Month: March 2013

Uttar Pradesh has announced a bidding process for a 200 MW capacity (refer to the Request for Proposal (RfP), PPA and Escrow agreement documents). The state has also finalized its draft solar policy. It is now called ‘Uttar Pradesh Solar Policy 2013′ (refer to the policy document). The policy aims to achieve an installed capacity of 500 MW till March 31st 2017.

PPAs in the Uttar Pradesh Solar Policy will be signed only for a period of 10 years

This covers a typical debt repayment period and is significantly more attractive for lenders and beneficial for developers

Due to heavy losses suffered by power distribution companies in Uttar Pradesh, full subscription but low competition in terms of tariff are expected

A unique aspect of this policy is that the PPA will only be signed for a period of 10 years. This covers a typical debt repayment period, so lenders should not have issues with regards to the PPA timeframe. Considering that the PPA is signed at a tariff of around INR 7 (USD 0.14/EUR 0.11)/kWh, in all probability, the solar project will be able to sell power at a tariff greater than this tariff after 2023. The APPC in India is currently at around INR 3.5/kWh. Assuming an annual cost increase of 7% p.a., in ten years, the APPC will be at around INR 7/kWh. If power prices increase more than 7% p.a., the new PPA can be significantly more attractive. For this reason, we believe that a shorter time period for the PPA can actually be beneficial for the developer.

Like in Tamil Nadu (refer), power distribution companies (discoms) in Uttar Pradesh are also making heavy losses. According to recent estimates, the losses have reached INR 310 bn. Recently, the Indian Credit Ratings Agency (ICRA) and CARE Ratings have compared 39 utilities from 20 states in a grading exercise conducted by the Ministry of Power and the Power Finance Corporation (refer). Four discoms from Uttar Pradesh were at the bottom of the ranking and along with eight other utilities were awarded the “C” grade. As the allocation capacity is limited to just 200 MW, we expect it to be completely subscribed but the competition in terms of tariff to be fairly low.

We will discuss the various Indian solar policies in-depth in our upcoming, 10th INDIA SOLAR COMPASS, published through our website on the 1st of April.

Jasmeet Khurana works on project performance benchmarking, success factors for module sales, financing and bankability of projects 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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Rooftop PV could reduce the capital’s power costs and improve its supply security. These are benefits typically associated with solar. However, the real benefit might lie in reducing Delhi’s chronically high levels of smog. We are only just beginning to understand the economic (let alone social and political) cost of excessive pollution. A look at China helps.

Smog in Delhi has reached extremely hazardous levels

Beijing has comparable problems with smog and is paying a huge economic prize

Policy interventions have worked for Delhi before – solar could be the next step

Delhi’s smog has become a winter scourge. According to an estimate, the deaths of over 10,000 a year are attributable to the bad air quality. Levels of P10, a measure of particulate matter, has in the winter months reached 749 – more than seven times the safe limit. P2.5 has reached 489 or more than eight times the safe limits. Some causes are found within the city (rapidly increasing car traffic, burning of wood, diesel back-up gen sets, coal fired power plants), some are outside of the city (burning off of agricultural residues, industrial air pollution). Meteorological factors play a role too.

The only city that might consistently be scoring worse on the smog index than Delhi is the Chinese capital of Beijing. According to the World Bank (refer), environmental pollution costs China as much as 5.8% of GDP. The costs of air pollution alone are estimated at around 3.8%. They include: healthcare costs, damages to materials, car accidents and flight cancellations. As a result, China plans to invest over USD 500bn into environmental protection until 2015. Experts believe that this is still insufficient: as much as 4% of GDP or more than USD 300bn would be required each year. This is just the economic cost of pollution.

In addition, there is the issue of quality of life. As Delhi will continue to grow and its citizen become wealthier, they will demand better air quality. This will become a political issue. China shows the way. According to a Gallup survey of December 2012, 57% of Chinese already agree that environmental protection should be given priority even at the expense of economic growth. In India, the number is at 45% (refer).

10 years ago, Delhi managed to significantly reduce pollution levels through strong new policy measures, enforcing structural changes and the adoption of cleaner technologies. Today, it could do so through e.g. reducing diesel subsidies, providing more public transportation, moving brick-kilns away from the city, or paving all roads to reduce the dust levels.

Solar could also play a significant role in the transition to a more environmentally sustainable, economically efficient and politically acceptable path to urbanization. Making the use of rooftop PV mandatory for certain building owners or power consumers would reduce the pollution from generator sets as well as from coal-fired power plants. There would be less smog. Today this sounds like a choice. Soon it might become a non-negotiable political demand and economic necessity.

The power tariffs in Delhi for commercial customers are at 8.3 INR/kWh – a price that can already be matched by solar PV (100 kW) installations if storage is not included. PV would be a complementary power source. Storage could become viable, if a 20% increase in tariffs (demanded by utilities), the cost of power stored in inverters (20-50% higher due to inverter inefficiencies) or diesel back-up costs (anywhere between 12-20 INR /kWh) are considered. Residential consumers, currently paying only INR 6/kWh might also turn to solar soon. The government can accelerate a transition to solar in Delhi by providing subsidies, by allowing for regulatory improvements such as net-metering or buy granting tax advantages (e.g. on VAT). Any additional cost for solar power to the government and to the public should be more than outweighed by the environmental cost of not reducing smog levels in Delhi.

BRIDGE TO INDIA and Greenpeace are currently exploring the case for solar rooftop PV in Delhi and will be publishing a joint report soon.

Tobias likes to write about solar business models, solar and energy policy and wider issues of sustainability, development and growth.

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The Indian state of Punjab has released a request for proposal (RfP) document for allocation of 300 MW of solar PV in the first phase of its state solar policy (refer to the RfP document). Punjab had earlier set a target of 1 GW of new solar capacity by 2022 in its ‘New and Renewable Sources of Energy Policy – 2012′ (refer to the policy document), which was released in December 2012.

Punjab is the first state to allow the use of agricultural land for setting up projects

50 MW is to be allotted for companies with no experience in setting up solar projects, while 250 MW is to be allotted for experienced companies

The policy is expected to attract higher tariffs than other states due to a higher cost of land and lower irradiation than other states

Project developers are given various incentives such as exemption from Value Added Tax (VAT) on equipment, exemption from entry tax for equipment supplies, exemption from payment of fee and stamp duty for registration / lease deed charges for the project’s land requirement and exemption from change of land use (CLU) charges. There is no domestic content requirement under the policy. Punjab is the first state to allow the use of agricultural land for setting up the projects. This is especially relevant as almost the entire state is made of up cultivable land as opposed to Rajasthan and Gujarat where large tracts of desert wasteland can be used for setting up solar projects.

The project allocation has been divided into two categories:

A total of 50 MW is to be allotted for newly incorporated or existing companies that have no experience in setting up and operating solar projects. The minimum capacity of the project has been set at 1 MW and the maximum capacity at 4 MW. The allotment of project capacities in this category will be in the multiples of 1 MW.

A total of 250 MW is to be allotted to experienced companies that have installed and commissioned at least one project with a capacity of 5MW or higher anywhere in the world which is in operation for at least one year before the last date of submission of e-bid anywhere in the world. The minimum capacity of the project can be 5 MW and the maximum capacity allowed for a single developer is 30 MW. The allotment of project capacities in this category will be in the multiples of 5 MW.

The benchmark tariffs for the bidding process have been fixed at INR 8.75/kWh for companies not availing accelerated depreciation and INR 7.87/kWh for companies availing accelerated depreciation. The RfP allows a period of six months for achieving a financial closure and 13 months for commissioning from the date of signing the PPA. The developers have to submit bank guarantees worth INR 4m/MW. Developers face a fine of 30% of this guarantee in case the project is delayed up to one month and the entire guaranty will be en-cashed for a delay of two months.

Punjab policy is expected to attract higher tariffs than other states like Rajasthan, Tamil Nadu and Odisha. This is primarily due to the high cost of land, which can be up to at least 5-10 times more than in Rajasthan, and a lower irradiation, which can be up to 20% lower than in Rajasthan.

The pre-bid meeting is scheduled for 3rd April 2013 and the last date for bid submission is 25th April 2013.

Overall, the policy has no salient features that make it either particularly attractive or risky, except for the fact that Punjab has a loss making power distribution company and payment security will be an issue. Given the short timelines as well as the fact that the policy requires developers for Category – II to have more than one year of experience in running a plant, established developers are clearly favoured over new entrants (who can still go for Category – I plants).

Jasmeet Khurana works on project performance benchmarking, success factors for module sales, financing and bankability of projects 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.

What are your thoughts? Leave a comment below.

As the Indian solar market is moving from subsidy-driven PV projects with public PPAs to commercially-driven private PPAs, two trends are emerging to service India’s power customers: large PV plants (e.g. 100 MW), located in high irradiation areas selling power through the grid directly to end-users and local, captive PV plants (e.g. 100 kW). Both might have a role to play in India. Which model will provide the end customer with cheaper solar power will depend on economies of scale and the cost of using the grid.

Large plants make sense in areas with good grids and favourable policies

Small plants make sense in areas with bad grids

A new household level retail market is fast emerging

The Indian solar market is abuzz with talk of large PV plants. We have been in various interactions with developers who are looking to build PV projects of 50 or 100 MW, sometimes 200 MW. Even 1 GW projects are being considered. To be sure, there is a long and stoney path between talk and realization. Yet there is a clear trend towards conceptualizing large plants.

In some ways, this is a natural progression from the 5 MW plants allocated under the National Solar Mission (NSM) phase 1 batch 1 (a ‘learning’ size), followed by the 10 to 50 MW plants allocated under subsequent policies. It also means that the transaction costs of such plants make sense. The developer can get a much higher return for time invested. Such projects can easily absorb the fees of extensive data gathering, detailed project reports, expensive consultants and lawyers or the cost of international travel. Most importantly, it is a size that lending institutions and certain equity investors find attractive to due diligence and perhaps fund (refer to our report on bankability and financing of solar in India). This resonates well with those accustomed to traditional power plants and other large infrastructure projects. However, it does not imply that the price of the solar power offered to the market can be exceedingly low and the return of the project particularly high.

According to our estimates, the cost per MW of installed solar capacity between 5 and 100 MW comes down by around 5-10%. (There is a significant drop in prices upon reaching 1 and then 5 MW and the economics might change significantly above 100 MW, bearing in mind that there might also be adverse effects of scale, such as an increased cost of acquiring suitable land or new evacuation infrastructure that might have to be built.)

A key determinant of the cost of power to the end customer that can be supplied through such projects will be related to the grid: outage times (often more than 20%) and various fees such as cross-subsidy surcharges, open access charges, banking, wheeling, etc. Some policy makers are thinking about reducing or entirely waiving grid charges for solar projects. The recent solar policy of Andhra Pradesh is an example. This can be a game-changer.

An alternative to building large projects, supplying solar power through the grid to end customers is to supply power directly to the customer through an on-site plant. This avoids or at least greatly reduces the need to use the grid or acquire land – two large headaches of solar in India. On the other hand, financing is more difficult to obtain as projects are much smaller in size and there is a higher off-taker risk. What happens if the on-site power customer no longer wants to buy the power? A key issue here is to ensure that the power customer is bankable and contracts can be enforced (refer to our Project Development Handbook). The risk can also be mitigated through a portfolio of projects across which default can be managed. In such a portfolio, also, financing and sourcing can be done for a larger number of MWs, unlocking similar scale effects as large projects can. The American solar power provider SolarCity, which successfully went public in December 2012, has installed over 40,000 systems. It gets excellent module prices and good financing conditions.

At projects sizes between 1 MW ans 100 MW, the market moves from a utility (power sale) model to an equipment sale model – with a number of hybrids (downpayment, lease, etc.) emerging along the way. One of the most dynamic markets in India today is the rooftop PV market for households, where many new companies and business models are emerging, especially in the South, in Kerala (refer) and Tamil Nadu (refer to our Tamil Nadu Policy Brief). Here, net-metering is the potential game changer.

The described markets will have fundamentally different success factors and drivers. Sustainable success will require such long-term USPs as access to low cost financing, to power customers or to a strong sales and marketing network (refer).

Tobias likes to write about solar business models, solar and energy policy and wider issues of sustainability, development and growth.

What are your thoughts? Leave a comment below.

CSP in India has had a bad run over the last two years. The enthusiastic initial party mood was quickly followed by a collective implementation headache with a number of challenges threatening the viability of projects. Now, further allocations have been postponed. At the same time, the focus shifts from large power plants to hybrid models. India is increasingly able to produce large parts of the value chain locally.

CSP projects in India are in trouble and policies are on hold

CSP has lost out against PV

Hybrid and de-central applications may give CSP a new future in India

In the past two years, Indian CSP projects have faced numerous difficulties: DNI data is not accurate, financing costs in India are high, banks are hesitant to lend (refer to our report on financing solar power in India), government support is waning, gas water and land are in short supply. Timelines are too ambitious and margins too low. The resulting cutting of corners has backfired. The complexity of setting up CSP plants has been systematically underestimated. Today, the only CSP plants up and running in India are a 2.5 MW solar tower in Rajasthan by Acme Telepower and a 3 MW parabolic trough project by IIT-Mumbai in the Solar Energy Center in Gurgaon. Around 500 MW of the NSM Phase 1 capacity is still under construction – all of it with significant delays. Much will likely never get built. Karnataka only managed to get bids for 20 MW out of 30 MW on offered last year. Rajasthan received no bid for its 100 MW offered this year. Currently, under the National Solar Mission (NSM) Phase II, CSP has been put on hold.

At the same time, solar PV has taken the limelight. There have been hick-ups in PV as well, but because the technology is simpler, faster to build and projects come in smaller ticket sizes, the learning curve has been faster. In addition, the cost reduction of PV globally has outperformed that of CSP.

CSP power plants retain a key benefit over PV in that they can produce better quality (more stable, predictable) power. This is crucial for a country with a fragile power grid infrastructure such as India. However, this advantage over PV might become less pronounced as policies start to shift from grid-connected, Feed-in-Tarff (FiT) driven to encouraging de-central solutions as in Tamil Nadu (refer) and Kerala (refer).

However, CSP might yet still stage a comeback in India. And if it does so, it will be on its own terms, increasingly de-hyphenated from PV. The availability of DNI data is improving. A local supply chain has already developed. Indian companies have started to manufacture tube receivers, frames, curved mirrors and other key components. Costs are falling, with much more potential for localization of manufacturing.

What can help CSP even more, is a policy shift towards hybridization of CSP with other technologies. In 2012, the Ministry of New and Renewable Energies (MNRE) has released a dedicated program for 20-50 MW CSP hybrid plants. The MNE will provide support in the provision of land, water resources, grid connectivity, geo-technical reports, PPA distribution licenses and the environmental clearance. The hybrid plants shall include the following combinations: a CSP plant with hybrid cooling to reduce water consumption, a CSP plant with steam temperatures higher than 500°C, a CSP plant with more than 10 hours of storage to achieve 24/7 operation and a CSP plant with 30% natural gas support. The focus of these hybrid plants is clearly on developing solutions tailored to Indian challenges and requirements.

In addition, CSP would be able to provide process heat solutions to factories reeling under power shortages and rising power process across the country. This would be relevant especially for industries with high energy and heat demands such as pulp and paper, steel, cement, or textiles. What needs to be done at this stage is to provide more working examples of how solar technology can reduce energy costs and improve energy security.

Tobias likes to write about solar business models, solar and energy policy and wider issues of sustainability, development and growth.

What are your thoughts? Leave a comment below.

Karnataka has announced a second round of allocations under its state solar policy. In the last round that took place one year ago, 80 MW was allocated (refer).

Allocations of 130 MW of PV as well as CSP projects are targeted

The policy aims to meet the RPOs of distribution companies, and makes no attempt to put forward more ambitious targets like in other states

The state has opted for a reverse auction based on a benchmark tariff of INR 14.50/kWh for PV and 11.35/kWh for CSP

The new bidding process aims to allocate a capacity of 130MW (refer to the PPA and Request for Proposal (RfP) documents). The pre-bid meeting will take place on 12th March 2013 and the bid submission due date is 28th March 2013.

In the first round, 50 MW was reserved for PV and 30 MW for CSP. However, since proposals for just 20 MW of CSP came in, the remaining 10 MW had been transferred to PV. This time round, no demarcation has been made for PV and CSP. Given that the maximum size of a single project is 10 MW as per the RfP document, it is unlikely that any developer will bid for CSP. The minimum size for a single project is 3 MW.

The primary aim of these allocations is to meet the Renewable Purchase Obligation (RPO) of the state’s power distribution companies. No attempt has been made to deviate from this limited objective and put forward more ambitious targets like other states such as Gujarat, Andhra Pradesh and Tamil Nadu have done. The bidding process in Karnataka is similar to its previous allocations as well as to phase one of the National Solar Mission (NSM): a reverse auction, based on a (rather surprising) benchmark tariff of INR 14.50/kWh for PV and 11.35/kWh for CSP. Unlike other new policies in Tamil Nadu, Andhra Pradesh and Rajasthan, the state has not opted for the L1 process, wherein developers are asked to meet the lowest bid.

Stability in Karnataka might be considered a good thing on the face of it. However, solar is a new market and the regulatory environment has been evolving constantly over the last two years, with plenty of opportunity to learn from different policies.

For example, Gujarat came out with the concept of solar parks. Solar parks help developers streamline the development process. Andhra Pradesh became the first state to waive open access, wheeling and other grid-related charges, thereby opening up the markets for direct third party power sales (refer). Tamil Nadu pioneered Solar Purchase Obligations (SPOs), effectively shifting the cost of solar from debt-ridden power distribution companies to large power consumers (refer). Both Kerala and Tamil Nadu are planning to offer net-metering, which can open up the immense potential of the residential market. India is currently a great laboratory for solar policies (refer), with a key focus on ensuring bankability (refer). To stand still in such a dynamic market means losing out on opportunities to deliver more solar power more rapidly to more consumers at lower rates.

Jasmeet Khurana works on project performance benchmarking, success factors for module sales, financing and bankability of projects 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.

What are your thoughts? Leave a comment below.

BRIDGE TO INDIA has come out with its latest report, ‘Bankability and Debt Financing for Solar Projects in India‘. The report looks at debt financing for solar projects in India from two perspectives: the lender’s point of view and the borrower’s point of view. The lender’s point of view addresses the bankability of solar projects in India by covering all the risks and their respective mitigation strategies. Here we help the developer’s understand the steps they need to take to increase their chances of receiving non-recourse financing. From the borrower’s point of view we cover how the project finances can be structured in an optimum manner. We go into the details of how bridge financing can be used to solve liquidity issues. Also, various sources of financing have been discussed in detail.

Lenders have concerns with debt recovery and the legal enforceability of claims in India in general. This is a concern that extends to any project-related finance in India

On the intermediate level, with respect to the Indian solar market, banks have two main concerns: the first is the limited availability of irradiation data and the strength of PPAs

Unavailability of non-recourse financing is a critical hurdle in the expansion plans of developers as they cannot continue to accumulate recourse on their balance sheets

Till the time non-recourse financing becomes more readily available in the Indian market, access to the right financing options will remain the key differentiator across different developers and their projects

Solar projects in India still struggle to raise debt finance. So far, only a small percentage of projects have attained non-recourse financing. Most have worked with either limited recourse or full recourse finance. Banks that have in the past provided non-recourse financing are either Indian commercial banks or international lenders with a development mandate. There are several reasons why non-recourse finance is difficult to obtain. They relate to three layers of the market:

On the macro level, lenders have concerns with debt recovery and the legal enforceability of claims in India in general. This is a concern that extends to any project-related finance in India. Even cross-defaulter clauses of converting debt into equity only have a limited appeal. The best way for a project promoter to reduce this concern is through a strong company reputation and banking relationship as well as through the actual track-record of debt repayment and future plans and debt requirements (the larger the risk to future business of being labeled a ‘defaulter’, the higher the incentive to repay the debt). Recovery of Debts Laws (Amendment) Bill, 2011 was passed in December 2012 in the Indian parliament. Recent modifications of debt-recovery rules will make it easier for banks to recover bad loans and thereby to make more non-recourse financing available in the future.

On the intermediate level, with respect to the Indian solar market, banks have two main concerns: the first is the limited availability of irradiation data, which forms the basis for projecting future revenues. The second is the strength of public power purchasing agreements (PPAs) due to the weak financial health of India’s public utilities. On account of these risks, the market is slowly maturing: more on-ground measuring stations and actual generation data from existing plants provide a stronger set of data. With respect to the strength of PPAs, payments are sometimes backed by guarantee funds and sometimes passed on to the private sector (through Renewable or Solar Purchase Obligations. For Renewable Energy Certificates (RECs) the main questions hover around the enforcement of Solar Renewable Purchase Obligations (RPOs) and Solar Purchase Obligations (SPOs in Tamil Nadu), which create the demand. The project promoter will need to be conservative on yield assessments and evaluate the off-take and REC options very carefully.

On the project level, there can be projects that are simply not well developed. A well- developed project usually starts from the perspective of the debt provider (bankability) by identifying and mitigating risks. The second step is proving viability to the lenders. Our report will primarily focus on steps for improving the bankability of the projects and arranging for project debt.

Currently, a dynamic, early stage, uncertain and regionally diverse regulatory environment also negatively impacts project bankability by keeping the transaction costs for lenders high and visibility low. The nature of solar power projects – with their high upfront capital requirements and low operational costs, typical of infrastructure projects – further emphasizes the bankability challenge. Another issue is that since many Indian banks currently have excess exposure to the conventional power sector, they have very limited funds left over for solar projects. Apart from that, interest rates in India have been at an all-time high. Solar projects financed by Indian banks, non-bank financial companies (NBFCs) and infrastructure funds end up paying an interest rate of over 13% per annum.

Unavailability of non-recourse financing is a critical hurdle in the expansion plans of developers as they cannot continue to accumulate recourse on their balance sheets. In addition, the high cost of financing significantly adds to the cost of solar power in India as compared to more mature solar markets.

Till the time non-recourse financing becomes more readily available in the Indian market, access to the right financing options will remain the key differentiator across different developers and their projects. This is exceptionally important in a competitive project allocation landscape that exists in India. International financing from export credit agencies (ECAs) such as the US EXIM bank and development finance institutions (DFIs) such as the IFC has helped some developers secure a lower cost of debt. Even after completely hedging for currency, a project is able to derive a rate differential of around 100 basis points. These financing sources are also more open than commercial banks to financing solar projects as they tap into funds allocated for climate initiatives and/or have a mandate to promote exports from the host country.

As a trend, project developers and other key stakeholders in the solar industry realize that conventional financing from banks is not the sole answer to scaling up of solar power in the country. Innovative mechanisms need to be worked out. Currently, this innovation is working at two levels: lack of liquidity is prompting project developers to look for instruments like suppliers’ credit and construction finance to get the projects up and running quickly (gaining speed) and at the same time, the high Indian interest rates are spurring efforts to acquire debt from outside the country without a full or partial financial hedge against currency fluctuations.

Download ‘Bankability and Debt Financing for Solar Projects in India’ for free.

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The south Indian state of Kerala has published a draft solar policy (refer). This makes it the ninth Indian state to release a solar specific policy document.

The Kerala solar policy has set a target of 500 MW by 2017 and 1,500 MW by 2030

Unlike the NSM, the state will incentivise distributed solar through Feed in Tariffs

Like Tamil Nadu, Kerala has also tried to pass on the financial burden of RPOs from the state-owned DISCOM to large power consumers. This may be the only viable option for implementing the RPO mechanism

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. Earlier, the state had already initiated a 10,000 rooftop solar power programme (refer).

Until now, all state and central solar policies have emphasised utility scale projects. Kerala’s policy is unique in its focus on distributed power generation. Unlike the off-grid capital subsidy scheme under the National Solar Mission (NSM), the state will incentivise distributed solar through Feed in Tariffs (FiTs). Net-metering and a focus on protocols to improve the quality of the grid (especially community grids that would be integrated with the state’s “no load-shedding”-campaign) will help the implementation. This policy is a further step in a significant development in India towards the implementation of net-metering and community grids to unlock the immense distributed generation potential of India. See also the net-metering initiative under the Tamil Nadu policy (refer).

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). All HT and EHT consumers have to procure 3% of their power from solar until March 2014 and 6% from April 2014 onwards. In future, the SPO requirement will also be applicable for high consuming domestic consumers, i.e., consumers with more than 500 kWh per month. Open access, wheeling and transmission & distribution charges for captive consumers have been waived off in the state. An exemption on electricity duty and conditional banking of power has also been provided.

Given the poor financial health of most state DISCOMs, passing on RPO requirements as SPOs directly to consumers seems to be the most viable option for implementing the RPO mechanism and encouraging solar without burdening public funds. In India, roughly 70% of all RPOs have to be met by Discoms that are in bad financial health. If more states implement such an SPO mechanism, it can revitalise the Renewable Energy Certificate (REC) market that is currently written off by many stakeholders due the lack of RPO implementation.

Jasmeet Khurana works on project performance benchmarking, success factors for module sales, financing and bankability of projects 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.

What are your thoughts? Leave us a comment below.