Category: Market Outlook

The year 2013 has been good for investors in solar companies listed on the US stock market. Manufacturers like SunPower, Yingli, Jinko, First Solar, ReneSola and Trina have all had a spectacular bull run with share values of companies like Trina more than tripling over the year. SolarCity, the rising star of distributed installations in the US, has seen a five-fold jump in stock price. All this is good news for the market as a whole as well. The global solar market seems to have now stabilized from its over-capacity in 2012 and 2013. New installations in 2014 are expected to grow beyond 40 GW, largely driven by the US, China and Japan.

Jinko recently announced that it would completely separate its projects business from the manufacturing business

Stock prices of Indian solar companies had been in a free fall during the greater part of 2013 until the announcement of Domestic Content Requirement (DCR)

Improving global demand for solar is likely to help with export that has been the lifeline of manufacturers in India

Due to over-capacity and dwindling margins, most large global manufacturers had to integrate downstream into project development to create an in-house demand for their modules. Now, these companies are viewing their project development businesses as a separate opportunity in itself. As an example, Jinko recently announced that it would completely separate its projects business from the manufacturing business and it will acquire a 500 MW production line, currently owned by Topoint Group (refer).

This global trend is currently not replicated in India. Even though India has grown to become a 1 GW market in 2012 and 2013, domestic manufacturers haven’t been as lucky as their international counterparts. The stock prices of the few publicly listed companies like Moser Baer, IndoSolar and Webel Energy had been in a free fall during the greater part of 2013, until the announcement of Domestic Content Requirement (DCR) for phase two of the NSM provided a small relief rally. This too is fizzling out in the early days of 2014.

Despite a couple of bad years that have inflicted a lot of damage on some of the manufacturers, some of whom were even forced to shut down manufacturing lines, there is still a silver lining. DCR is expected to provide these manufacturers some breathing room and allow the closed cell capacity to restart again. Over and above that, the improving global demand is likely to help with export that has been the lifeline of manufacturers in India to begin with.

This post is an excerpt from this week’s INDIA SOLAR WEEKLY MARKET UPDATE. Sign up to our mailing list to receive these updates every week.

You can view our archive of INDIA SOLAR WEEKLY MARKET UPDATES here.

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Solar irrigation pumps in India could be a very attractive market. They could replace diesel powered pumps in many parts of India’s agricultural heartlands, especially in the under-electrified Gangetic plains. They could even increase agricultural output by making more irrigation water available to farmers. However, at the moment, neither the products nor the distribution chains are anywhere near maturity. I recently served as a jury member on a Greenpeace Innovation Challenge to develop a new solar pump. The challenge was initiated by the Greenpeace Innovation Lab and conducted online, across the world and in a collaborative manner. This blog is part one of a three part series, in which I look at the market. The other two parts look at the new pump design and at how online innovation processes can help identify and spread solutions.

Around 300 million Indians still have no grid power. Another 300 million have only very unreliable grid power. Most of them live in rural areas

Only 12,000 solar pumps were sold in 2012, indicating that the current product designs find it hard to compete

The market for diesel pumps in India is ca. 2 million pumps at ca. INR 80bn (USD 1.3bn) per annum

It was my first trip to Patna. The capital of the state of Bihar and formerly of the ancient empire of Magadha, cannot be described as a beautiful city. It offers its 2 million inhabitants barely a village infrastructure. Pollution and noise are at extreme levels. So is population density. I got stuck for an hour in a honking traffic inferno next to a park designed for meditation. Despite its fertile soil, its famously brainy people and the good efforts of a competent government, Bihar is still a desperately poor part of the world.

A two-hour drive out of the city brings me to a small village. The countryside is lush green and the air is clean. Large power transmission lines run over the fields. Bihar used to be a major center for coal mining and is in India’s most resource rich region. However, none of the electricity seems to be intended for the people here. The village we come to has no grid power. There is an old distribution line, so it presumably counts as ‘electrified’, but it is defunct.

It is villages such as this, one of thousands in India, where people need off-grid power solutions. Almost 600m Indians still don’t have reliable grid power supply. A couple of houses in the village have individual solar modules on the roof. They can be bought at the local market and power mobile chargers, light bulbs or fans. Greenpeace wants to set up a solar and biomass fueled micro-grid here, together with the local energy pioneer Husk Power Systems and the microfinance company Basix.

It could also be an ideal place for solar irrigation pumps. Water is currently pumped either manually or using expensive diesel. Land for solar is available. Pumped water is a great ‘storage’ solution for the intermittency of solar. The cost of solar panels has plummeted in the past years. A 10 W solar home system, which can light a bulb and charge a mobile phone, is currently offered in rural India at a price of around INR 3,000 (USD 50), barely more than a goat.

India wide, there are currently around 10 million diesel pumps in operation. The average lifespan of a pump is approximately 5 years. Older models burn diesel to directly run a ground-mounted pump. Newer, more efficient models are submersible and run on electricity from a diesel gen-set. Depending on the depth of the water table, they are rated at between 1 and 10 horsepower (0.7-7 kW). Installation of a diesel pump costs anywhere between INR 20,000-80,000 (USD 300-1,300). If the average price is INR 40,000 (USD 667), this is an INR 80bn (USD 1.3bn) market each year. If the average pump size is 3 kW, the total installed diesel pump capacity in India comes to 30 GW, equivalent to almost 1/6th of the country’s total installed power generation capacity.

Diesel pumps, however, have four disadvantages: their fuel is costly; they deplete the water table more than necessary by pumping heavily at short intervals; they create local pollution and carbon emissions; in addition, diesel is often a hassle to get. Solar based pumping systems would be better on all four accounts. Yet only around 12,000 systems were installed in 2012. That is a market share of less than 1%. Why is that the case?

Solar pumps, so far, typically have the following flaws from a consumer’s perspective: First of all, they are too expensive. This is not so much an issue of the lifetime cost, but rather with liquidity. Diesel is expensive, but cash outs are spread over time, as fuel has the major share of the lifetime cost. Solar has to be paid for upfront. In addition, diesel pumps are a highly standardized, off-the-shelf-product. This reduces cost. Solar pumps are still at an early stage of product maturity. Secondly, diesel pumps are an established product. They have sales channels and consumer finance solutions. Many distributors and banks are still reluctant to bet on a new product like solar as long as the old one is being sold just fine. This point is also important from a customer trust perspective: diesel pumps are proven. Anyone thinking of buying one can see it in operation on a neighbor’s plot. Thirdly, diesel pump sets are portable. Solar pumps are not. Portability is important as it protects the system from theft (can be stored at night) and it makes it easily usable across different locations and users. It can be rented out and it can be easily brought to villages for demonstration purposes.

In order to encourage designs that can overcome these drawbacks and make solar water pumps attractive, Greenpeace started the innovation challenge. In my next blog, I discuss how this challenge was framed and what the resulting solutions were.

Tobias Engelmeier is the Managing Director at BRIDGE TO INDIA.

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Media reports claim that Kerala’s ambitious rooftop plan to set up 10,000 off-grid solar power plants would be missing the deadline. However, based on our interaction with the officials, it seems that the program is likely to be completed well ahead of schedule as per the December 2014 deadline set by MNRE. As of now, around 6,000 plants have been commissioned and the rest are already in pipeline. However, another program announced last year that aims at installing 25,000 grid connected rooftop power plants, faces delays and no power plant has been commissioned under the policy as yet.

The 10,000 rooftops program is the first of its kind in India to incentivize off-grid power plants

State electricity board in Kerala is hesitant to connect rooftop power plants below the 11 kv line

State policies for rooftop solar should be made self-reliant and not dependent on central government grants

The 10,000 rooftops program (refer) is the first of its kind in India to incentivize off-grid power plants at this scale. It not only makes a lot of sense for Kerala, considering the substantial power deficit in the state, but also proposes attractive incentives to consumers by allowing state subsidies apart from the central ones. Despite the fact that there have been significant delays with the subsidy disbursement (complete subsidies have only been disbursed to around 1,000 systems) and issues with facilitation of low cost interest loans, the rooftop program is on track. The timely implementation of the project can be attributed to the streamlined processes under the program in terms of selection of vendors, dual subsidy mechanism, price benchmarking and quality assurances.

On the other hand, the 25,000 grid connected power plant program will likely be delayed due to issues with net metering, energy accounting and handling grid connectivity. As per BRIDGE TO INDIA conversations, the state electricity board in Kerala is hesitant to connect the rooftop power plants below the 11 kV line as it might face energy accounting challenges. Kerala now wants to increase the cut-off size of individual rooftop projects to have them connected to the 11 kV line.

Nevertheless, being the first state to announce and implement a distributed solar program in India at this scale, it is noteworthy that Kerala might successfully complete the 10,000 rooftop program ahead of schedule. It is a good case study for the other states that have recently announced or are in the process of formulating their rooftop policies or schemes. These include Tamil Nadu (refer), Uttarakhand (refer), Gujarat (refer) and Karnataka (refer).

The key learning from delays in subsidy disbursement in Kerala is to make a policy self-reliant and not dependent on central government grants. Secondly, a policy for grid-connected rooftop projects needs to be accompanied with timely implementation of net metering. States that have communicated ambitious plans need to now focus on solving the ground level challenges such as grid connectivity, improvement of grid infrastructure and reducing the power deficit.  This will enable a successful transition of solar in India from centralized large scale to small-scale rooftop.

Developers are in the process of finalizing their bids for National Solar Mission (NSM) projects. The use of Viability Gap Funding (VGF) mechanism for the first time, resulting in significantly different cash flow profiles, poses many interesting questions for developers. Financial structuring will play a very important role in determining bid outcomes.

SECI has the right to claw back VGF in case of project underperformance. Hence, lenders will not allow VGF to be used for capital repayment to a developer

Top-tier sponsors that can provide corporate guarantees or recourse to lenders will likely benefit from most competitive financing

If adequate sponsor support is not available, the lender is directly concerned with the risk associated with the treatment of VGF disbursement

As VGF is disbursed only after construction, developers need to finance the entire capital cost upfront. It is worth bearing in mind the key headline numbers: i) normative capital cost of a plant of INR 65m/MW (USD 1m/MW, EUR 0.8m/MW); ii) VGF of INR 10m/MW (USD 160,000/MW, EUR 120,000/MW); iii) Solar Energy Corporation of India’s (SECI’s) minimum equity investment stipulation of INR 15m/MW (USD 240,000/MW, EUR 177,000/MW); and iv) lenders expect to provide no more than 70-75% of total project cost as senior debt.

Project developers might argue that subject to satisfaction of key lender covenants, the bulk of the financing requirement above their minimum equity investment of INR 15m/MW (USD 240,000/MW, EUR 177,000/MW) should come from debt financing. And in order to improve their bid competitiveness, they would like the VGF disbursement to be used to distribute capital back to themselves as equity providers (suggesting possible use of preference capital or shareholder debt structures).

The problem, however, arises due to SECI’s right to claw back the VGF in case of project underperformance. Senior lenders will likely see a serious risk in this and will therefore not allow VGF to be used for capital repayment to a developer. They may even argue that VGF is pure equity risk. Notwithstanding the recent revision, whereby SECI has accepted second claim on project assets, they may want to see a structure that has sufficient cushion for both senior debt and VGF in an underperforming project. This opens up opportunities for gaining a competitive advantage through financing structures around, equity structures, letters of credit, corporate guarantees, etc. For example, top-tier sponsors, which can provide corporate guarantees or recourse to lenders, will likely benefit from the most competitive financing. This puts pure play solar IPPs at a disadvantage vis-a-vis larger industrial houses. (And they are already limited by not being able to make effective use of accelerated depreciation options. See our previous blog here.)

In addition, if adequate sponsor support is not available, the lender is directly concerned with the risk associated with the treatment of the VGF disbursement: Should VGF stay in an escrow account for the lenders security (very inefficient from the point of view of the developer)? Or should it go to repay senior debt? Or will debt/equity be able to come to a mutual agreement? Could strong EPC/O&M guarantees provide some answers? Interesting possibilities!

This post is an excerpt from this week’s INDIA SOLAR WEEKLY MARKET UPDATE. Sign up to our mailing list to receive these updates every week.

You can view our archive of INDIA SOLAR WEEKLY MARKET UPDATES here.

What are your thoughts? Leave a comment below.

Developers are in the process of finalizing their bids for National Solar Mission (NSM) projects. The use of Viability Gap Funding (VGF) mechanism for the first time, resulting in significantly different cash flow profiles, poses many interesting questions for developers. Financial structuring will play a very important role in determining bid outcomes.

As VGF is disbursed only after construction, developers need to finance the entire capital cost upfront

Senior lenders will not allow VGF to be used for capital repayment to a developer due to SECI’s right to claw back the VGF in case of project under performance

If adequate sponsor support is not available, the lender is directly concerned with the risk associated with the treatment of VGF disbursement

As VGF is disbursed only after construction, developers need to finance the entire capital cost upfront. It is worth bearing in mind the key headline numbers: i) normative capital cost of a plant of INR 65m/MW (USD 1m/MW, EUR 0.8m/MW); ii) VGF of INR 10m/MW (USD 160,000/MW, EUR 120,000/MW); iii) Solar Energy Corporation of India’s (SECI’s) minimum equity investment stipulation of INR 15m/MW (USD 240,000/MW, EUR 177,000/MW); and iv) lenders expect to provide no more than 70-75% of total project cost as senior debt.

Project developers might argue that subject to satisfaction of key lender covenants, the bulk of the financing requirement above their minimum equity investment of INR 15m/MW (USD 240,000/MW, EUR 177,000/MW) should come from debt financing. And in order to improve their bid competitiveness, they would like the VGF disbursement to be used to distribute capital back to themselves as equity providers (suggesting possible use of preference capital or shareholder debt structures).

The problem, however, arises due to SECI’s right to claw back the VGF in case of project underperformance. Senior lenders will likely see a serious risk in this and will therefore not allow VGF to be used for capital repayment to a developer. They may even argue that VGF is pure equity risk. Notwithstanding the recent revision, whereby SECI has accepted second claim on project assets, they may want to see a structure that has sufficient cushion for both senior debt and VGF in an underperforming project. This opens up opportunities for gaining a competitive advantage through financing structures around, equity structures, letters of credit, corporate guarantees, etc. For example, top-tier sponsors, which can provide corporate guarantees or recourse to lenders, will likely benefit from the most competitive financing.

This puts pure play solar IPPs at a disadvantage vis-a-vis larger industrial houses. (And they are already limited by not being able to make effective use of accelerated depreciation options. See our previous blog here.)

In addition, if adequate sponsor support is not available, the lender is directly concerned with the risk associated with the treatment of the VGF disbursement: Should VGF stay in an escrow account for the lenders security (very inefficient from the point of view of the developer)? Or should it go to repay senior debt? Or will debt/equity be able to come to a mutual agreement? Could strong EPC/O&M guarantees provide some answers? Interesting possibilities!

The January 2014 edition of BRIDGE TO INDIA’s quarterly publication, the India Solar Compass, has been released. The new edition focuses on the current state of the Indian solar market which is in transition from being an incentive driven market to a parity driven market. A gist of this edition of the Compass is given below.

A positive implication of the transition is a possible shift from utility scale market to a more distributed generation market

A drawback of the state rooftop policies is that most of them rely largely on funding support from the MNRE which is suffering a funding crunch

NSM will not result in any capacity addition in 2014 but will provide a renewed vigour for investments and rapprochements in the second half of 2014

A positive implication of this transition is a possible shift from utility scale market to a more distributed generation market. It is expected that 2014 will lay the groundwork for the rooftop solar market in India. Net-metering will be a crucial determinant of the same. In the policy space, it is encouraging to see that several state and central policies have announced measures to promote the rooftop solar market. Subsidies, feed-in-tariffs (FiTs) and net/gross metering concepts are being introduced across different policies.

One drawback of the state rooftop policies is that they rely largely on funding support from Ministry of New and Renewable Energy (MNRE) which has been suffering a funding crunch. With the general elections around the corner in India, no new fund allocations are expected before the new government is formed.

Outside of the rooftop sector, there has also been some action in ground mounted projects for captive consumption or third-party sale of power. Most of these projects are driven by accelerated depreciation (AD) or Renewable Energy Certificates (RECs). Given the challenges facing the REC mechanism, future of these projects is uncertain unless they can sign commercially viable PPAs with bankable counterparties. State level incentives such as a waiver of open access charges can play a significant role here.

In 2014, new solar PV capacity of 750 MW is expected in India. Tamil Nadu, Andhra Pradesh, Uttar Pradesh and Punjab will likely sign PPAs within the next few months. NSM will not result in any capacity addition in 2014 but will provide a renewed vigour for investments and procurements in the second half of 2014 with capacity additions materialising in 2015.

Click here to download for free and read the full report.

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Recent reports indicated that India’s Department of Atomic Energy (DAE) is in an uncomfortable situation as the cost of power from its new nuclear power projects appears to be too high (refer). It has been reported that the cost per unit at the 9,900 MW Jaitapur Nuclear Power Plant is around INR 9 (EUR 0.11/ USD 0.15) per kWh. At the 6,000 MW Mithi Virdhi Nuclear Power Plant costs may even be as high as INR 12 per unit (EUR 0.15/ USD 0.20).

Due to the risk perception of nuclear power, many projects face opposition from the public leading to significant delays

Renewable sources of power are much more promising in terms of cost and speed

Currently, India needs to look at all available sources of power, including nuclear, to meet its power deficit and rapidly rising demand

The high cost of nuclear power is explained by the capital costs of installing nuclear power plants which are in excess of INR 300 million (EUR 3.75 million, USD 5 million) per MW, with the Mithi Virdhi Nuclear Power Plant costing nearly INR 400 million (EUR 5 million, USD 6.7 million) per MW. Capital costs for the American made reactors are substantially higher than the INR 220 million (EUR 2.8 million, USD 3.7 million) per MW negotiated price with Russia for units at the Kudankulam nuclear plant in Tamil Nadu. Besides including waste disposal costs, the higher cost of nuclear power is also explained by India’s nuclear liability clause, which has increased insurance expenses for cautious international firms (refer). The projects are implemented in collaboration with international companies such as Areva from France and Westinghouse Electric from the US.

Average consumer power tariffs in India are currently at around INR 5.5 per unit (EUR 0.07/ USD 0.09). The average pool purchase cost at which utilities buy power is around INR 4 per unit (EUR0.05/ USD 0.06) for new projects. Moreover, due to the risk perception of nuclear power, many projects face opposition from the public, which in turn may lead to significant delays. In theory, a nuclear power plant takes five to seven years for commissioning. In reality, however, this timeline is often much longer, even decades as in the case of the Kudankulam nuclear plant in Tamil Nadu. A look at India’s ambitious five year plan projections for nuclear power since the 1950s as compared to the reality, shows that nuclear power has time and again failed to meet expectations.

Renewable sources of power, by comparison, are much more promising. They are, to begin with, significantly cheaper. Wind power is already competing with coal power across India at prices of INR 4.5 per unit (EUR 0.06/USD 0.08). The cost of solar power is now at around INR 8 per unit (EUR 0.10/ USD 0.13) and this is expected to fall in the long run. A second major advantage is speed: EPC companies across India are now constructing utility-scale solar projects in a matter of months, if not weeks.

In the current context, India needs to keep its energy portfolio diverse and look at all the sources of power available, including nuclear, to meet its power deficit and rapidly rising demand. However, the strategic emphasis should be on renewables. Solar power is even more uniquely positioned as it can be generated in a distributed manner. This means that it competes with the cost of power at the consumption end as compared to the generation end and that the significant commercial and technical grid losses can be avoided.

Solar power will require strategic emphasis beyond a certain limit, as it will require investments in strengthening of the grid in terms of green corridors and smart grid implementation. Solar power being an intermittent power source provides supplementary power when compared to nuclear which provides base load (firm power). Therefore, as the focus on renewables increases, smart grids and ancillary grid infrastructure will be required to balance out the variability of generation and provide a stable and more efficient power.

This post is an excerpt from this week’s INDIA SOLAR WEEKLY MARKET UPDATE. Sign up to our mailing list to receive these updates every week.

You can view our archive of INDIA SOLAR WEEKLY MARKET UPDATES here.

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Last week, Solar Energy Corporation of India (SECI) announced results for third phase of allocations under the rooftop PV projects scheme in select cities. A capacity of 8.75 MW has been allocated across 21 projects in nine cities: Chennai, Coimbatore, Delhi, Kolkata, Mumbai, Pune, Palatana, Chandigarh and Gwalior. Capacities allocated to individual project developers range between 250 kWp to 1.75 MWp with highest capacities allocated to TATA Power Solar (1.75 MW), Ravano Solar India (1.5 MW) and Waaree (1.25 MW).

Rooftop PV projects scheme is different from the off-grid capital subsidy scheme since projects have to be connected to the grid

In rooftop PV projects scheme, disbursement of subsidy is linked with plant performance

If restriction on the city of installation is removed, this mechanism would be suited to take over the capital subsidy scheme

Under this scheme, SECI provides a capital subsidy of 30% to the bidders who are required to provide a turnkey solution including operation and maintenance (O&M) for a period of two years and sell the power at INR 6/kWh for private consumers. The scope of work for the bidder includes the identification and leasing of the buildings suitable for the rooftop plants. This model is different from the off-grid capital subsidy scheme of the Ministry of New and Renewable Energy (MNRE) in two important ways – 1) The projects have to be connected to the grid and sell power to a third-party; and 2) disbursement of the subsidy is linked to performance of the plants: 20% will be disbursed at the time of commissioning subject to minimum performance ratio of 75%; further 5% will be disbursed after 1 year, and another 5% after 2 years, if Capacity Utilization Factor (CUF) of the project exceeds 15% for the two years.

Phase two of the National Solar Mission (NSM) (2013-2017) has a target of installing 200 MW of rooftop based capacity. Earlier, this was envisaged to come through the capital subsidy mechanism. However, we know that the process for capital subsidies has been held up for some time now and we believe that MNRE is likely to altogether move away from this model. Currently, this bidding based rooftop scheme allows developers to also sell excess power to the distribution company at Annual Pooled Purchase Cost (APPC).

However, as net-metering becomes a reality across different locations, these projects are expected to be the first ones to transition into net-metering.

Given the higher transparency and competitive process followed and use of performance based criteria, we believe that this scheme is significantly better than the existing capital subsidy scheme. If the restriction on the city of installation can be removed, this mechanism would be ideally suited to take over the existing capital subsidy mechanism for good.

This post is an excerpt from this week’s INDIA SOLAR WEEKLY MARKET UPDATE. Sign up to our mailing list to receive these updates every week.

You can view our archive of INDIA SOLAR WEEKLY MARKET UPDATES here.

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Across the globe, renewables are entering into their second phase: no longer driven by subsidies or even climate concerns, they directly compete with existing fossil fuel based power. So far, few utilities have been able to manage even the first phase successfully. And they seem to be struggling to strategize the second. Why is that the case? Should they oppose or embrace renewables? This is Part 2 of a three part series on utilities and renewables, looking at how utilities should respond to this new scenario. To read part one, click here. The third looks at how utilities can successfully re-invent themselves. Click here to read part 3.

Utilities in many countries are trying to block policies that promote renewable energies, distributed generation and competition

They should, however, embrace the inevitable and make an opportunity out of a threat

While this is not a guarantee for their future success, it is probably their best bet

Electricity utilities can still portray themselves as ‘systemically relevant’ and ‘too big to fail’ in the way large banks do. They are tasked with ensuring that electricity is always available and that there are no blackouts by maintaining and expanding the grid and balancing the flow of power in it. It would, however, be unwise for utilities to overplay this position as they may rapidly lose it, if they do not quickly set themselves up for success in the new energy world, where renewables will make up half of the additional power generation capacity to be built globally until 2035 (IEA estimate).

Utilities today see renewables no longer as an insignificant fad. Instead, depending on the level of renewable penetration in a country, they see it as either a nuisance or a threat. And the position is all too often one of opposition. They fight ‘unjust’ subsidies or other privileges for renewables, forgetting that fossil fuels and nuclear power have since long been supported by governments. In fact, the IEA estimates that global fossil fuel subsidies in 2012 amounted to USD 544 bn as compared to USD 100 bn for renewables. They decry the high cost of renewables, forgetting that the pricing of traditional power falsely fails to include very expensive externalities such as effects on local pollution levels, habitats and livelihoods, climate or the cost of securing fuel imports. They warn of the destabilizing effects of infirm power on the grid, while good grids (e.g. in Germany) work well with high penetration levels of renewables and unreliable grids (e.g. in India) are unstable even without renewables and distributed generation might actually help stabilize them.

In Europe, utilities are still opting for investments into coal generation plants, driven by falling coal and carbon prices. While this might give short term respite from commercial bottlenecks, it is a strategically flawed choice. Coal-fired plants are simply too inflexible. This shows the increasing divide between the choices of traditional power generators, whose path-dependency both of past investments and current mindsets ties them to centralized generation and the likely electricity architecture of the future (distributed, smart). In Germany and California/US, rooftop solar is an increasingly attractive option for households based on the costs of solar and grid power alone. In both places, utilities are very uneasy about this development and try to stall it through imposing adverse regulations and requirements. In India, too, in the state of Maharashtra, where power tariffs are highest, the state utility is fighting private generators through various petitions and tariff orders.

There is an alternative choice for utilities: Rather than wasting efforts to stymie renewables, they should actively create the energy future. This would put them in a much better position to voice legitimate concerns. Firstly, utilities need long-term visibility on a national energy strategy. That will allow them to make corresponding investment choices into grids and power generation capacities. Currently, almost no country has a clear, long-term strategy on how to manage the big transition from old to new energy systems. Secondly, they need to know how balancing and spinning reserves will be priced during this transition and who pays for these services (and they should be paid for). Thirdly, they should have more clarity on the pricing of carbon.

At the same time, utilities should seek to play a much stronger role in renewables themselves. There have been some investments into large off-shore wind and solar parks, and of course large utilities develop hydro power plants. However, portfolios are still highly lopsided. Even if they are not used to it, utilities are in a good position to go into distributed, renewable power generation. They have vast experience in managing grids. More importantly still, they often have direct access to the power customers. In the new energy system, this will be the crucial advantage as the consumer will increasingly be able to choose where to get power from.

Refer to part 1 of the blog series here.

Refer to part 3 of the blog series here.

Tobias Engelmeier is the Managing Director at BRIDGE TO INDIA.

What are your thoughts? Leave a comment below

Tata Cleantech Capital recently announced that it may provide funds for as much as INR 2.5 billion (EUR 30m) of renewable and energy-efficiency projects in India (refer). The key new opportunity highlighted has been the parity driven market for a combination of power tariffs and diesel cost.

The LCOE for diesel based generation is much higher than that of solar power

The diesel consumption however, does not fall in proportion to the operating load

Several companies are working on solutions that can intelligently manage different sources of power as per load requirements

India has a very large installation base of diesel gen-sets. Some industry estimates peg the market size to be around 60 GW. The typical levelized cost of energy (LCOE) for diesel based generation can be anywhere between INR 12/kWh to INR 18/kWh (EUR 0.14/kWh to EUR 0.22/kWh) (or significantly more for remote sites) and the grid commercial and industrial tariffs can be as high as INR 9/kWh (EUR 0.11/kWh) in many locations. Compared to this, the LCOE of solar power is around INR 8/kWh (EUR 0.14/kWh) for solar PV systems without storage.

Intuitively, it makes a lot of sense for companies with high diesel consumption to go solar. However, there is a technological catch in this proposition: Diesel consumption does not fall in proportion to the operating load. This means that the LCOE of diesel generation at say 40% operating load will actually be higher than the LCOE at 80% operating load. Also, as solar power is an intermittent source, in most cases it is not suggestible to shut down a part of the diesel generation in lieu of solar power as a minimum ‘spinning reserve’ (refer) for diesel based generation is usually required.

Several companies are already working on developing solutions that can intelligently manage the different sources of power as per the load requirements of a consumer. SMA has launched its ‘Fuel Saver’ product for the Indian market (refer). This solution is said to be economically viable for project sizes greater than 500 kWp. Some other companies who have a similar offering in the international market are also looking to launch products for India. In addition, new entrants are developing similar products.

BRIDGE TO INDIA is currently verifying the actual savings potential of such products. New, cost effective solutions that will provide significant and reliable savings on diesel costs to consumers can unlock a large diesel abatement market for solar PV in India.

This post is an excerpt from this week’s INDIA SOLAR WEEKLY MARKET UPDATE. Sign up to our mailing list to receive these updates every week.

You can view our archive of INDIA SOLAR WEEKLY MARKET UPDATES here.

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As a part of the central government’s debt restructuring process, four states – Haryana, Uttar Pradesh, Rajasthan and Tamil Nadu – have begun the process of taking over their short term liabilities from the respective power distribution companies (refer). According to the approved scheme, 50% of the liabilities would be taken over by the state governments. This would be converted into bonds issued by the Discoms (power distribution companies) and backed by a state guarantee.

As a part of debt restructuring process, the central government will provide Transitional Finance Mechanism for liquidity support

Solar power is becoming increasingly competitive across many states for commercial and industrial consumers

Market participants now view the subsidy mechanism as a roadblock more than an incentive

The central government will provide the Transitional Finance Mechanism (TFM) for liquidity support and a capital reimbursement support of 25% of the principal amount if all terms are met. As per the requirements, these Discoms will need to become financially sound in a time bound manner, primarily by raising tariffs. For example, Tamil Nadu has already raised power tariffs by 37% last year (refer) and Uttar Pradesh by 40% (refer) this year.

Apart from these four states, Andhra Pradesh, Jharkhand and Bihar have also been given an extension to join the scheme (refer), taking the total tally of states to seven. Rising tariffs in these states will bring them at par with other states that have already raised tariffs. Bihar, for example, has now proposed to increase the electricity tariff by 55% for all categories of consumers in the next financial year (refer).

Given the unsustainable losses and debt of most state power distribution companies, the central Ministry of Power hopes that the State Electricity Distribution Management Responsibility Bill, 2013, will be tabled in the winter session (beginning 5th December 2013). This bill is expected to force state electricity distribution companies to revise tariffs more frequently (refer). Furthermore, after the ongoing state elections in four Indian states and national elections in May 2014, power tariffs are expected to rise across the board.

In a high power tariff regime in India, solar power is becoming increasingly competitive across many states of India. This is especially true for the commercial and industrial consumers who end up subsidizing tariffs for rural and small urban consumers. Commercial consumers in four Indian states – Maharashtra, Andhra Pradesh, Kerala and Delhi – have already achieved parity with solar power. Many more Indian states are expected to join this list in the next one year. In our latest product, the India Solar Navigator (click hereto download), BRIDGE TO INDIA has carried out an analysis that predicts which states are expected to be favorable for adoption of solar power over the next five year.

As a part of the overall analysis, we have looked at the future trend for power prices based on factors such as losses of distribution companies and their debt-restructuring plans.

Regulations to increase the adoption of solar power are also on the anvil. Pondicherry has successfully piloted net-metering in India. Tamil Nadu and Andhra Pradesh have notified their net-metering policies. Punjab, Delhi, Kerala and Chandigarh are expected to adopt net-metering soon.

According to BRIDGE TO INDIA research, around 120 MW of rooftop solar has already been installed in India. The rooftop market saw a slowdown in the last eight months because of the unavailability of MNRE’s subsidy funds. Now, many market participants view the subsidy mechanism as a roadblock more than an incentive. The subsidy overhang is coming to an end and EPC companies are known to be finalizing orders for installations without subsidies. Many companies and solar specific task forces in trade associations have also been voicing their opinion to completely do away with the subsidy mechanism as it is doing more harm than good in its current form. Parity based adoption of rooftop solar in India will be spread out across states and consumer types. With rising tariffs of conventional power and favorable regulations, the adoption for solar will pick up pace.

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Across the globe, renewables are entering into their second phase: no longer driven by subsidies or even climate concerns, they directly compete with existing fossil fuel based power. So far, few utilities have been able to manage even the first phase successfully. And they seem to be struggling to strategize the second. Why is that the case? Should they oppose or embrace renewables? This is Part 1 of a three part series on utilities and renewables, looking at their dilemma. The second part will look at the choice of obstructing vs. embracing change (Read here). The third looks at how utilities can successfully re-invent themselves (Read here).

Traditional utilities are still the backbone of energy systems

Many face rapidly falling market capitalization and profitability in electricity generation

They have no real strategy of their own for redesigning the future of energy and thus are constantly driven by other stakeholders

Over the course of the 20th century, the generation and distribution of power had become an increasingly centralized affair. Grids grew in size and linked up with one another. Ever larger power plants, fired by coal or nuclear reactions, fed power through them. Often, generators and distributors were the same. Often, these were public sector monopolies. The future seemed predictable and investments safe. Then, new regulations lead to tectonic shifts in the world of utilities. First, competition was encouraged through unbundling and privatization. Then, new distributed, smaller power plants, based mostly on renewable energy technologies began to emerge. These were initially belittled, as their contribution to the power supply was still tiny and their infirm nature gave them an air of fundamental impracticality. However, as the costs of fossil fuels rose and climate concerns grew in the 90s and early 2000s, their development was rapid and suddenly they changed the game. Utilities – out of arrogance or ignorance or inertia – were left wrong footed. They had bet on the traditional model of power generation and sale and seemed quite incapable of adapting to the new business models that emerged. While new, often profitable energy companies popped up across the globe, many traditional utilities began to lose money.

In Germany, a pioneer in the field of renewables, this development was particularly pronounced. Generators of solar, wind or biomass power were given preferred access to the grid. They did not have to worry about balancing fluctuating power, but could supply power whenever available. At times, this could lead to oversupply of power. On June 16th 2013, Germany had to sell power at a price of minus (!) 100 Euro per MWh to get rid of excess generation and keep the grid stable. Wind and solar made up over 60% of the power at that point in time. Coal and gas fired power plants reduced their generation to just 10%. While the renewable power generators were still paid through the FiT, the coal and gas fired plants made heavy losses.

Utilities are still the backbone of the electricity system, providing base-load power, spinning reserves and managing the grid. However, a deep structural shift is taking place in this highly conservative industry. Utilities are not driving the debate; they are driven by it. That might be their main failing: a lack of imagination, innovation and strategy. As a result, industry developments are not going in their direction.

While renewable energy generators have the privilege of stable framework conditions, fossil fuel plants are increasingly denied long-term visibility. In Germany this had lead to the phenomenon of high and rising consumer power prices (driven among other things by a renewable energy surcharge) while at the same time, power prices at the power exchange have dropped to a long time low, making it unviable for utilities to sell power. By now, and this is the second phase of their development, renewable power is increasingly competitive and will be bought by consumers even without government support, exponentially creating a more complex web of generation and distribution to which the traditional infrastructure seems increasingly ill-fitted. As their core business is threatened and unrelated strategic mistakes have piled up, utilities have so far failed to sufficiently tap into the new opportunities. Markets are skeptical about their prospects to do so in the future. Germany’s largest utilities E.On and RWE have lost over 60% of their market value in the past five years. Their very survival is called into question.

Refer to part 2 of the blog series here.

Refer to part 3 of the blog series here.

Tobias Engelmeier is the Managing Director at BRIDGE TO INDIA.

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In the last two quarters of every financial year (October – March) for the last couple of years, the solar policy space in India has become alive. This year is no exception and in the last couple of weeks we have seen announcements on phase two of the National Solar Mission (NSM), Kerala’s recently finalized solar policy and new project allocations in Haryana.

The pre-bid meeting focused on the relevance of the location of a project, the working of the CUF limits and the impact of anti-dumping duties on the allocations

Under Kerala’s draft solar policy, the state has a target of an installed capacity of 500 MW by 2017 and 1,500 MW by 2030

Haryana to soon begin allocating 10 projects of 5 MW each using standard tariff based reverse bidding process

This happens every year because state and central governments need to publish policies now to meet next year’s capacity addition targets. However, in the past, the implementation of at least the state policies dragged on and most of the actual capacity addition has spilt over to the subsequent year. Last year, around this time, solar policies in Tamil Nadu, Andhra Pradesh, Uttar Pradesh and Punjab were doing the rounds. As per the original plan, a majority of the capacity under these policies should have been commissioned by March 2014. However, timely meeting of these targets seems nowhere in sight.

Even though the announcement of phase two of the NSM has been delayed, this being a central government policy, the allocation process will likely be implemented on schedule. The pre-bid meeting was held on 19th November 2013. Based on BRIDGE TO INDIA’s perception, the government officials were helpful and most developers satisfied with the process. The Solar Energy Corporation of India (SECI) is expected to release a clarification document soon to address specific questions. The key aspects discussed in the meeting were related to the relevance of the location of a project, the working of the Capacity Utilization Factor (CUF) limits set under the bid document and the possible impact of anti-dumping duties on the allocations. Read our blog for further analysis on these topics and our overall take on the pre-bid meeting.

Kerala’s draft solar policy has also received cabinet approval and has now been finalized (the draft policy document can be downloaded from here, the final document should be uploaded soon). Under the draft policy, Kerala has set itself a target of an installed capacity of 500 MW by 2017 and 1,500 MW by 2030. Like Tamil Nadu, Kerala has also tried to pass on the financial burden of Renewable Purchase Obligations (RPOs) from the state-owned distribution company (DISCOM) to large power consumers. Solar Procurement Obligations (SPOs) will be mandated for commercial consumers with a connected load of more than 20 kVA and industrial consumers with more than 50 kVA on the low tension (LT) transmission network (up to 415 V). Also, SPOs will be applicable to all consumers connected to the high tension (HT) transmission network (up to 11 kV) and Extra High Tension (EHT) transmission network (up to 66 kV). Further analysis of the Kerala solar policy can be accessed here. Earlier, the state had already initiated a 10,000 rooftop solar power programme (refer). The implementation of this programme seems to be on track as most of the installations have already taken place. Reportedly, there has been some delay in the release of subsidies to the empaneled installers.

The state government of Haryana is also expected to begin the process of allocating 10 projects of 5 MW each based on the state’s draft solar policy (the draft policy document can be accessed here). These projects are to be allocated using the standard tariff based reverse bidding process. The power from these projects would be bought by the state distribution companies. Apart from these utility scale projects, the policy also talks about canal solar projects and promotion of rooftop solar installations for commercial buildings. However, no update is available on the implementation of these aspects of the policy.

As things stand, execution of projects under the NSM, Andhra Pradesh, Tamil Nadu, Punjab, Uttar Pradesh and now perhaps even Haryana and Kerala can be expected around the second half of 2014. Theoretically, this may add up to over 1,800 MW that would need to be executed in a limited span of time. However, if the past experience is any indicator, many of these policies and projects are expected to hit further roadblocks.

This post is an excerpt from this week’s INDIA SOLAR WEEKLY MARKET UPDATE. Sign up to our mailing list to receive these updates every week.

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Tamil Nadu is expected to issue guidelines for subsidy to be provided to residential rooftop systems in the state (refer). This is expected to be similar to the rooftop solar scheme earlier announced in Kerala (refer). Domestic consumers will shortly be able to send their applications online to the Tamil Nadu Energy Development Agency (TEDA), the installers empaneled by the state, like in Kerala, will carry out the installation of systems. However, these systems are expected to be grid-tied and without any storage, unlike in Kerala.

A domestic consumer will have to pay INR 50,000 after getting government subsidies for rooftop solar systems
The key issue with the rooftop solar policy in various states is that they rely on MNRE subsidy scheme
Feed-in-tariff (FiT) based system is better from a customer’s perspective

A subsidy of INR 20,000/kWp will be provided by the state government. This is expected to be in addition to the 30% capital subsidy available from the MNRE. Assuming that the system cost is INR 100,000/kWp, a domestic consumer, will effectively have to pay INR 50,000 after the subsidies. At this price, the payback period for the system is expected to be around five years. For the budget that has been sanctioned for this initiative, around 5,000kWp is expected to be installed in total.
Uttarakhand had earlier announced a policy for rooftop installations but that is based on a generation based incentive and not on upfront subsidy (refer). Gujarat and Andhra Pradesh are also known to be working on a policy similar to that in Kerala and Tamil Nadu.
The key issue with these policies is that they all rely on the MNRE subsidy scheme. In the last one year we have seen that the MNRE scheme has not been working as planned (refer). Therefore, the future of all these policies is linked to the success of the MNRE subsidy scheme, which itself is in doubt. Moreover, it is generally believed and BRIDGE TO INDIA has shown it in an analysis (refer to the report), that a feed-in-tariff (FiT) based system is better from a consumer’s perspective.
There might be a lot of room for an improvement of these policy initiatives but India needs more distributed systems and these policies are already laudable steps in the right direction.
This post is an excerpt from this week’s INDIA SOLAR WEEKLY MARKET UPDATE. Sign up to our mailing list to receive these updates every week.
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India’s electricity system is a mess. While that is bad for consumers, it is great news for innovators and entrepreneurs who see an opportunity to earn money, to provide a social solution or to do both. Prayas Energy Group, a Pune think tank, now wants to provide more data for such ventures. Its concept is a finalist in the Google Impact Challenge 2013.

India has many different needs, markets and there are many different solutions
There are signs that the market has moved from ideating to tested, scalable solutions
Monitoring and data availability are a challenge

The markets for distributed power solutions are many: wealthy farmers who need power for pumping water, tens of millions of households without access to the grid, telecom tower operators who spend more time and money on energy procurement than on their core business, industries who face rising grid power costs or irregular power supply, and many more.
A host of companies are busy solving these troubles. Mera Gao Power, Husk Power Systems, d.light and Onergy are developing solutions for the rural market – often in the North. Greenpeace and GiZ have established trial village mini-grids. Signs are that some models are now approaching investment grade. In September, when the UN Foundation held a workshop on energy access in Bihar’s dustry capital Patna, it attracted interest from several international investors. Selco, which has set up over 100,000 solar home lighting systems in Karnataka and other states, runs an incubation center to mentor solar entrepreneurs with a social vision.
Telecom towers are another market, where the first wave of pilots (usually a couple of hundreds or thousands of towers) has been completed and solution providers are looking to roll out their concepts. They include companies such as OMC and Applied Solar. Intelligent Energy, a UK-based sustainable technology company whose offering includes fuel cell solutions, has just closed a round of fundraising with a specific view to the rolling out its India business.
Entrepreneurs are also targeting the residential customer market. A new breed of professional solar service providers with international experience and local reach, such as Orb Energy, Peetee Solar in Tamil Nadu or PTL Solar in Kerala, to name just three, has come up all across the country. The Indian start-up Gensol has developed a simple, integrated solar solution for households (1 kW) which is selling well in Kerala. Greenpeace is just running an innovation challenge for new solutions for sustainable irrigation pumps.
One factor that holds back growth in this market is the lack of data on the supply quality. To improve this, the think tank Prayas is developing a reliable database on supply interruptions and voltage levels at consumer locations in India with up to 2,500 Electricity Supply Monitors (ESM) in households, farms, and small commercial establishments.
This is to be combined with an intuitive web-interface that uses GIS to map the data to its locations and enable users to view and download the data of any region over specific time-periods (day, month or year). Consumers, civil society organizations, researchers, regulatory commissions and stakeholders can use this data to increase the accountability of electric utilities. The data can be used, for example, to verify whether the villages electrified through India’s rural electrification program get the mandated 6 hours of daily supply. The initiative is now one of the finalists of the Google Impact Challenge. More information on this can be found here.
Tobias Engelmeier is the Managing Director at BRIDGE TO INDIA.
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According to a Crisil research note (refer), pure-play power project developers in India are finding it difficult to compete for solar projects against investors that have entered the segment primarily to avail the tax incentives. An investor with existing profits in India from other businesses can claim accelerated depreciation (AD) of 80 per cent of the capital costs in the first year, making the project more viable for them.

AD makes sense for companies that have high, taxable profits or are willing to the solar plant as an asset on the balance sheet of the entity making these profits
The difference between the AD and non-AD tariff offered in the bids was more than INR 1/kWh. Many IPPs hope to get new allocations under the NSM
The opportunity arising out of the AD-driven market will be in mergers and acquisitions (M&As)

Barring the National Solar Mission (NSM) and Gujarat allocations, where separate tariffs have been offered for projects not availing AD, a majority of the bids received for solar projects in India are from companies that can avail AD. AD makes sense for companies that (a) have a high, taxable profits in the current financial year and (b) are willing to hold the solar plant as an asset on the balance sheet of the entity making these profits.
Due to these tax benefits, such investors are able to offer much more competitive bids. For instance, in a tender issued by the Tamil Nadu government in January, IPPs such as Welspun and Lanco Infratech quoted a tariff of INR 8.60/kWh (USD 0.14/kWh, EUR 0.10/kWh) and INR 8.20/kWh (USD 0.13/kWh, EUR 0.09/kWh) respectively. However, the lowest bid has been submitted by a non-IPP, Mohan Breweries, offered to supply power at INR 5.97/kWh (USD 0.10/kWh, EUR 0.07/kWh). Similarly, for allocations in Rajasthan, Azure Power (an IPP) quoted a tariff of INR 8.20/kWh (USD 0.13/kWh, EUR 0.09/kWh) while Essel Mining (a non-IPP) bid for a tariff of INR 6.45/kWh (USD 0.11/kWh, EUR 0.08/kWh). In the NSM and Gujarat policies, the difference between the AD and non-AD tariff offered was greater than INR 1/kWh. Many IPPs are now hoping for the new allocations under the NSM.
To gauge the importance of the AD benefit to the Indian solar market, one can look at wind power: When AD for wind projects was discontinued, capacity additions almost halved.
The opportunity arising out of the AD-driven market will be in mergers and acquisitions (M&As). As most of the newer renewable focused IPPs are aiming for public listing of their companies, they have targets for asset holdings within the company at the time of the public listing. Acquisitions will be the easiest way for these companies to accumulate these project assets.
Non-IPP players, after availing the AD benefit will often want to sell a project asset as soon as the lock-in period, as determined by the PPA, is over. Selling the asset will also make sense for non-IPP players as they often have access to more lucrative investment opportunities. IPPs will be able to improve the viability of any acquired project assets by refinancing them using new financing sources and more innovative structuring.
If such an ecosystem for transferring of assets from non-IPPs to IPPs can be created, it will incentivize the non-IPPs to keep the eventual buyer in mind and ensure quality oriented implementation of projects. Overall, it might not be a bad proposition for sector for now.
This post is an excerpt from this week’s INDIA SOLAR WEEKLY MARKET UPDATE. Sign up to our mailing list to receive these updates every week.
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Stock market valuations of major solar global companies have risen significantly in the last two months, beating the respective indices by a significant margin. The share prices of Jinko are up by 61%, Yingli Green Energy by 107%, Sun Power by 40%, Trina Solar by 124%, Renesola by 35% and First Solar by 11%. The share prices for Indian cell manufacturer, IndoSolar, have increased by 73% over the same period. The nadir of valuations that from 2012 are far behind.

Share prices have been influenced by the fact that module prices have stabilized in the past six to eight months after a two year fall

The rise in share prices of of Indian manufacturers has been greatly influenced by domestic factors such as the introduction of DCR

Module prices in India, which had been one of the lowest globally, might actually see an uptrend

The rally in the share prices has been particularly sharp over the last few days. This has largely been driven by the announcement that the US-based Solar Energy Industries Association (SEIA) will issue a proposal to remove anti-dumping duties imposed on Chinese suppliers and that China will remove the retaliatory duties on poly-silicon imports from the US.

Overall, the share prices in the last six to eight months have been influenced by the fact that module prices have stabilized after a rapid two year fall. Also, a large part of the needed consolidation in the industry has already taken place and the increased demand from Japan has been able to absorb a significant part of the excess capacity. Apart from this, new policy targets in China and India have also helped.

The rise in the share prices of the Indian manufacturer, IndoSolar, has been greatly influenced by domestic factors such as the introduction of domestic content requirements (DCR) for an allocation of 375 MW under the National Solar Mission. The stocks might rise further, if anti-dumping duties are announced (unless investors have already priced their expectations in).

The uptrend in these share prices is a very positive development. It means that the industry is expected to return to sustainable, profitable growth. However, it might also mean that prices for modules will not continue to fall as they have during the last years.

Module prices in India, which had been one of the lowest globally, might actually see an uptrend. This has been confirmed to BRIDGE TO INDIA by several EPC companies that have recently closed deals or are in the process of negotiations. The actual landed cost will increase further due to the devaluation of the Indian currency.

Overall, sustainable margins across the value chain are welcome from an industry perspective. BRIDGE TO INDIA believes that price reduction should be driven by technology innovation, scale and fair competition. A stable module pricing regime will also take away the ‘incentive to wait’ for lower prices for developers and end consumers and might encourage sales.

This post is an excerpt from this week’s INDIA SOLAR WEEKLY MARKET UPDATE. Sign up to our mailing list to receive these updates every week.

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Today, solar adds less than 1% to the Indian power mix. Coal, by contrast, contributes over 60%. Coal is the lead power source and setting the overall power price. However, as coal is getting more expensive with respect to solar, and since the potential for solar is almost without limits, solar can become the lead power source in the next ten years.

The cost difference between a kWh of coal and solar has reduced from a factor of 7x in 2011 to only 1.8x in the summer of 2013.

Solar is the only currently commercially available energy source that has the theoretical potential to replace coal and satisfy India’s long term power requirements

But can an infirm power source like solar replace a firm one like coal as the backbone of the Indian energy mix?

India’s economy is heavily dependent on coal power. Most of the coal is mined in India, but the share of imports is increasing fast. In a recent report, the Pune think tank WISE estimates that coal production in India will peak in the early 2030s. While this may seem a far off point in time, it impacts investment decisions already today as coal plants have expected operational lives of 40 years and more. An increasing dependence on imported coal will further push the current account deficit to at least 13% by 2030, according to the report.

The cost of power from imported coal is pushing towards INR 4/kWh. This does not include the cost of externalities. (WISE estimates that including those and subtracting hidden subsidies would bring the cost of coal to almost INR 13/kWh for domestic and over INR 15/kWh for imported coal.) Solar from large, grid connected power plants is now offered at INR 7/kWh (wind is even cheaper at INR 3.5 to 5/kWh). In 2011, coal-fired Ultra Mega Power Plants (UMPP) signed PPAs with tariffs around INR 2.8/kWh and CERC estimated the cost of solar to be as high as INR 18/kWh. The differential has thus reduced hugely over the last three years, from INR 15.5/kWh to INR 3/kWh (for imported coal). This is a game-changing fact.

In addition to this shift on the cost side, there are persistent concerns about energy availability and security in India. The power deficit hovers around 10% (base load). Importing ever more fossil fuels to close this gap (under conditions of rapidly rising power demand) will increasingly put India at the mercy of volatile global markets and individual exporting nations. The grid is another concern: Although India is making progress in connecting villages to the distribution grid, the country is still hundreds of millions of people away from supplying reliable grid power to every household.

Solar power is the only currently commercially available source of power that could both provide enough power from within the country to meet India’s rising demand and in addition offer distributed solutions that are less dependent on grid extension. In addition, solar plants can be built relatively fast and at any size, while coal plants are often mired in all the challenges of large infrastructure projects in India, including bureaucracy, social and environmental concerns, as well as compliance, land acquisition and water usage issues. I do not think that land is a limiting factor for the spread of solar, as less than 1% of India’s land would suffice to power the country with solar plants.

As a result, solar could replace coal as the backbone of the Indian power supply. If, how and when this will happen, will depend on four main considerations:

The long-term cost trajectory of solar power vs. coal. The cost of solar might fall to around INR 5/kWh in the next couple of years. In the longer term the cost will likely fall further, but this will depend on future innovations in materials used, new production technology and efficiency improvements. At the same time, the cost of coal might rise further or stabilize (shale gas in China and the US could play a key role). However, whereas the long-term cost for solar is driven continuously downwards by the industry itself, the cost for fossil fuels as limited, non-replenishing resources depends on much more fickle global, regional and local supply and demand dynamics.

The cost of balancing and storage. Solar is a relatively infirm power source (although far more predictable than wind), which is not always available. As a result, a high share of solar in the energy mix will incur additional costs in balancing demand and supply. This is a complex topic and we are currently working with Prayas and IIT Mumbai on understanding it. Some key issues are: the quality of the grid, the availability of storage (e.g. pump hydro or the use of distributed storage opportunities such as irrigation pumps, inverters or- in the future, perhaps – electric vehicles), the availability of balancing power generation (especially gas-based), the development of smart grids and demand management systems, and perhaps the liberalization of power prices and the creation of a new grid code. On the other side, there could be large savings as the mining, port and railway infrastructure required for a massive scale-up of coal-fired power generation would not need to be built.

If and how externatilites are measured. While solar has some negative externalities in terms of e.g. emissions in the manufacturing process, these are significantly lower than for coal. Coal externalities are global (greenhouse gas emissions) and local (soil degradation, water usage, pollution, etc.). The way coal is currently mined, transported and burned in India is highly harmful to the environment and the people. Indian politics might currently not place a high priority on these externalities vis-à-vis the more pressing concerns of generating enough power. However, a look at China’s development path suggests that this may soon change.

If and how energy security is measured. Importing more and more fossil fuels will be a costly decision. The US, which for the last decades was highly dependent on imported oil, has spent large amounts on building and securing the supply routes. This included military and foreign policy decisions that often stood at odds with the country’s other interests and in turn created unpredictable follow-up costs (including wars). India’s geostrategic environment, the emergence of China and the fact that many reserves are already claimed or developed, will make it difficult to follow that path, even if the country wanted to. So India would likely depend on fossil fuels with only a very low degree of control over supply amounts, security and prices. This would incur its own set of ‘balancing’ costs in terms of high current account deficits, risks of political crises and stunted economic development.

What will this mean for long-term power prices in India? Currently power prices are driven upward by rising costs of fossil fuels, by inefficiencies in the transmission and distribution system and by past political decisions on power pricing. As a result, solar has come close to parity. It is likely that prices will continue to rise for a period of ten years or so, in a mid-term price ‘hump’. During this time, the power infrastructure would need to change from a centralized one to a more flexible central/decentral one. Post that, when solar becomes the lead power source, average power prices would likely fall. This process of transition should be politically actively managed to ensure that energy security is always guaranteed, that there are no infrastructure bottlenecks and that power prices do not become excessively volatile at any point in time.

Tobias Engelmeier is the Managing Director at BRIDGE TO INDIA.

What are your thoughts? Leave a comment below

There has been much talk about the great transition in the Indian solar (power) market moving from a centralized, policy-driven market, to a distributed, private PPA market. In fact, we have ourselves added to the chorus (see our various blogs and reports). While we see some first projects in that space, however, the breakthrough is yet to happen.

Is the pain not strong enough? Or the gain not attractive enough?

There is a larger question about India as an infrastructure market and the country’s readiness for long-term solutions

Diesel replacement with storage might be a better way to play to short-term needs

The first question, one encounters when interacting with a power consumer to whom one offers solar, is, of course: what can I save? Even in very favorable locations (high irradiation, high grid tariffs), the answer will rarely be more than INR 1/kWh on a levelised basis, assuming the solar solution provider has market return expectations and a sound financial model, and there are no subsidies involved. It is interesting to the consumer, but not a revelation. And then there are hassles: Long term contracts to be signed, construction to be done. The savings are often insufficient to trigger immediate action. While this is changing- power prices are rising fast, while solar costs are stabilizing- it is anyone’s guess, when the savings are substantial enough to move solar to the top of more power customers’ agendas.

However, even if savings improve, the return on investment time for going solar will drop from, say, eight years, to four years. In the highly dynamic Indian market environment that is still a long time. In four years, companies and entire industries grow, falter or change entirely. The macroeconomic (e.g. rupee conversion rates, cost of fossil fuels) and political frameworks are subject to frequent, incisive ruptures. As a result, flexibility is valued and cash often prioritized over longer term benefits. There is an inbuilt myopia that is further aggravated by insecurities such as concerns about the enforcability of contracts or limited availability of information.

To put it into context: the reason why diesel gen sets are a hugely successful product in India, despite high costs and pollution, is that they offer great flexibility and costs are pushed into an uncertain future. The user only pays if and when there is a power cut. It is a typical ‘Jugaad’, or patchwork, solution- not a structural one.

In future, there will be a market for long-term infrastructure investments like solar in India. The fundamentals of rising power tariffs and diesel prices, the energy deficit and stable solar costs will make going solar attractive enough to get consumers excited. At the same time, it is probably a good idea to look at the already existing and profitable power markets around diesel and develop solar solutions targeted at them. Here, storage will play a key role.

Read more about the Private PPA market here.

Tobias Engelmeier is the Managing Director at BRIDGE TO INDIA.

What are your thoughts? Leave a comment below

The Ministry of New and Renewable Energy (MNRE) has released its revised draft guidelines for a capacity of 750 MW of solar PV under batch one of phase two of the National Solar Mission (NSM) (refer to this document for the latest draft).

SECI wants to sell solar power to state distribution companies

States that are already meeting their RPO targets may not be interested in purchasing power from SECI, whereas for other states that don’t have a dedicated state policy, this will be one of the cheapest options

Out of a total capacity of 750 MW, a capacity of 375 MW will have a DCR

The Solar Energy Corporation of India (SECI) will carry out the allocation process, provide viability gap funding (VGF) and sign the power purchase agreements (PPA). SECI wants to sell the solar power to state distribution companies. It has now decided to first obtain confirmation from them on their willingness to do so, prior to issuing a Request for Selection (RfS) for the developers. This process is currently under way. The RfS document is expected to be available from 15th October to 21st November 2013.

This process addresses a key concern for developers and helps them better choose locations for their projects. The concern was also raised in an earlier blog of ours, commenting on the first draft of the guidelines (refer).

Most developers look to high irradiation locations in the west and south of India. However, considering that states like Rajasthan, Tamil Nadu, and Karnataka are already meeting their RPO targets, their state utilities may not be interested in purchasing power from SECI. On the other hand, states like Maharashtra, Bihar, and Haryana that do not have a dedicated state policy in place and fall short of meeting their solar RPO targets might want to buy solar power from phase two of the NSM. It will be one of the cheapest options for them.

The much-awaited ambiguity surrounding the Domestic Content Requirement (DCR) has also been cleared. Out of the total capacity of 750 MW, a capacity of 375 MW will have a DCR. At the time of bidding, the developers can either opt for ‘DCR’ or ‘Open’ or both categories; however, separate bids have to be made for DCR and non-DCR projects. It is expected that the tariffs for projects with DCR will be slightly higher. Indian cell manufacturers such as IndoSolar, Webel and Jupiter are expected to benefit the most. International suppliers such as ReneSola, which have contract manufacturing in India, are also likely to benefit.

The VGF mechanism is largely the same as defined in the previous draft, which was released earlier in the year (refer). The difference concerns the disbursement of the incentive. The VGF will now be released 50% on successful commissioning of full capacity and the remaining 50% over a period of five years from the date of commissioning of the project, provided that the project meets the requirements for generation (i.e the Capacity Utilisation Factor, CUF). This performance-related approach is new. In the earlier draft, 25% of the incentive was to be handed out after the delivery of 50% of the project equipment, another 50% on the successful commissioning of the full capacity and the remaining 25% was to be given after one year of successful commissioning.

This change will address the issues raised by BRIDGE TO INDIA in the October 2012 edition of the India Solar Compass (refer) and a blog that we had written after the announcement of the draft guidelines (refer).

The last date for the submission of interest (along with the relevant guarantees) is 29th November 2013. The minimum project capacity has been fixed at 10 MW and the maximum at 50 MW. A single company can, however, submit an application for a maximum of three projects at different locations, with a maximum aggregate capacity of 100 MW. The developers are expected to attain financial closure within 210 days from the date of signing of the PPA and the project has to be commissioned within 13 months. A waiting list of up to 100 MW will be maintained by SECI up until the deadline for financial closure, at which point SECI may allocate new projects, if any of the previously allocated projects fail to achieve financial closure. Developers will have to provide Bank guarantees (BG) and Earnest Money Deposit (EMD) even for the waiting list.

The document also stipulates penalties for delays in completion of the projects. In case of a delay of more than one month, SECI shall en-cash 20% of the total Performance Bank Guarantee (BG) on a per-day-basis and proportionate to the capacity not commissioned in lots of 10 MW each. In case of a delay of more than one month and up to three months, SECI will en-cash the remaining BG in the same manner. Finally, in case commissioning is delayed by more than three months, the pre-fixed levelized tariff of INR 5.45/kWh shall be reduced at the rate of INR 0.50/kWh per day of delay for the delay in such remaining capacity, which is not commissioned. Effectively, any project that is delayed beyond three months will become unviable.

On the bankability front, the draft also calls for the NVVN to step in, in case there is any delay on SECI’s part with respect to payments. To avoid a default from SECI, the developers might be required to sign short-term PPAs with NVVN, which in turn, will sign short-term Power Sales Agreements (PSAs) with interested state utilities. Even though this increases the complexity, we believe that this provision safeguards the interests of the developers in case a given state distribution company does not honor its commitment towards SECI and SECI in turn is unable to honor its commitment to the developer. The document states that as and when SECI is fit to carry out its functions, the short-term contracts will be terminated and long-term contracts with SECI will become effective. All the PPAs and PSAs (short-term with NVVN and long-term with SECI) will have the enabling provision for such a changeover so that the transition from NVVN to SECI is smooth and neither the solar power developers nor the buying entity is affected in this process.

All in all, the revised guidelines have addressed many concerns that were voiced after the release of the previous draft of these guidelines. The PPAs for these allocations are expected to be signed around 27th February 2014. This means that with a 13-month timeframe, these projects are to be commissioned around March 2015.

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Less than planned for, but at least a start: As per the Andhra Pradesh Transmission Corporation (APTRANSCO), 60 MW of PPAs have been signed in the state until now and around 80 MW more are expected be signed soon. The tariff will be INR 6.49/kWh (EUR 0.08/kWh; USD 0.10/kWh).

Andhra Pradesh is looking to allocate a revised target capacity of 350 MW.

Considering to the large shortfall with respect to the earlier goal, the state has offered PPAs to any further project developer who wishes to set up the same tariff of 6.49/kWh

Andhra Pradesh expected to extend the deadline and allow more developers to evaluate the risks and tariff conditions

The state of AP was initially looking to allocate a capacity of 1,000 MW. However, following a mid-way revision of tariffs, several developers withdrew their interest (refer). Subsequently the target was revised to 350 MW. Now, due to additional issues such as the creation of Telangana and the depreciation of the Indian Rupee, only a total capacity of 140 MW will likely to sign the PPAs under the current allocation process.

In a previous blog, we had already stated that some project developers would opt out of the Andhra Pradesh PPAs (refer). This is partly because of concerns related to the state’s political split and partly due to projects no longer being viable in the wake of increased component costs (driven by the rupee’s devaluation).

Recognizing the large shortfall with respect to the earlier goal, the state has offered PPAs to any further project developer who wishes to set up projects at the same tariff of INR 6.49/kWh. Yesterday was the deadline. Around 5 developers are known to have expressed interest. According to APTRANSCO, these applications amount to an additional capacity of as much as 500 MW. The new project sizes are typically around 100 MW, which could make them viable at the given tariff. Issues, such as land acquisition and grid evacuation capability will reduce the final capacity for which actual PPAs will be signed.

To address concerns of developers, APTRANSCO has incorporated a clause in the PPAs that states that in case the state DISCOM is restructured, its successor will fulfill the obligations of the PPA.

BRIDGE TO INDIA expects that Andhra Pradesh will extend the deadline to allow more developers to evaluate the risks and tariff conditions. We believe that this could further increase developer interest.

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Allocations under batch one of phase two of the National Solar Mission (NSM) were supposed to begin in May 2013. However, there has been a significant delay in the process and these allocations have not yet been announced. Officials from the Ministry of New and Renewable Energy (MNRE) have been quoted as saying that the documents for phase two of the NSM are now with the union cabinet for approval (refer).

NSM expected to be kept on further hold due to the looming elections

The capital subsidy scheme is also on a hold creating a void for state governments looking at rooftop solar policies that are tied to central subsidy scheme

The investors are increasingly losing patience with the flagship policy of the Indian solar market

The NSM has primarily been held up due to India’s fiscal deficit and the resultant focus on reducing government spending. Apart from that, the MNRE also wanted to wait for more clarity on the domestic content requirement (DCR) case that the US has registered against India at the WTO and the ongoing investigations on anti-dumping duties within India.

The union cabinet may keep the NSM further on hold due to the looming elections. Some market participants expect that the NSM may only be announced after the general elections, to be held by May 2014.

The capital subsidy scheme for smaller projects under phase two of the NSM is also stuck in the same process. This creates an awkward void for state governments looking at rooftop solar policies that are tied to the central subsidy scheme (Uttarakhand has already announced its policy (refer), Gujarat’s policy for 40 MW of rooftop systems to be released soon (refer), Andhra Pradesh is working on a similar policy). All these policies depend on the central subsidy scheme and then provide incentives over and above that. With no clarity on the timelines for phase two of the NSM, the effective implementation of these state policies comes into question.

The state solar policies of Tamil Nadu, Andhra Pradesh, Uttar Pradesh, Punjab, Rajasthan and Karnataka have helped keep the market moving for a greater part of this year. However, many Indian and international developers have not participated in these allocation due to the high PPA risk perception and have been waiting for the announcement of the bids under the NSM. These investors are increasingly losing patience with the flagship policy of the Indian solar market. It is of great importance that the government more actively communicates with the market and provides regular information on the status and timelines of the NSM.

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The Ministry of New and Renewable Energy (MNRE) has been planning to build mega size solar projects (>500 MW) in India (refer to the July 2013 edition of the India Solar Compass). These projects would be aimed at bringing down the cost of solar power to around INR 5/kWh (USD 0.08/kWh).

PGCIL, the key stakeholder of the ultra-large solar project, is expected to bring an equity contribution of 16%

The high cost of convntional power has already made solar power viable (on the consumption end) in some parts of India

If mega projects can bring down the cost of solar power to INR 5/kWh, it should be an option worth looking at

There has been no official confirmation as to how the government plans to develop these projects. However, according to recent reports, India’s first ultra-large solar power project, perhaps under the same objective and with a capacity of 1,000 MW is being planned in Rajasthan (refer). Based on this report, the Power Grid Corporation of India Limited (PGCIL) is the key stake holder in the project is expected to bring an equity contribution of 16%. Along with PGCIL, Hindustan Salt is another stakeholder as it will ensure land availability for this proposed project. Hindustan Salt has over 20,000 acres of land available in the salt plains of Rajasthan. Other stakeholders in this project include Solar Energy Corporation of India (SECI) and Satluj Jal Vidyut Nigam. Bharat Heavy Electricals Limited (BHEL) is likely to be the EPC partner as well as bring investments for this project. The work on this project is expected to begin as soon as a Special Purpose Vehicle (SPV) company is created after the government’s cabinet level approval. Apart from these five partners, the consortium would also be roping in other investors in the project as equity partners. Power produced by this project would be transmitted to the grid by Power Grid under its green corridor project. It is expected that the overall objective of these mega projects would be to build a capacity of 3,000 MW in six phases of 500 MW each.

According to BRIDGE TO INDIA, there are two fronts on which solar power will compete with conventional power in India in the future. The first is at the generation end and the second at the consumption end. At the consumption end, the tariffs are high (as high as INR 10/kWh in some cases) for conventional power due to all the losses, charges and margins in between. This has already made solar power viable in some parts of India, especially for commercial consumers who pay the highest tariffs among all consumer categories in India.

Under all existing policies, solar power is currently competing with conventional power at the generation end as most of these projects are ground mounted and located away from consumption centers. We understand that new coal based generation now costs between INR 3.5/kWh to INR 4.5/kWh and solar power still costs around INR 6/kWh for project sizes above 10 MW. If these mega projects can bring the cost of solar power down to INR 5/kWh, it should be an option worth looking at, on the generation side.

However, we think that it makes more sense for the government to facilitate the adoption of solar power at the consumption end, where it already makes financial sense. This can be done by taking steps to enable easier grid connectivity, by providing net-metering for sale of excess power and removing open access and other such charges for co-located projects.

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A recent article (refer) revealed that Indian C-si PV manufacturing is witnessing a five year low. The poor performance of domestic manufacturing in the last few years is well known. In response, the MNRE recently announced the establishment of the ‘National Institute for Solar Energy’ (NISE) to support the development of advanced solar technologies and bring benefits of cost reduction to Indian manufacturing (refer).

Indian manufacturing is not competitive because of the lack of scale

Solar industry in India is moving towards minimal government support

Manufacturers should focus their efforts on increasing the scale of individual manufacturing facilities

Most manufacturing facilities in India are either lying idle or are operating at a very low utilization rate. The key reason is that Indian manufacturing is uncompetitive in terms of costs with international, especially Chinese competitors. In a recent report that compares manufacturing costs in the US and China, it has been established that subsidy is not the driver for the cost competitiveness of Chinese manufacturers. Instead, the report claims that the key reason is the scale effect (and to a lesser extent the cost of labor) (refer). BRIDGE TO INDIA believes that Indian manufacturing is not competitive because it lacks precisely that – scale. The largest manufacturing facility in India is around 200 MW, while several Chinese companies have capacities above 2GW.

In this context, while something like the NISE may help domestic manufacturers with their R&D efforts, it will not address the main problem of Indian manufacturing, i.e., the lack of scale.

With 1.75GW already installed, India has gained a good momentum for solar, with ongoing demand created by the NSM and different state policies. Solar is also already a viable option in relation to diesel and grid power in many parts of the country. This means the industry is moving towards minimal government (financial) support. Generation side obligations such as a domestic content requirement will just increase the cost of solar to power consumers and tax payers. However, costs will continue to play an important role in determining the manufacturing in industry’s future. If there is anything that the manufacturers or the government should focus their efforts on, it is to increase the scale of individual manufacturing facilities in order to create a company that can compete globally without government support. Whether it is a good investment for India to create such national champions is a different matter.

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