Month: November 2019

After staying relatively stable in the past year, module prices are on the decline again. Prices of multi-crystalline modules, still the de facto choice for most Indian developers, have fallen from USD 0.23/ W to USD 0.20/ W in the last six months. Cost delta between low efficiency modules and high efficiency mono-PERC has also halved to about USD 0.02/W. Alongside fall in module prices, inverter prices and balance of system (BOS) costs have been falling steadily too (see chart below). As a result, total EPC cost including safeguard duty of 20-25% on modules and 8.9% effective GST has fallen by 13% to INR 27.60/ Wp in the same period.

Module prices are falling steadily as supply is rising sharply but international demand remains stagnant;

Short-term cost outlook is positive with prices expected to reduce further through early 2020;

The industry needs to guard against risk of disruption in international trade policies, logistics or foreign exchange markets due to high dependence on equipment imports;

The module price fall owes mainly to continued demand slowdown in China. After touching a high of 53 GW in 2017, demand has been falling steadily with latest estimates for 2019 suggesting annual capacity addition at only about 25 GW. Demand has risen elsewhere, most notably in Europe, where solar capacity addition has doubled in the last two years to touch an estimated 20 GW this year. Aggregate global demand is believed to stay broadly flat at about 120 GW. In contrast, the module manufacturers have been expanding ferociously. Some of the latest numbers coming out of China, in particular, are mind boggling – Jinko, the industry leader by shipment volumes, expects to supply 20 GW modules next year, up from just 4.5 GW in 2015. LONGi is considering expanding its module manufacturing capacity from 9 GW in 2018 to 30 GW by 2021. Most other leading players including Canadian Solar, Trina, First Solar, JA and Risen are planning similar scale expansions. 

Figure: Total EPC and component cost trends

Source: BRIDGE TO INDIA researchNotes: Cost data is shown using Q1 2018 numbers as benchmark. For modules and inverters, we have used CIF price before any local tax or duty. Total EPC cost includes GST and safeguard duty as applicable. 

Outlook on the cost front remains positive. Prices are expected to reduce further through early 2020. Safeguard duty on modules and cells would also fall to 15% in January 2020 and be phased out completely by the end of July 2020. That alone would reduce EPC cost by 12%. 

Amid all the recent doom and gloom in the sector – PPA renegotiation, delayed payments, undersubscribed tenders, debt financing challenges – fall in capital costs provides welcome respite to the developers. It should help in improving financial returns and raising capital for the projects. However, over-dependence on China raises the risk of potential disruptions in international trade policies, logistics and foreign exchange markets.

Last week, a news report suggested that Madhya Pradesh DISCOMs have accumulated losses of INR 250 billion (USD 3.5 billion). The DISCOMs have requested the state regulator to allow increase in grid tariffs for recovery of losses. It is feared that average power tariff may have to rise by INR 2.00/ kWh or more as a result. The situation is similarly grim in Tamil Nadu, where aggregate DISCOM losses have touched INR 1 trillion (USD 14 billion) because tariffs have stayed flat for five years. The state government is not even allowing the DISCOM to present a tariff increase petition to the regulator. 

Tariffs have failed to keep up with rising costs across most states;

There seems to be rampant misreporting in financial numbers by DISCOMs with various errors reported by external observers;

While long-term reform is deliberated, meaningful tariff hikes can provide much needed relief to the DISCOMs and power producers;

Madhya Pradesh and Tamil Nadu are not isolated examples. Combined DISCOM losses increased by 89% in FY 2018-19 to INR 284 billion as tariffs have failed to keep up with rising costs. To make matters worse, the state governments and public sector consumers are falling further behind in making subsidy and power purchase payments respectively to the DISCOMs. At the same time, post UDAY, banks have cut lending lines to DISCOMs, who have been under pressure to supply 24×7 power throughout the country at subsidised tariffs.

This is a perilous position for the entire power sector and it is not a surprise that payment delays to power producers are rising alongside other insidious practices of curtailment and tariff renegotiation. Worryingly, actual picture may be even worse as there is a question mark about reliability of financial numbers put out by DISCOMs. Last year’s results have been already revised by several DISCOMs. A recent report by Prayas, an energy think-tank, on growing use of subsidies in power distribution contends that: i) subsidy amounts are often not (correctly) reported by the states even to Power Finance Corporation, a Government of India-owned financial institution and the only entity to undertake any kind of financial assessment of DISCOMs; and ii) there are significant discrepancies in detail, terminology and accuracy of subsidy information in various regulatory documents filed by the DISCOMs.

As the following chart shows, with the exception of Karnataka, grid tariffs have stayed broadly flat or even declined in most states over the last five years. 

Figure: Grid tariffs over last five years, INR/ kWh

Source: BRIDGE TO INDIA research, state tariff ordersNote: Figures shown represent energy charge only. Electricity duty, cess and other surcharges including fuel adjustment surcharge are excluded. 

The Ministry of Power has been talking up sector reform in recent months. Various ideas have been mooted including UDAY 2, revised National Tariff Policy and amendments to Electricity Act to make DISCOMs financially sustainable. But there is little actual progress. While these long-term measures are deliberated and implemented, the government needs to bite the bullet and effect meaningful tariff hikes across consumer categories to avoid the crisis spiralling out.

For RE, a substantive grid tariff hike would be beneficial in many ways. Besides reducing offtake risk, it would spur power demand from DISCOMs, and result in better prospects for open access and rooftop solar markets. 

In a major relief to the sector, MNRE has granted project completion deadline extension to wind projects allocated under SECI auction tranches 1-5. More time has been granted to these projects mainly because of delays in land allocation and completion of transmission infrastructure. A total capacity of 7,200 MW was allocated by SECI in these auctions between Feb-2017 and Sep-2018, but only 1,825 MW has been commissioned so far. 

Heavy concentration of projects in Gujarat has exacerbated land and transmission connectivity delays;

The developers face a multitude of other challenges on supply chain, debt financing and project clearance fronts;

Progress is likely to remain slow with total capacity addition estimate of only 9 GW over next three years;

Figure: Developers with pipeline projects in SECI wind auction tranches 1-5, MW

Source: BRIDGE TO INDIA researchNote: This chart excludes commissioned projects. 

Since February 2017, wind projects aggregating 12,265 MW have been allocated under auction route by various central and state government agencies. Based on the mandated completion deadline of 18 months, 5,000 MW of these projects should have been commissioned by now. But only 2,128 MW has been actually completed. The issue is mainly lack of suitable land at acceptable price. More than 75% of total tendered capacity is estimated to be coming up in Gujarat with most of the balance being located in Tamil Nadu. However, late last year, Gujarat refused to allocate state land for central government schemes. This left the developers in a bind – moving to other states was not viable due to low wind speeds and time constraints, and buying private land at 3-4x the cost of government land was simply unaffordable. Under persistent pressure from the central government and developers, the state is believed to be in the process of finally allocating land for the projects. 

The developers face yet more hurdles. All projects in Gujarat need approval from the Ministry of Defence, which can be time consuming. The turbine market has shrunk due to debt woes afflicting Suzlon and Senvion, and many of the smaller suppliers being squeezed out of the market. Lack of bankable turbine makers, willing and able to take large scale lump sum EPC contracts, is bound to affect execution timelines as well as cost. Layering debt financing challenges on top of these problems being faced by the sector currently means that there is a growing risk of some projects being abandoned altogether. 

After a bumper FY 2017, when 4,564 MW of new wind capacity was added, the sector has been in a slow, gut wrenching mode. Capacity addition in FY 2018 and FY 2019 stood at only 1,788 MW and 1,819 MW respectively. Our estimate for total capacity addition over next three years until the end of FY 2022 is around 9 GW. 

Last week, SECI conducted auction for a 1,200 MW utility scale solar tender. The tender received bids for full 1,200 MW but the auction was completed for only 960 MW, equivalent to 80% of the bids received, as per the rules in place. ReNew, Avaada and UPC Renewables won 300 MW each at a tariff of INR 2.71/ kWh; Tata Power won the remaining 60 MW at INR 2.72/ kWh. The developers are free to locate projects anywhere in the country and seek inter-state transmission system (ISTS) connectivity. 

Tariffs have finally started inching up but the increase is not commensurate with various operating and financial risks assumed by developers;

The uniquely open and transparent nature of renewable auctions has created an extremely competitive market;

In the rush to raise more money and build more capacity, most of the leading developers have failed to create any lasting competitive advantage;

The auction is unremarkable for all intents and purposes except that the tariffs have finally started inching up a little. These are the highest ever tariffs in a SECI or NTPC solar ISTS tender. However, the increase is only about INR 0.20 or 6-8% over average tariffs seen in the last two years. Indeed, the surprise is that tariffs have not increased faster in response to various cost increases as well as teething execution and financing hurdles faced by developers. 

How to explain continued investor interest and competitive dynamics in the sector? The answer lies primarily in the massively scaled up, fully transparent auction programme developed by the Indian government. It has (arguably) played a winning hand by creating a near level-playing field and reducing project bidding to a single point online game – tariff. In an already commoditized sector, there is no premium for developers to deploy advanced technology, deliver more reliable plants, reduce land or water requirement, or tailor power output profile to match demand curve. In the process, the government has managed to attract some of the world’s biggest strategic and financial investors including utilities, IPPs, business conglomerates, sovereign wealth funds, pension funds and PE funds. 

On their part, the investors have found lure of deploying huge chunks of capital in a sector with high growth prospects and green credentials too hard to resist. Many of the leading developers have simply followed the motto of ‘raise money, build more’ and struggled to create a lasting competitive advantage. Setting aside financing, it is almost impossible to identify any winning strategy or undertake any meaningful comparative analysis in the project development business. On the contrary, in the rush to raise money and build projects, many developers have cut corners on risk, project quality and long-term business planning. 

Lessons ought to have been learnt after all the problems faced over past two years. For sure, there is more risk aversion and return expectations have increased marginally as evident in the recent tender results. But unless the developers build a true competitive advantage (assuming that the government allows them to), they are likely to be chasing elusive returns in an overcrowded market.

MNRE has announced various changes to the competitive bidding guidelines for utility scale solar projects. There are broadly two categories of changes – to address offtake risk and improve execution timelines. 

On offtake risk, the government has proposed full compensation in the event of power back-down and bolstering of the payment security fund;

Measures to improve timelines include more time for land documentation, deemed tariff approval by the regulator in the event of delays and protection from government failure to issue project clearances;

The changes are highly welcome and seem to have come in response to growing concerns about poor risk profile of RE projects and falling investor interest;

Mitigation of offtake risk seems to be the biggest objective. First, in the event a solar plant is asked to back down, other than for grid security or safety reasons, the developers would be offered 100% compensation (previously 50%) for loss of power output. With growing instances of curtailment across many states, the provision of only 50% compensation was increasingly untenable. Heeding further the demands of project developers, the amendment also specifies that no backdown may be ordered without formal written instruction and that the details of such backdown need to be made public by the concerned Load Dispatch Centre. 

Second, there is a new provision for top-up tariff, whereby the ultimate offtakers are required to pay an extra INR 0.10/ kWh in case they are not able to provide state government guarantee to cover their PPA obligations. But this amount would be payable only to intermediary offtakers (for example, SECI or NTPC) for topping up the three month payment security fund maintained by them. It is a positive step but the amount is too small at about 3-4% of power tariff. The government ought to consider enhancing this amount as well as widening ambit of this clause to projects where there is no intermediary procurer.

Third, the developers are required to contribute INR 500,000 per MW of project capacity towards the payment security fund maintained by intermediary procurers. They would not be very pleased to cough up this amount as maintaining payment security should really be an obligation for the offtakers. The contribution would increase capital cost and raise tariff expectations by about 1%, both unwelcome in times of cash crunch. The amount is insubstantial though and would not be adequate to cover even one month of revenue shortfall. 

There is also an attempt to introduce more certainty on the project execution time-table. As land acquisition and subsequent documentation formalities have posed teething problems in many states, the developers are now given time until COD to complete these requirements as against only 12 months earlier. In response to another problem faced by many projects relating to delay in approval of project tariffs by the regulators, the amendment proposes deemed approval if the regulators fail to issue a decision within 60 days of application. 

The last material change in the guidelines is introduction of the concept of non-natural force majeure, in particular, failure of a government authority to provide any project clearances. If such an event persists for more than 6 months, the developers are entitled to terminate PPA and seek full termination compensation as under the offtaker default scenario. 

The changes are highly welcome and seem to have come in response to concerns about deteriorating risk profile of RE projects and falling investor interest. They are also consistent with the recent draft guidelines for solar-wind hybrid projects. But the move is largely reactionary and akin to a sticking plaster. To build new growth momentum, RE needs a new procurement model and some fresh thinking. MNRE guidelines are not binding on the DISCOMs in theory, but they would be compelled to accept these changes as investors get more demanding.