is no money or time left for this government to implement the new schemes;

Lack of imagination in policy making is a worrying sign for the sector;

In rooftop solar, the government wants to continue capital subsidy support of 20-40% for residential consumers. Plus, it aims to offer 5-10% of benchmark capital cost as incentives to DISCOMs to get their support for this market. The government also wants to solarise agriculture through installation of 1.75 million solar pumps, another 1 million pumps powered by solar power and 10,000 MW of distributed power plants of up to 2 MW capacity each. A capital subsidy of between 60-80% is proposed for pumps and there is a promise of feed-in-tariff, to be approved by respective state regulators, for power injected into the grid.

As the following table shows, the numbers are not realistic. Moreover, the proposed incentive of 5-10% for DISCOMs is insignificant both in terms of absolute quantum and as compensation for loss of their revenue

Apart from the fact that the numbers do not seem to add up, it is not clear how the two initiatives would be funded. The central government is walking a fiscal tightrope and has been unable to find money for the sector. MNRE’s budgetary allocation of INR 52 billion for FY 2019-20 remains unchanged over previous year. The National Clean Energy Fund, with a cumulative corpus of INR 860 billion, has already been appropriated for other spending needs.

The essence of cabinet clearance after more than a year of announcement of the two schemes is also unclear. At this stage of the political cycle, it seems more like an exercise in political posturing rather than a serious intent. With the ‘model code of conduct’ likely to be imposed from early March, actual implementation is unlikely during the term of this government. That is perhaps a good thing. Upfront subsidies offer little value for money and have failed to achieve purported benefits in the past. They distort incentives for installers and lead to mis-selling and shoddy execution. Moreover, the high cost of administering subsidies wipes out almost 50% of the proposed benefit.

Something unique happened in the Renewable Energy Certificate (REC) market last month. Prices of solar RECs moved above the specified floor (INR 1,000/ MWh) for the first time ever and touched INR 1,750/ MWh. Non-solar RECs also traded above the floor level at INR 1,500/ MWh. The price jump came even as trading volumes continued to stay low.

The reason for price rise is that the REC supply has not kept up with demand. Total RE capacity registered for RECs was only 3,948 MW as on 31 March, 2018, just 5.3% of total operational RE capacity. The number of RECs issued fell to 6.2 million in 2018 from 8.2 million in 2015. One of the most popular mechanisms for projects to generate RECs has been to sell ‘brown’ power to DISCOMs at APPC (average pooled purchase cost). Even today, about 42% of total capacity registered under REC mechanism is supplying power to DISCOMs at APPC. But with power prices falling steadily for both RE and conventional sources and supply exceeding demand, the DISCOMs are no longer keen to buy uncontracted ‘brown’ RE power. The affected projects are therefore increasingly forced to sell ‘green’ power to C&I consumers under open access route and forego RECs.

In contrast to diminishing supply, REC demand has been looking up. A disproportionate 40% of demand is coming from private sector entities – captive power producers and open access consumers – keen to fulfil their compliance requirements. Compliance by DISCOMs is still patchy with many state regulators treating them softly because of their perilous financial position. But MNRE’s RPO monitoring cell seems to be gaining traction and should help push demand further.

As a result of the demand-supply mismatch, REC inventory accumulated because of poor compliance in the early years is nearly exhausted. Unsold stock of solar and non-solar RECs has fallen to 0.5 million and 1.7 million from 4.4 million and 13.2 million respectively in the last two years.

Notwithstanding the short supply of RECs, it is clear that this market has lost its relevance as a tool to support RE growth. With cost of RE power falling to below INR 3.00/ kWh, the DISCOMs are reluctant to buy RECs as evident from low trading volumes in the last three months. The solution lies in making RE accessible to resource deficit states in north and east India. We believe that a new mechanism is therefore needed to replace RECs. Enabling RE power trading on the exchanges and facilitating ‘contracts for difference’ style structures may be one potential solution.

A DISCOM payment crisis has been building up again in India. The Ministry of Power payments portal shows that outstanding dues increased to INR 410 billion (USD 5.9 billion) by November 2018 (March 2018: INR 250 billion). These numbers are based on limited available data, actual amounts are likely to be much larger. Worst offending states include Uttar Pradesh, Tamil Nadu, Karnataka, Andhra Pradesh, Telangana, Madhya Pradesh and Punjab. Payment delays range from 2-3 months to as much as 9-10 months in the worst cases. We understand that dues of some large renewable IPPs may have gone up to as high as INR 15 billion (USD 0.2 billion).

UDAY has failed to provide sustainable solution to DISCOM finances;

The crisis has been worsened by rollout of the SAUBHAGYA scheme and impending general elections when tariff rises are politically unpalatable;

Weak DISCOM finances and delayed payments undermine all government moves to reform the sector;

Late payments have been a chronic challenge for the power sector. There were hopes that the UDAY scheme, introduced in 2015, would provide a lasting relief with emphasis on debt transfer, tariff rises and reduction in T&D losses. The one-off financial engineering – transfer of (nearly 70%) debt to the respective state governments – was successful in temporarily shoring up balance sheets. But disappointingly, there has been little progress on key fundamental aspects of the UDAY scheme. The sector continues to see heavy meddling by the local governments as the election season looms. Average annual tariff rise of between 0-4% in the last three years has been nowhere near sufficient to meet rising costs. T&D losses are also stuck at about 21% despite the target of reduction to 15% by 2018-19.

The payment crisis owes partly to the success of the Indian government’s SAUBHAGYA scheme. Sale of power at subsidised prices to small residential consumers is costly and incurs a heavy loss of about INR 6.00/ kWh. There is some evidence to show that load shedding to agricultural and residential consumers has fallen drastically in advance of the elections. (should we provide a link here?)

As a result, annual DISCOM losses, which are estimated to have fallen by two-third from about INR 600 billion in FY 2014-15 to INR 200 billion in FY 2017-18, are expected to again increase this year. At the same time, state government power subsidy bills are also rising. Punjab is a glaring example with annual subsidy bill of INR 140 billion (USD 2 billion), more than 10% of the state’s annual budgeted revenues.

Delayed payments not only starve the IPPs of liquidity and put them at risk of default to lenders, but also eat into profits as IPPs rely on more expensive short-term debt or equity to bridge cash deficit. To make matters worse, the DISCOMs usually don’t even pay interest on delayed payments in contravention of the PPA provisions. The crisis has blown to such an extent that a radical move to make advance payments to IPPs is being proposed. But we are not very optimistic – the problem is behavioural/ systemic rather than structural.

The payment crisis comes at a very inopportune time as the industry is already reeling under multiple problems. It is one more factor draining away industry confidence and a solution doesn’t seem in sight.

After failure of its flagship 10 GW integrated manufacturing tender, SECI has issued another integrated tender combining project development (3 GW) and module manufacturing (1.5 GW). There are some notable changes over the previous tender. Minimum bid size has been reduced to 1 GW project development and 0.5 GW module manufacturing, down from 2 GW and 0.6 GW respectively. Backward integration is now limited to cell manufacturing as against wafer manufacturing. Cross-penalty structure between the two businesses is much simpler now. And ceiling tariff has been reduced marginally to INR 2.75/ kWh from INR 2.85/ kWh earlier.

Reduction in tender size is helpful from a risk management perspective but the proposed manufacturing business would be significantly sub-optimal in size;

The ceiling tariff of INR 2.75/ kWh is border line attractive at best;

We put the odds of this tender going through successfully at 50:50;

Smaller scale of project development, limited backward integration and simplification of penalty structure are helpful changes. They reduce capital exposure and should attract more players into fray. But the core underlying problem remains – the combination of two disparate parts of the value chain – manufacturing and project development – does not stack up as the two businesses have very different core competencies and risk-return expectations. Few companies want to be present in both manufacturing and project development.

Moreover, the new manufacturing business would be sub-optimal in size. In a cut-throat business, scale is seen as a major competitive advantage. Share of top ten module manufacturers globally has gone up to 60% from just 42% in 2015. Incredibly, average global shipment of top ten players has gone up to 6.3 GW per annum from less than 2.5 GW just three years ago.

Figure: Top ten global module suppliers in 2018

Source: PV-Tech, BRIDGE TO INDIA research

The proposed minimum manufacturing capacity of 0.5 GW is miniscule in comparison. And it will be seen as a loss leader by potential bidders. Unfortunately, the ceiling tariff of INR 2.75/ kWh for project development is not enough to compensate for this downside.

With safeguard duty having failed to shore up domestic manufacturing, the government is under pressure. It is doubling down on the curious integrated tender concept. We are not sure if the new tender will enthuse the market sufficiently. Some of the Chinese manufacturers, keen to diversify their manufacturing bases in view of trade war with the US, are bound to show interest. We put the odds of this tender going through successfully at 50:50.

Gujarat has cancelled the Banaskantha solar park based 700 MW utility scale solar tender for which an auction was conducted in December 2018. Winning bidders were SB Energy (250 MW, INR 2.84/ kWh), Fortum (250, 2.89) and Engie (200, 2.89).  Reason for cancellation is same as ever and arbitrary – the winning tariffs are “too high.”

Main reason for high tariffs is the extremely high solar park charges fixed by another arm of the Gujarat government;

5,300 MW of valid winning bids have been cancelled by different agencies in the last year in the expectation that they can keep driving down tariffs ever lower;

Arbitrary tender cancellations are taking the shine off India’s solar story and threaten to turn the investors away;

Winning bids were about INR 0.40/ kWh higher than in the last solar auction conducted by the state in September 2018. Main reason for high tariffs is that solar park charges in Banaskantha were fixed at extremely high levels (by another arm of the Gujarat government). We have computed net present value of these charges at INR 8 million (USD 0.1 million)/ MW, about 2.5 times the cost of similar services in the open market. If the charges were set at more reasonable levels, the winning tariffs would have been lower by about INR 0.30/ kWh. We understand that the winning developers argued this point with the Gujarat government and offered to reduce tariffs if solar park charges are made more competitive but with no result. Curiously, unlike other states, Gujarat does not specify any ceiling tariffs in its tenders. So, there is no formal guidance to bidders on acceptable tariff range.

This cancellation comes after a previous cancellation of a 500 MW tender by the state in April 2018 where winning tariffs came in the range of INR 2.98-3.06/ kWh. In that instance, cancellation was partly justified as the auction took place just weeks before announcement of safeguard duty and the developers duly added a fat risk buffer to the tariff. Three months later, the state got much lower tariffs of between INR 2.44-2.45/ kWh but the reduction was largely due to sharp fall in module prices and clarity over safeguard duty risk. Unfortunately, the procurement agencies have learnt the wrong lessons and cancelled 6,725 MW of valid project bids in the expectation that they can keep driving down tariffs ever lower.

Figure: Utility scale solar capacity – tender progress since January 2018, MW

Source: BRIDGE TO INDIA research

Gujarat attracts leading international developers to its tenders because of its sterling reputation, highly rated DISCOMs and prompt payment track record. But the state is damaging its standing by repeatedly cancelling tenders and runs the risk of turning investors away.

Indian RE has faced many challenges in the last year. Many players, hurt by adverse risk profile and low returns, have exited the sector. There are clear signs of consolidation in the bidding activity and the number of active, deep-pocketed bidders is down to about ten. Government agencies need to beware – they need to provide attractive investment environment to attract capital. Solar is growing in many other parts of the world and international capital, in particular, can be fickle.

India’s general elections are around the corner. Scheduled date is May and final detailed time-table should be announced soon around early March. There is emerging consensus that no single party is likely to return with majority in the parliament. The increasing possibility seems one of a highly fractured verdict and a weak coalition government. This is giving rise to fears if RE could lose policy thrust in India. The other fear is that a weak government may more generally herald a period of economic uncertainty with focus on populist vote winning policies rather than on fundamental sectoral reform.

We expect no dilution in policy support for RE irrespective of who forms the government;

There is little correlation between governments run by different ruling political parties and RE development;

Major policy action would be off limits for a few months putting initiatives like National Storage Mission and SRISTI at risk;

We have two broad takeaways from the pressures of electoral cycle and emerging political environment. First, the policy purdah would be imposed as soon as the elections are announced. The government would still be able to make minor policy tweaks and issue project tenders in the run up to elections, but major policy action would be off limits. That puts initiatives like National Storage Mission and SRISTI at risk of considerable delays. Populist giveaways and gimmicks are expected to attract voters in the next few months. Most of these are likely to be aimed at the farming sector and low-income section of the population. There may be some funding for the KUSUM solar pump scheme but any meaningful progress is unrealistic.

Second, we believe that the sector enjoys broad cross-political support and there is unlikely to be a retreat irrespective of who forms the government. Support for the sector is seen as being development-oriented. It is also seen as a way to earn international plaudits as India’s efforts to form International Solar Alliance (ISA) point to. A state level analysis confirms that there is little correlation between governments run by different ruling political parties and RE development. Examples – Karnataka and Andhra Pradesh, two leading RE states have been ruled by Congress and TDP respectively, whereas Maharashtra and Uttar Pradesh lag significantly despite strong BJP governments. ­

Figure: Commissioned and pipeline RE capacity vis-à-vis March 2022 target

Source: BRIDGE TO INDIA researchNotes:

This chart includes data for only utility scale solar and wind projects.

Rajasthan, Madhya Pradesh and Chhattisgarh have recently elected Congress led state governments.

For pan India tenders with provision for inter-state transmission connectivity, capacity is assigned to states based on offtake rather than project location. This information is not available for about 5,400 MW of pipeline projects.

Encouragingly, there are some studies showing that coalition governments do not have an adverse impact on economic growth and performance. But a note of caution is still needed – day-to-day policy formulation and urgency behind the sector would be likely casualties in the event of a coalition government.

To read more about our assessment of the RE sector in 2019, please read our latest report – India RE Outlook 2019.

In the last six weeks starting December 2018, 22 utility scale tenders aggregating 15,453 MW of capacity have been issued for wind and solar power projects in India. This spree has come as MNRE announced a revised plan in December 2018 to issue tenders for an aggregate capacity of 80,000 MW by March 2020 – equivalent to a phenomenal monthly average of 5,000 MW.

It is encouraging to see more demand for RE from leading power consuming states such as Maharashtra, Gujarat and Uttar Pradesh;

Progress on tenders last year was very poor as multiple tenders were undersubscribed and/ or cancelled resulting in weakening investor confidence;

Issuing more and more new tenders without addressing operational and financial constraints faced by the sector is a pointless exercise;

In total, there are now 24,862 MW of utility scale projects for which tenders have been issued but auctions are yet to be held. Most of these tenders are for solar project development. Share of wind and EPC tenders has been steadily falling. It is pleasing to see a surge of issuance in Maharashtra, the biggest power consuming state and a relative laggard in the sector.

Figure: Project location for tenders issued for which auctions are yet to be held

Source: BRIDGE TO INDIA research

Note: Jammu & Kashmir tender is for supplying power to other states.

MNRE has been keen on issuing more tenders since December 2017. However, actual progress has been much slower due to multiple instances of tender undersubscription and cancellation. Private sector response has dimmed in response to poor tender design, low tariff expectations and transmission sector bottlenecks. Ratio of successful project allocation to tender capacity issuance fell to a record low last year.

Figure: Tender issuance and auctions, MW

Source: BRIDGE TO INDIA research

As MNRE goes on another tender issuance spree, there is a growing sense of déjà vu. Lessons have not been learnt from past failures and this makes us believe that 2019 would be a repeat of the last year. First, power demand growth simply does not merit issuance of new tenders at such scale. Demand has picked up in the last six months to about 8% but we believe that this is a temporary boost ahead of the general elections as industrial activity remains subdued. Many DISCOMs are cautious about buying more RE power despite record low tariffs because of RE’s intermittency problem.

Second, we don’t see any room for tariffs to go down in the near-term as costs are expected to remain stable while economic and political environment is likely to be somewhat volatile. At the same time, competitive intensity in the private sector is falling. In such a scenario, investors are expected to be more cautious with capital raising posing significant challenges for most of the year.

In essence, there is a growing divergence between expectations of DISCOMs and procurement agencies on one hand, and project developers and their investors and lenders on the other hand. Unless the market becomes more investor-friendly, bidding environment is expected to remain challenging.

The state of Uttar Pradesh is gearing up to apply blockchain technology to the energy sector. In October 2018, UPERC, the state regulator, organized a conference on creation of an eco-system using blockchain technology to explore decentralized energy trading, track RE production and facilitate payment gateways for charging EVs. More recently, the regulator has proposed to allow peer-to-peer power transactions using blockchain technology in its rooftop solar PV regulation, 2019.

Blockchain, a nascent technology most often associated with cryptocurrency, is seen as a new frontier in the energy space. It is a distributed database technology that securely maintains a growing ledger of data transactions and other information among network participants. It is expected to change the way power is traded with new business models for peer-to-peer transactions between distributed power generators and storage facilities on one hand, and EVs and power consumers on the other hand. It can potentially allow power generators to set up dynamic smart contracts in response to ongoing changes in demand-supply and other market factors, creating a dynamic pricing system. The ability to record every asset, transaction and energy flow in a way that is tamper proof, verifiable and accessible to all participants could be transformational.

Internationally, Europe is the most active region for blockchain pilots, with utilities working on EV charging, connected home and wholesale trading and settlement. One of the early successful case studies for use of blockchain technology is the Brooklyn micro-grid project in New York that creates localized energy marketplaces for transacting energy across existing grid infrastructure. In October 2018, WePower, a European blockchain-based RE trading platform in collaboration with the local transmission operator shifted all their energy trading data onto blockchain.

In the Indian context, we believe that the regulatory system needs to change very fundamentally to exploit the potential of blockchain technology. According to the Electricity Act, 2003, no person/ entity is allowed to undertake trading or distribution of power without a license. Also, the Reserve Bank of India (RBI) has barred Indian banks from serving virtual currencies and cryptocurrency exchanges which are considered as the basic transaction entity in blockchain. It is hard to see how blockchain can be adopted in the energy sector unless the regulations are relaxed. For that, we need a consensus amongst policy makers, regulators and other stakeholders on wider reform of the power sector and viable mechanisms for blockchain adoption.

MNRE is reportedto have asked states to proactively issue more RE tenders and reduce dependence on central government agencies. MNRE’s advice states that states are better positioned to structure tenders based on their price expectations, offtake requirements and RPO obligations.

As per our tender database, the split between state and central government tenders is almost 50:50 over the past five years although wide variations can be observed on an annual basis.

Figure: Share of central and state government tenders

Source: BRIDGE TO INDIA research

Interestingly, we find that tariffs in state government tenders have been consistently higher than in central government tenders. This is understandable due to higher DISCOM risk perception in comparison to central government agencies. The difference varies from state to state – for example, Gujarat DISCOMs, being highly rated, procure power at same rates as SECI and NTPC, but lower rated DISCOMs (Uttar Pradesh, Tamil Nadu, Madhya Pradesh, amongst others) haver to pay much higher premium for their own tenders. The tariff difference has persisted over the years although it has come down from an average of about 25-35% three years ago to about 12% over time.

Figure: Weighted average tariffs in central and state government tenders, INR/ kWh

Despite having to pay a substantial tariff premium in their own tenders, most states have curiously preferred this route over buying power from SECI and NTPC. Rajasthan and Andhra Pradesh are the only exceptions as seen in the chart below. There is no rationale for this behaviour unless the DISCOMs and state governments intend to deliberately delay payments or default on their PPA obligations, not a viable option under central government tenders. The project developers, in contrast, have become more indiscriminate in their choice of tenders as evident from the gradually diminishing tariff premium.

Figure: State-wise share of tenders issued during 2014-18

Source: BRIDGE TO INDIA research

Note: This chart excludes pan-India, inter-state transmission based tenders issued by SECI and NTPC.

So why the unexpected advice from MNRE to states now? We believe that it is an attempt merely to speed up tender issuance by eliminating any possible friction or coordination time between different state and central government agencies. MNRE is focused on achieving the 100 GW target and is keen to expedite issue of tenders.

As 2018 comes to an end, we take stock of the progress made by the RE sector in the year. After finishing 2017 on a record high, total capacity addition is expected to fall by 32%. The fall is most notable in wind (down 46%), followed by utility scale solar (down 36%). In contrast, rooftop solar has grown by about 75%.

Source: BRIDGE TO INDIA research

The one significant positive during the year was module prices falling substantially – by more than 40% – after rising through H2 2017. The fall has helped to counter effect of GST, safeguard duty and Rupee depreciation making the low tariffs bid out in early 2017 (nearly) viable.

MNRE’s mega roll-out plan, announced at the end of 2017, failed to live up to expectations. Tender issuance rose markedly but many tenders had arbitrary tariff ceilings or were poorly structured and were undersubscribed as a result (manufacturing linked tender 10,000 MW, SECI Uttar Pradesh 275 MW, SECI pan India hybrid 1,200 MW, Assam 100 MW). Further, tenders with an aggregate capacity of 4,025 MW were cancelled because SECI and the DISCOMs found bid tariffs unacceptably high (SECI 2,400 MW, GUVNL 500 MW, UPNEDA 1,000 MW and GRIDCO 125 MW). Total final allocation is still considerably up on the last year at 19,166 MW (+171% yoy).

2018 was also the year when many on-paper risks, ignored in the frenzy of online auctions, became real. GST, safeguard duty and BIS guidelines have together presented huge headaches for the sector despite CERC clarifications on ‘change in law’ relief. Projects across the board have suffered delays due to these and other challenges in procuring land and transmission infrastructure. 12% annual depreciation in Rupee and almost 2% increase in interest rates made a big dent in project returns. It is not a surprise that the investors are finally becoming more cautious. Access to capital has become more difficult – many of the expected IPOs and large M&A deals have stalled and the sector is getting consolidated.

There were other notable disappointments. Distributed solar holds so much promise but there has been no progress on SRISTI (rooftop solar) and KUSUM (solar pump) schemes. Announcement of the purported national storage mission has kept getting delayed.

We believe that the low point for the year was MNRE’s unrealistic tariff expectations, accusations of cartelisation and open threats that bids would be cancelled if tariffs rise. The mismatch in expectations betrays lack of appreciation of challenges facing private developers and can be potentially very damaging to future prospects of the sector. India needs billions of dollars of private capital and the government needs to send out an altogether more positive message to the investors.

Indian RE had nice momentum at the end of 2017. But moving another gear has proved too difficult and instead, we have taken a step back. The sector needs new thinking, policy visibility and systematic government action to address specific challenges rather than radical actions.

The one significant positive during the year was module prices falling substantially – by more than 40% – after rising through H2 2017. The fall has helped to counter effect of GST, safeguard duty and Rupee depreciation making the low tariffs bid out in early 2017 (nearly) viable.

MNRE’s mega roll-out plan, announced at the end of 2017, failed to live up to expectations. Tender issuance rose markedly but many tenders had arbitrary tariff ceilings or were poorly structured and were undersubscribed as a result (manufacturing linked tender 10,000 MW, SECI Uttar Pradesh 275 MW, SECI pan India hybrid 1,200 MW, Assam 100 MW). Further, tenders with an aggregate capacity of 4,025 MW were cancelled because SECI and the DISCOMs found bid tariffs unacceptably high (SECI 2,400 MW, GUVNL 500 MW, UPNEDA 1,000 MW and GRIDCO 125 MW). Total final allocation is still considerably up on the last year at 19,166 MW (+171% yoy).

2018 was also the year when many on-paper risks, ignored in the frenzy of online auctions, became real. GST, safeguard duty and BIS guidelines have together presented huge headaches for the sector despite CERC clarifications on ‘change in law’ relief. Projects across the board have suffered delays due to these and other challenges in procuring land and transmission infrastructure. 12% annual depreciation in Rupee and almost 2% increase in interest rates made a big dent in project returns. It is not a surprise that the investors are finally becoming more cautious. Access to capital has become more difficult – many of the expected IPOs and large M&A deals have stalled and the sector is getting consolidated.

There were other notable disappointments. Distributed solar holds so much promise but there has been no progress on SRISTI (rooftop solar) and KUSUM (solar pump) schemes. Announcement of the purported national storage mission has kept getting delayed.

We believe that the low point for the year was MNRE’s unrealistic tariff expectations, accusations of cartelisation and open threats that bids would be cancelled if tariffs rise. The mismatch in expectations betrays lack of appreciation of challenges facing private developers and can be potentially very damaging to future prospects of the sector. India needs billions of dollars of private capital and the government needs to send out an altogether more positive message to the investors.

Indian RE had nice momentum at the end of 2017. But moving another gear has proved too difficult and instead, we have taken a step back. The sector needs new thinking, policy visibility and systematic government action to address specific challenges rather than radical actions.

BRIDGE TO INDIA has just completed the latest round of rooftop solar data compilation exercise. India added new rooftop solar capacity of 1,538 MW in the year ending September 2018, up a remarkable 75% over previous year. Total installed capacity is estimated to have reached 3,399 MW as on 30 September 2018.

Robust growth even in the face of safeguard duty and GST uncertainty reflects huge market potential of rooftop solar;

The government’s rooftop solar policy stance is outdated and lacking in vision;

Focus needs to evolve from reducing cost (capital subsidies, tax incentives and cheaper credit) to bolstering market confidence and tackling operational challenges;

We believe that 75% market growth in a year plagued by safeguard duty and GST uncertainty is absolutely fantastic. Ongoing fall in module prices should continue to drive growth in the next few years. The other notable aspect of market growth is that it has come despite rooftop solar policy stuck in a dead-end. The market has moved significantly in the last few years with rapid fall in capital cost, changes in business models and improved technical and operational experience of the industry. But government policy has hardly changed in the last few years. It remains predicated on capital subsidies, accelerated depreciation and an out-of-date net metering connectivity framework. There have been no new initiatives since announcement of the concessional credit scheme back in 2015. Inexplicably, there has been no progress on the promising proposals announced in December 2017. MNRE has even quietly scaled down the annual rooftop solar target for 2017-18 from 6,000 MW to 1,000 MW.

We think that lack of government policy initiative is a missed opportunity. Rooftop solar has huge growth potential and should be given more policy support particularly when utility scale solar is increasingly facing acute land and transmission connectivity challenges. Its share in total solar capacity addition has already gone up to 16% from 10% in three years. And we believe that this could go up to as high as 40% by 2022 in a strong policy support scenario.

The market is growing rapidly but still faces many hurdles. Concerns of DISCOMs, who see rooftop solar as a threat, need to be addressed through technical and financial support. The net metering policy framework needs an overhaul to accommodate new business models and do away with unnecessary caps on system sizes. Uptake of rooftop solar in residential and SME segments needs to be boosted by addressing poor consumer awareness and financing constraints.

Proactive government intervention can help in boosting growth and realising full potential of this compelling energy source.

Global solar demand is expected to fall for the first time ever this year – to about 85-90 GW from 103 GW last year. Most of the leading countries including China, India, US and Japan are reporting significant declines in capacity addition. Result – multi-crystalline module prices have fallen to USD 0.22/ W, down nearly 40% in the last nine months and are predicted widely to fall further to USD 0.18-0.19/ W by Q2 next year. This price crash is having a profound impact on the entire sector value chain.

Bigger module manufacturing players are breaking away from the industry by expanding aggressively and investing in new technologies;

There are question marks over long-term survival prospects of smaller players;

In a fast-moving industry subject to fierce pressure, the project developers need to be extra cautious in choosing equipment suppliers;

It is difficult to know how the module manufacturers will ride out these tough conditions. On one hand, the industry is getting consolidated with a new ‘super league’ of players with 5-10 GW of global capacity. At the same time, aided in part by China’s Top Runner programme, some players (LONGi, GCL, Tongwei) are making aggressive investments in new technologies and expanding their footprint. The module technology landscape, dominated by plain multi-crystalline modules for long, is suddenly looking like a rainbow. Development of new technologies and form factors – n-type, mono and mono-PERC, half-cut cells, IBC, HJT, bifacial, frameless and glass-glass modules – is adding complexity to the business. And even though the module players have benefited from large price falls in upstream polysilicon industry (see chart below), it is feared that many of the smaller tier-2 and tier-3 players in China may undergo a financial collapse. But that is dependent on Chinese government policy and plans for the sector (there are some talks that China may increase its 2020 solar target by as much as 60 GW).

Figure: Module manufacturing value chain, USD/ W

For the project developers, changes in the module industry pose all kinds of challenges. At a recent conference, some developers seemed confused – they were unhappy that the module manufacturers are pushing new technologies and products without proven track record. Some even complained that project design process is becoming too cumbersome as they have to run multiple design configurations. More pressing concerns relate to quality, bankability and after-sales service in a fast-moving industry subject to fierce price pressure.

Nonetheless, the Indian developers, facing their own viability challenges, are increasingly buying (cheaper) modules from relatively smaller and/ or unknown players. The short-term price focus may not be a wise move in these times.

Figure: Market share of module suppliers in Q3 2018

Source: India Solar Compass Q3, 2018, BRIDGE TO INDIANote: This data is for utility scale projects commissioned in the quarter.

In the first nine months of this year, 10,081 MW of utility scale solar capacity has been auctioned, up nearly 70% over the entire year 2016. A close look at the auction results shows some very interesting trends – despite the sharp increase in auctioned capacity, number of winning bidders has fallen to 26 from 49 two years ago. Average winning bid size has increased to 124 MW from 63 MW. And market share of top five developers has increased to 65% from 47% in 2016.

Smaller players are being squeezed out by adverse risk profile, increasing volatility in the sector and stagnation in secondary market activity;

With M&A activity being relatively slow, consolidation is being dictated by the primary market;

As much as 50% of total wind and solar capacity may be stranded if current owners are not able to find successful exits;

Figure: Top winning developers in utility scale solar auctions

Source: BRIDGE TO INDIA research

Market consolidation is a sign of evolving maturity of the Indian solar sector. Competitive bidding and capital-intensive nature of the sector mean that scale is becoming increasingly more important. Larger players benefit not only from procurement and execution efficiencies but also greater access to financing and better ability to absorb risks. The smaller players are unable to cope with adverse risk profile and increasing volatility in the sector.

An especially interesting aspect of this consolidation is that it is being dictated by primary market. The secondary route ie, M&A has failed to take off, unlike in most other countries. Deals have been held back by mismatch in valuation expectations, poor corporate governance norms and sub-standard construction quality. That scenario is unlikely to improve anytime in the near future particularly as interest rates are on the way up. In a declining rate environment, refinancing provided a sweet upside to the sellers and acted as a deal catalyst. But the trend has reversed. We estimate that a 2% increase in senior debt cost can depress equity valuation by as much as 15%.

Our research shows that successfully completed M&A deals in the last