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Tamil Nadu’s net metering policy – a step forward and two steps back

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Tamil Nadu announced its final order on LT connectivity and net metering on 13th November 2013 (click here to view it). The highlights of this order are:

Generation Based Incentive (GBI) is applicable for domestic (residential) consumers. This makes the policy an attractive proposition for homeowners

This regulation is limited to government run institutions and residential consumers. Unfortunately, the net metering scheme rules out those consumers for whom solar would actually make sense – commercial clients (IT companies, private hospitals, educational institutes, malls and shopping complexes) and industries.

There is a policy disconnect between those clients on whom SPO’s are enforced and those eligible for net metering.

Tamil Nadu is one of the first states in India to come out with a net metering policy. It announced the net metering scheme under its flagship solar policy of 2012. Since then, there have been two separate drafts submitted on the Tamil Nadu Electricity Regulatory Commission (TNERC)’s website. The final order announced on the 13th of November 2013, has incorporated several comments from stakeholders.

The policy now allows residential consumers and housing societies to go via the net metering route. The tariff applicable to residential consumers under the highest slabs of consumption is INR 5.75/kWh. It is highly unlikely that any project developer will be willing to offer an OPEX (operating expenses) based solution at a price lower than this figure. Most residential installations will be self-owned (CAPEX: Capital Expenditures). In this case, one can expect a payback of around 10 years without the MNRE subsidy.

BRIDGE TO INDIA earlier interviewed MNRE officials and confirmed that the capital subsidy program (30%) has been indefinitely delayed due to lack of funds (see our blog).

Interestingly, a Generation Based Incentive (GBI) is also being offered to eligible domestic consumers. According to the Tamil Nadu Government Solar Policy, domestic consumers are eligible for a GBI of INR 2.00/kWh for first two years, INR 1.00/kWh for next two years, INR 0.50/kWh for the subsequent two years (Link: http://bit.ly/1cHq9Iv). This is an attractive proposition for residential consumers and can shorten the payback period. In addition to the GBI, there is the Chief Minister’s Capital Subsidy program which offers INR 20,000/kW for LT-1 consumers(link: http://bit.ly/1cNMpjM). It is not clear if both incentives will be simultaneously applicable or not. Nevertheless, the proposition seems attractive enough to incentivize residential consumers to set up their own power plants.

Unfortunately, the net metering policy leaves out industrial consumers and commercial consumers altogether. See table below for list of eligible customers.

Net metering policy: Tamil Nadu

This comes as a surprise because the Tamil Nadu Solar Policy 2012, enforces SPOs on HT I to HT V consumers. Industries typically do not work 24/7/365 and require a banking policy to export excess energy on to the grid. Leaving out such clients from the net metering policy will only increase the unit cost of procurement of solar power for these consumers.

Most factories and industries that fall under this enforcement are exploring the possibility to meet their requirement through in-house power plants. Ironically, this is something that would go against the interests of TANGEDO. TANDGEDO would lose out high value clients. Denying net metering to these clients implies that they would be forced to either procure solar power from TANGEDCO or utilize their grid to wheel power from solar power plants across the state (for which they have to pay a fee to TANGEDCO). Either way, TANGEDCO clearly wants to have its share of the solar pie.

Tamil Nadu’s solar policies are progressive and ambitious. It was the first southern state to announce a GW scale solar policy. It was also the first state to announce a net metering policy. In this case, though, the state has taken one step forward and perhaps two backwards.

What are your thoughts? Leave a comment below

Akhilesh Magal heads the Project Development team at BRIDGE TO INDIA. He likes to present his opinion on the policy environment in solar in India.

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Weekly Update: Solar policy space in India becomes active again

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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.

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

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Distributed power and the grid – what are the technical challenges?

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This blog piece is based on a recent workshop that was part of a joint project by Bridge to India, Prayas Energy Group and IIT Mumbai (National Center for PV Research and Education, NCPRE). Our research results will be published in March 2014. At the event, representatives from state and private sector utilities, government institutions and academia as well as Indian and international private sector companies including solar system installers and inverter manufacturers met to discuss the effects of distributed, infirm power generation on the grid and of fluctuating grids on PV systems. Below are some hypotheses that emerged and that will be tested further over the coming months. As always, we highly appreciate feedback.

Detailed standards and regulations have been developed in Germany and the US to deal with safety concerns

Even at high penetration levels, few challenges are purely technical. Most are commercial, relating to the economics of storage, balancing, spinning, etc

Indian regulators and utilities have insufficient data to fully understand the impact of distributed power generation on the grid

At the workshop, we looked at both the effects of a PV system on the grid and of the grid on the PV system. We assumed net-metering or feeding back into the grid (which is arguably required to achieve significant numbers of distributed PV systems). We looked at safety concerns (especially islanding) and stability concerns (both with respect to the grid and with respect to the PV system). The overall mood at the meeting was that the question is timely – as there are plenty of net-metering regulations on the anvil – and that the challenges are quite manageable. The issue is more to clearly identify the challenges and develop structured guidelines to deal with them.

One of the key concerns of utilities and regulators is the safety and within it the main issue is unintentional islanding. This seems to be a non-issue, however. All quality inverters will automatically shut off, if the grid is down. Regulations from more experienced international markets like Germany and the US can be used to specify technical requirements in India in order to ensure that all new entrants in the inverter market adhere to the same standards. Intentional islanding, to allow local ‘mini-grids’ to continue to operate if the main grid fails, would require a further thought through the set of safety regulations, including communication with the load dispatch centers and utilities.

With respect to grid stability, equally, the inverter can be specified to shut off as soon as the grid frequency is outside of a specified boundary, this protecting the grid from excessive solar power. However, the details need to be clearly spelt out: What are the frequencies at which the inverter shuts off? Should all inverters shut off at the same levels, or should they be phased out at different levels, perhaps based on system sizes or location? Perhaps the tolerable frequency range in India can be larger than in e.g. Germany? What are protocols, standards and certification processes that can be put in place to ensure that systems have the right functionality right from the start? While the issue is still negligible at current penetration levels, it is easier and cheaper to specify these now than to retrofit later. At the same time, it should be avoided to burden smaller systems with excessive standards-related costs that make them unviable. There was a strong sense that distributed PV can actually help to stabilize the distribution grids.

Challenges might arise at the transformer level, if there is a lot of distributed capacity in a certain locality. If it is necessary to limit grid-interactive PV installations, installations would have to be effectively monitored, which could in itself be a difficulty. However, transformers typically have a loading capacity of 110% of the rated load and have safety devices to cut off if that is exceeded. Also, it might be unrealistic to expect solar to exceed the load. Wherever the power demand is high with respect to available space/rooftops, e.g. wherever cooling is used, this is unlikely. The issue might arise in rural areas. However, here the economics of feeding solar into the grid without FiTs are not strong as power prices are heavily subsidized. So this might not be an issue after all.

Another challenge is to manage sudden, sharp drops in PV generation (e.g. if there is a sudden cloud cover). These issues will only arise at high penetration levels, but could be relevant in specific places already quite soon. Gandhinagar in Gujarat, for instance, is planning to install a total of 10 MW of solar capacity (8 MW on rooftops) with a base load power requirement of only 40 MW (25%). This will be an interesting test case for understanding the impact of a high penetration of solar generation on the grid. Inversely, the opinion at the workshop was that voltage fluctuations in the grid and outages of the grid have no significant impact on the functioning or lifetime of PV systems.

The larger grid-management questions relating to stability, such as balancing the grid, providing storage and spinning reserves for times when renewables are not available, pricing the solar power fed back into the grid and pricing distribution and transmission services for this power are not so much technical issues than commercial ones. They relate to the proper incentivization. However, if they are not addressed, they lead to technical challenges of managing the grid. There is little clarity on what would be a dangerous limit of having infirm, unbalanced power in the grid. According to an older NREL study, 20% should be unproblematic. In Germany, the grid has functioned well with penetration rates of up to 60%. Similarly, ‘smart grids’ that allow for a very active communication between different generation and consumption points are not so much a technical necessity as an economic opportunity.

The thrust of the research should be on clearly outlining and structuring the various challenges that need to be addressed and to give Indian and international case studies and data showing how they have been tackled already to increase the comfort level of regulators and utilities. In addition, there should be standardized (modular) requirements for different system types and sizes, including e.g. protocols for grid interconnection points and detailed inverter spec sheets. From the utility and regulatory side, processes need to be standardized to provide fast turnaround times for any permits needed in order to not stall the market.

Tobias Engelmeier is the Managing Director at BRIDGE TO INDIA.

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Weekly Update: India’s national policy is betting big on centralized solar power

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Average project allocation sizes under India’s National Solar Mission (NSM) have been increasing ever since the mission started. The batch one of phase one allowed a single developer to take up a capacity of up to 5 MW. This was increased to 50 MW in the second round. In the first round of phase two, it has been increased to 100 MW. With this, the direction of the national policy is clear. It is moving towards ever larger projects.

MNRE plans to set up five ultra-mega renewable power plants to add up to a capacity of 18 GW over the next 10 years
The central governments focus is on centralized solar primarily to bring down costs and ensure hassle free meeting of targets
According to BRIDGE TO INDIA, it is more important to help solar stand on its own feet than just to meet targets

Now, the Ministry of New and Renewable Energy (MNRE) has taken it a step further by announcing ultra-mega solar power projects. These are envisaged to be gigawatt scale projects. The first of its kind is the 4 GW project that has been allocated to a joint venture of six government owned companies (refer). Bharat Heavy Electricals Limited (BHEL), one of the project proponents, is expected to announce EPC bids for the first 1 GW capacity by March 2014.
According to media reports (refer), the MNRE may be planning to set up five ultra-mega renewable power plants which will add up to a capacity of 18 GW over the next 10 years. However, it is important to note that these are renewable parks and not solar parks . Hence, this would not increase India’s solar capacity by nine-fold as claimed in the report.
According to BRIDGE TO INDIA, the MNRE will stick to its target of allocating 2.52 GW of solar PV capacity by 2017 (refer). The only shift that can be envisaged is that the 1.08 GW of solar thermal capacity will also be diverted to solar PV. This means that a maximum of 3.6 GW can be allocated to solar PV by 2017. Considering that 750 MW is already being allocated under batch one of phase one of the NSM and 1,000 MW is being allocated to the first ultra-mega project, only 1,850 MW will be left to be allocated until 2017. Most likely, up to four projects with a capacity of around 500 MW each will be allocated in 2014 to meet the current five year plan (2012-2017) targets. Apart from this 3.6 GW capacity, any predictions for allocations beyond 2017 cannot be made as of today as they will be guided by a new policy document for phase three of the NSM.
With very little emphasis on decentralized solar under the central government policy, it seems like India has put all its eggs in one basket, i.e., centralized solar. From the ministry’s perspective, the key objective of doing this is to bring down costs and ensure a hassle free meeting of targets.
However, all these decisions are being made by the ministry even when the debate about centralized solar vs. decentralized solar, as the way to go for India, has not even begun. Centralized solar offers economies of scale and helps bring down costs on the generation side. However, this power needs to be transmitted to the consumption end and the losses in between can be as high as 20%. Moreover, in the centralized framework, solar power is competing with the cost of power generated from other sources of power such as thermal, wind and nuclear. Also, under the centralized model, new transmission infrastructure in the form of green corridors needs to be set up.
On the other hand, solar power, unlike most other sources of power, can be generated directly on the consumption end. Under this framework, there is no need to set up new transmission infrastructure and there are no transmission losses. The drawbacks of decentralized generation include higher cost of generation due to the lack of scale and new investments in making the distribution of power smarter at the last mile. Within the decentralized framework, economies of scale can be created if the market size increases and investments in making the grid smarter can also help make distribution of conventional power more efficient.
As a country, until we have a clear answer as to whether centralized generation is better than decentralized generation or vice-versa; it might not be very wise for us to choose a side.
According to BRIDGE TO INDIA, creating an ecosystem which will help solar to stand on its own feet in the future is more important that just meeting the target numbers set under the policy document.
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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Pre-bid meeting brings a lot more clarity for the upcoming NSM allocations

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The pre-bid meeting for allocations under batch one of phase two of the NSM was held today and was chaired by officials from the MNRE (Ministry of New and Renewable Energy) and SECI (Solar Energy Corporation of India).

The first point that was discussed was about the location of projects, its impact on the open access charges and who would be responsible to bear this cost
Another key aspect which was raised was regarding the impact of possible anti-dumping duties on these projects
Aspects related to project capacity and Capacity Utilization Factor (CUF) were also discussed at length

The government officials seemed satisfied that despite a new mechanism of funding, they have been largely successful in keeping the process simple and as similar to the phase one process as possible. SECI took up the responsibility from NVVN of trading power between the developers and the state utilities/any other obligated entities. Senior NVVN officials have helped in this transition. SECI hopes to create a dynamic trading environment, in which a developer is shielded from the direct off-taker risk. A special fund has been allocated to SECI to ensure timely payments in case one or more off-takers are unable to meet their commitments.
Approximately 60 developers along with several equipment suppliers, EPC contractors and consultants were present for the meeting. The variation in the type of developers was evident from the questions raised. On one end of the spectrum, there were developers who were sure that they would be bidding for the maximum possible bidding capacity of 200 MW. Given the fact they can secure only 100 MW, they wanted to know if they need to submit Earnest Money Deposit (EMD) for just 100 MW. On the other end of the spectrum were developers who were just figuring out how to become eligible for the bidding process. Then there was everyone in between. It was easy to count on your fingers to see how, if the bid viability permits, a handful of serious developers could easily take up the entire capacity two times over.
The first point that was discussed related to the location of projects, its impact on the open access charges and who would be responsible to bear this cost. This is a point BRIDGE TO INDIA has been raising since the first draft of the guidelines was released back in April 2013 (refer). SECI and MNRE have clarified that the developer is only responsible up to the interconnection point and will not have to pay any open access charges. Even SECI will not be paying these charges as they have not been accounted for in the margin that they are charging. It is the final off-taker who will end up the paying charges.
Another aspect that was raised regarded the impact of possible anti-dumping duties on projects. BRIDGE TO INDIA has raised concerns about this risk at multiple occasions in the past (refer). A suggestion was made to pre-exempt these duties for the upcoming projects as it is essentially unpredictable and might make projects unviable. The bidding process for India’s coal-fired Ultra Mega Power Plant (UMPP) policy was cited as a precedent for such an exemption. The MNRE officials did not think that a similar step could be taken, but acknowledged the fact that the risk is serious. The ministry will try to provide as much clarity as possible on both the timelines and the dumping proceedings to facilitate an informed decision for the developers.
Several clarifications were made for land procurement and lease related aspects: lease of private land for a project was permitted and a clause is to be added to that effect. The legality of a ‘right to use of land’ (given in states such as Madhya Pradesh) instead of the regular lease agreement will be looked into. The only state government officials that participated in the discussion were from Gujarat. It was indicated that Gujarat might be looking to attract NSM projects by providing support on evacuation and land allotment in the state’s existing solar park.
Aspects related to project capacity and Capacity Utilization Factor (CUF) were also discussed at length. As suggested by BRIDGE TO INDIA earlier, it was amply clear that as the incentive is in the form of an upfront capital infusion, SECI was comfortable with allowing excess generation at the project facilities. Any excess power generated is expected to be bought by SECI at INR 3/kWh. However, as all the excess power generated will be used to meet the renewable purchase obligations (RPOs) of the off-takers, developers will not be allowed to claim Renewable Energy Certificates (RECs) for this power.
The bidding process envisages a wait-list for the allocation process. For the waitlisted capacity, developers pointed out that submitting guarantees for a period of seven months and thereafter agreeing to the bid quoted today will put them at a risk of changing equipment costs and they asked for an option to be created for them to withdraw their names from the waiting list after two months. The MNRE officials agreed to look into the request.
It was clear that, based on everyone’s learning from phase one, the developers now seem much more comfortable with the overall structure of the bidding process and are more interested in understanding the finer details of the documents. The MNRE and SECI officials are meeting with lenders tomorrow to address their concerns as well. A document clarifying the relevant doubts raised by developers along with the necessary changes in RfS, PPA and VGF securitization documents will be published in a few days.
BRIDGE TO INDIA believes that the bidding process is on track and all major concerns have been addressed. We expect the non-DCR part of the biddings to be oversubscribed many times over. As far as the DCR part is concerned, developers are still unsure about the Indian manufacturers’ ability to supply the equipment on time. In case the DCR part of the biddings is undersubscribed, the capacity could perhaps be shifted to the non-DCR part. If that happens, we expect the entire 750 MW capacity to be allocated through this process.
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