The present scenario in the renewable power viz. solar PV, is reminiscent of frenzy seen in the years ~ 2005/2006 to 2009/2010 for coal based power projects, when every businessman worth its salt wanted to put a super critical thermal power plant housed as Independent Power Project (IPP) – 2 x 660 MW being a standard configuration. Some were more aggressive having planned for phase II also i.e., another of 2 x 660 MW plant to be implemented after the commissioning of phase I. And why not ? The Electricity Act 2003 had brought clarity for the private investment in the power sector – generation was delicensed, power trading was made a distinct activity paving the way for setting up of power exchanges, DISCOMs were to purchase power – only after competitive bidding with case 1/case 2 bidding options thus curtailing the monopolist role of NTPC/state GENCOs, regulation related to SERC & CERC were fine tuned, provision of APTEL for resolving up of dispute etc. etc.
Central govt. had kick-started the mad race with successful auction of Ultra Mega Power Projects (UMPP) under Case 2 bidding through Power Finance Corporation (PFC), wherein, large capacity coal based power project sites were offered alongwith captive coal blocks with enough coal reserves to run the plants for 30 to 35 years and assured off-take from participating DISCOMs. States followed suites with their own Case 2 bidding. Parallely, govt also allocated long term coal linkages and coal blocks with tapering linkages till the blocks get fully operationa. Attracted with the fuel security in form of captive coal block/long term coal linkages and assured of power off-take by DISCOMs through Case 1 bidding, business houses successful in other businesses jumped into the power sector. Power sector became the new Eldorado. Private Equity (PE) players soon followed suit and invested large amount of funds in such power plants – some took call on promoters with successful track record by taking minority stake with assured buy back plans or exit through IPO, some were more adventurous and went with majority stake. Most of these PE players were attracted by huge power demand deficit projected and sky high merchant power rates prevailing at that point of time.
Fast forward to 2017
Many of these thermal IPPs are yet to be commissioned, delayed on account of Indian ground realities of red tapeism, delays in getting approvals & clearances, environmental & forest issues etc. Those which have been commissioned are staring at bleak scenario, what with long term PPA with DISCOMs not in place/not being honoured in right spirit, cover of fuel security blown away and merchant power rate plunging to a level barely enough to cover the variable cost, what to talk of capacity charges. The PLF of the recently commissioned thermal projects is barely touching 60% though their viability during appraisal was assessed at base case PLF of 80 to 85%.
The situation has become so grim that the IPPs are not in a position to lift coal even at their lowest permissible threshold stipulated in their Fuel Supply Agreement (FSA) with Coal India, which may trigger payment of penalty by the IPPs to Coal India. The scenario had started changing from 2011-12 when allegation of favouritism in coal block allocation started and finally led to cancellation of coal blocks by Hon’ble Supreme Court in 2014. To make it worse Coal India Ltd (CIL) restricted coal quantity under long term linkage to IPPs for the quantum of power to be supplied to DISCOMs under long term PPA awarded through competitive bidding. However, as only few DISCOMs came out with competitive bids for long term PPA, most of the IPPs which got commissioned had to rely on costlier e-auction/imported coal (recently the coal scenario has changed) to run their plants and sell the power at Power Exchange at a low rate barely covering their variable cost. Worst were the IPPs where PE players had invested as they turned off the tap for further investment towards cost over-run and let the project suffer. This also brought out the short comings of PE investment. Typically PE horizon for investment spans 5 to 7 years, post which they look for exit with returns. In coal project their logic was similar – they were looking for 4 to 5 years of construction and 2 to 3 years for exit. The script went haywire once the projects got delayed and the few ones which got commissioned didn’t generate enough cashflow to entice new investors to give exit to the existing PE players.
Desperation of private sector promoters of coal based power plants
Promoters of some coal based power plants are so desperate that they are even willing to forgo their equity investment for a token amount in favour of new investors as they would like to get the co-llaterls – corporate guarantee of their holding/flagship companies and in some cases even their personal guarantee given to the lenders of the power project to secure the loan, released. This is due to the assessment that as the projects are stuck up and the loan has become sub-standard, the lenders would exercise their rights and may invoke the corporate guarantee/personal guarantee to realize their dues. By this action they would be able to atleast insulate their existing business or their personal assets from the lenders of the power project. Further, as most of these projects have also run into huge cost over-runs requiring infusion of additional equity, by surrendering the project they would also not be required to bring their part of equity. However, despite the offer of promoters’ stake at token or at near nil valuation and the lenders willing to take a hit on substantial part of their debt, there has not been much success in inviting new investors to the beleaguered power projects. There appears to be no appetite left in the investors to invest in thermal power projects.
Implementation risk weighs high on hydro power projects
The story is similar in case of hydro power projects. Being site specific the implementation risk is highest in case of hydro projects on account of geo-technical surprises despite of detailed surveys. Delay in getting timely clearance for forest & environment, coupled with time taken in ‘Rehabilitation & Resettlement’ (R&R) plan are other major factors contributing in delay. Many hydro projects got stalled/delayed midway on account of geological surprises leading to considerable delay, as first – understanding the nuisance of the surprise and then tackling it by alternative ways of construction took lot of time, besides increasing the project cost. Once a project start drawing debt it is suicidal for it to get stranded for any reason whatsoever, as interest to the lenders i.e. ‘Interest during construction’ (IDC) is still payable, besides the inflationary pressure on the construction materials. Many of the hydro projects in the Himalayan region from Himachal Pradesh to Arunachal Pradesh are stuck up on various grounds. The project completion cost have increased and in some cases nearly doubled raising doubts on their financial viability. In the meantime, the investors have been trapped with no exit option. Even if these projects are completed it would be a long haul before they start generating surplus for the investors. In one such hydro project the state govt. had to intervene and takeover the project to complete it as the investors refused to infuse additional funds on account of delays and increase in cost.
Fate of natural gas based power plants
Prior to fiasco in coal based thermal IPPs, power projects based on natural gas had also faced similar scenario, wherein enticed by availability of cheap domestic gas to run the power plants on account of bountiful (so called) gas recovery by Reliance in the KG basin, a number of gas based power projects were put up in 2004 to 2008. The gas from KG basin did flow and touched 60 mmscmd by 2010 and was soon to touch its peak outflow capacity of 80 mmscmd, then suddenly the flow of gas from the basin started petering out and became a trickle of around 10 – 12 mmscmd, which was not even sufficient for priority sector like fertiliser.
It is reported that RIL has cut the gas reserve estimate of KG6 basin from 14 trillion cubic feet (tcf) to 2.9 tcf. In the mean time the price of crude and therefore natural gas escalated to a level where it was not viable to run the gas power plants on imported gas i.e. on LNG (lately the scenario has changed), the fact that as most of the gas based power plants were in the eastern coast near KG basin and the LNG terminals were in the western coast, also did’t helped. The gas based power plants were trapped without any gas and to top it the DISCOMs refused to pay for the capacity charges on one or other pretext – court case followed, which is yet to be concluded till date. As these gas based power plants were shut down due to no fault of theirs, Lenders declared their loan facilities as NPA. Majority of these gas power plants are just sitting idle or running at 1/3rd capacity, though the crude and gas prices have fallen globally, on account of logistic involved in transporting the gas from west coast (where the LNG terminal are located) to east coast (where majority of these gas power plants are located).
Mess created in liquid-based power plants
Not to recall the mess in the mid to late 1990s which was created in liquid based power projects viz. Dabhol, wherein the costly imported fuel (naptha) soon made the cost of generation unviable. Though in this case the mess was also outcome of internal issues in the promoter company i.e., Enron.
Not so success story of biomass power plants
The story of Biomass power plants is no different, which is one of the few renewable source of power capable of feeding firm power to the grid. Planned to run on crop residue, rice husk, bagasse etc., these plants got caught between the vicious circle of tariff hike and increase in the cost of biomass. Among the biomass – rice husk and bagasse are most sought after biomass fuel, wherever they are available. However, rice husk is also a preferred fuel for many small scale local industries like brick klins, foundries etc and majority of bagasse is utilised internally by the sugar factories for co-generation, therefore, running power plant on these two is not financially viable as both are costlier and lead to higher variable cost. That leaves the option of running the power plant on mix of crop residue, which brings its own set of complexities. In the pre-feasibility stage it is assumed that as the crop residue needed to be removed from the fields for planting of next crop and at times they are burned in the field itself, it would be available to the developers at a nominal cost. No sooner the plants are commissioned the felony of such logic became apparent. With a biomass power plant in vicinity, the rate of biomass followed the classical theory of demand supply. Collecting biomass residue from far off locations from the power plant increases the transportation cost. Further, as the crop residue are available only within a short window of time – just after harvesting and before planting of next crop – that too once or twice in a year in most states, collecting and storing to run the power plant throughout the year also became a big challenge. Storage for biomass for long term use required land, was susceptible to fire hazards and also led to deterioration in calorific value. To top it all, many a times the travelling grate boiler which is best suited for biomass crop residue required modification to run on a particular biomass residue, which required shut down of the plant for a considerable time. At present, majority of the biomass plants are shut down and the loans given to them are sub-standard.
Burning of crop residue in the fields by the farmers mostly in Punjab and Haryana have been blamed for pollution & smog in Delhi and even the prodding from High Court to the state govts of Punjab and Haryana to ensure that the farmers do not burn the crop residue in the fields have not resulted in stoppage of such practice. To be fair, both the state govts came up with policy for biomass power projects in order to ensure that the menace of burning of biomass residue in the fields is tackled. The policy ensured yearly preferential tariff, exclusive command area for collection of biomass for a biomass project so that there is no competition for biomass among the power projects etc. Many developers lured by the incentives being offerd came up in both the state to put up the biomass based power project. However, as elaborated above on account of various issues, only few are running and most of them are shutdown causing heavy losses to the investors and creating sub-standard assets in the books of lenders. Few of them which are operating are those which are attached to rice mills or sugar mills with AFBC or CFBC boilers and using their internally generated rice husk or bagasse.
Failure of ‘Renewable Energy Certificate’ (REC)
To give boost to renewable power the central govt imposed ‘Renewable Power Obligation’ (RPO) on the DISCOMs. Further, as the renewable power is not spread evenly in the country, the concept of ‘Renewable Energy Certificate’ (REC) were introduced. The renewable generator were given the option either to sell their power to DISCOMs at preferential tariff or to sell the energy and environment attributes associated with the RE generation, separately. In the second option the environment attributes can be exchanged by the generator in the form of REC. The obligator of RPO can purchase the REC from the renewable generator to fulfil its RPO. An elaborate mechanism of issuance and trading of RECs through power exchange was worked out. However, due to absence of strict penalty on non-compliance of RPO resulted in most of the obligators shunning from buying the REC. presently, not more than 5 to 6% of the REC put up for sale are cleared at the exchange.
Focus on renewable sector – Solar PV to the fore
When all was looking gloomy in the power sector, renewable power projects emerged as a silver lining. Taking into view the inherent advantages offered by the renewables viz. wind & solar, central & state govt gave all support by having conducive policies for renewables, mainly to harness solar power. ‘Ministry Of New & Renewable Energy’ (MNRE), GoI came out with preferential tariff. Gujarat was among the first states to offer lucrative tariffs for solar power projects. Soon other states followed suit. The initial initiative by the state govt to develop solar power were based on MoU route wherein the tariff was known upfront and also the deadlines to commission the solar projects for which the tariffs were applicable. As the prices of modules plunged worldwide with each passing days, the developers took advantage of the crashing prices of modules and implemented the projects at the fag end of the deadline to take advantage of lower module prices. Lucrative tariffs and lower than estimated capital cost of solar modules boosted the returns to the developers and soon the solar power became the new Eldorado. The slide in tariff of energy from solar plants started once ‘NVVN’ the trading arm of Central CPSU – NTPC, invited bids for around 1000 MW of solar through a process of tariff based reverse bidding. The reverse bidding process ushered in a transparent and competitive system which led to developers quoting lower prices taking advantage of drop in the module prices. The state power utilities also followed suit and the rest is history. With reverse auction bidding the prices quoted by the developers fell to a level in certain cases that the lenders started raising doubts on their financial viability. In many such cases of aggressive bidding the lenders stipulated higher contribution from the promoters in form of decrease in debt:equity ratio.
As the solar PV become flavour of the season, what with conducive govt policies, concern over pollution from fossil fuel based power plants and falling module prices, the plant size at single location increased from kW size to MW size and plus. The early MW size of 1 to 5 MW in single location in no time became 5 to 10 MW and at present plant size of 25 to 50 MW are common. So far so good ! However, to have ‘Economy of Scale’ (EoS) the Developers have now started eyeing plant capacity of 100 MW plus at single location, some are planning of 300 to 500 MW and there are talks of even putting up ultra mega solar projects with capacity of 1000 MW plus at single location in line with UMPP for coal based power projects. However, large capacity installation of solar PV in the range of 500 MW plus at a single location are fraught with danger of destabilising the grid which emerges from the infirm (i.e., unpredictable) nature of the electricity from solar PV. The power from solar PV power plants are solely dependent upon the vagaries of nature and dependent upon the presence of sun light. Apart from the infirm nature, the electricity from solar PV is also prone to variability which means the electricity from solar PV is non-controllable i.e., the power output would be a non-steady output. In solar PV, the energy output is directly related to the intensity of sun light termed as insolation – higher the insolation, higher is the output. The electricity in Solar PV starts flowing to the grid after some time past sunrise and ebbs out before sunset- typical time of electricity generation would be from 7-8 am in the morning to around 4-6 pm in the evening, with some variations in summers and winters. Further, the electricity from solar PV typically follows a bell curve with peak levels reaching in the afternoon from 11-12 am to 1-2 pm. The output is also susceptible to any shade on the solar panels and therefore is negligible during rainy or foggy days. Similarly, the energy from wind mostly peaks during night and 80 to 90% generation is during the peak season spanning 5 to 6 months from March/April to Sep/Oct, generally coinciding with the monsoon months.
In my article ‘Grid stability must before ramping up Solar PV’ published in October 2015 edition of ‘Electrical India’, I had elaborated on the need for taking measures to stabilise the grid before ramping up the solar PV in line with govt’s vision of adding 100 GW of solar power and another 60 GW of wind power to the grid by 2022. As of now the renewable portfolio of solar & wind account for ~10% of the total installed power capacity and contribute ~4 to 6% of electrical energy which is on account of their lower PLF. Even with 60 to 70% achievement of targeted solar & wind capacity by 2022, the renewable portfolio may account for ~25 to 30% of installed capacity, contributing ~12 to 15% of electrical energy. As Solar PV and Wind both would be generally generating during off peak hours, measures for sucking up the excess power during non-peak hours through mass storage devices to be used during peak time has to be in place in order not to de-stabilise the grid. In context of Solar PV it would mean storage device for 4 to 6 hours, to shift excess power generated during day off peak to evening peak hours. Mass storage devices for 4 to 6 hours would be costly and would add to the generation cost of electricity from the renewables. Therefore, there is reluctance from the DISCOMs to call bids with such large capacity storage.
Apart from the need to shift off peak surplus power from renewables to peak hours which would require storage of 4 to 6 hours in case of Solar PV, there is a greater need for having a back up storage for ½ hours to 1 hour in case of large capacity Solar PV projects, to take care of grid disturbance during sudden inclement weather like storms or cloud cover. As long as the plant capacity at a single location hovers around 50 to 100 MW, their impact on grid in case of disturbance would be manageable. The impact on grid would become pertinent once the focus shifts towards installation of capacities in the range of 500 MW plus in solar PV at a single location.
There are already news of Load Dispatch Centres (LDCs) of some states instructing solar projects to back down during their peak generation hours which may be on account of over supply to the grid, among other reasons. This is despite the fact that solar power projects have ‘must run’ status as there is no fuel involved in energy generation and therefore, normally, it should have been the other way round i.e. the thermal power should have been instructed to back down. However, for a cash starved DISCOMs it is beneficial to back down solar power as payment for energy from thermal power (under long term PPA) is paid through a 2 part tariff – fixed (capacity) charges to cover the plant’s fixed expenses like lenders interest etc., and variable charges to cover fuel cost. In case the thermal plant is instructed to back down the fix or capacity charges are still payable. As solar plants are not paid through 2 part tariff and are only paid for the energy injected in the grid, in case of backing down they are not paid. The DISCOMs are yet to face grid disturbances on account of sudden power loss due to inclement weather from mega Solar PV installations (capacities exceeding 500 to 1000 MW plus at a single locations), as mega solar pv plants are still in planning or implementation stage. The moment the DISCOMs face one or two grid breakdown on account of inclement weather the reaction would be typical– lot of hue & cry, formation of a panel to fix accountability etc.
Issues being faced by the wind power plants
Now let us see what is happening in the wind power, which is slated to add 60 GW by 2022, on top of the present ~ 27 GW. Wind power has been in India for the last 25 to 30 years and is already a matured sector. However, as against falling capital cost of Solar PV, the installation cost of wind power has been steadily inching upwards – from around Rs 50 million per MW in 2007-08 to Rs 70 to 85 million per MW currently – depending upon site and type of ‘Wind Turbine Generator’ (WTG). Sites having higher PLF command a premium. Similarly, WTGs having higher hub height alongwith longer blades and gauranting higher PLF increase the project capital cost. The reason for increase in the capital cost of wind power projects being that it is just like other E&M equipment consuming lot of steel and copper, not to talk of cement for a solid foundation. The cost of all these ingredients have been increasing in line with inflation – say for a blip here & there. In contrast major part of the cost of solar pv consists of solar panels where the cost have been continuously falling. No wonder the cost of solar pv which was around Rs 200 million per MW in 2010 has fallen to around Rs 50 miilion to 60 million per MW, depending upon location and features like trackers etc. The higher or lower cost of installation is also reflected in the sale rate of both the renewables – in case of wind the preferential tariff across the states has increased form around Rs 3 p.u. to around Rs 5 p.u. whereas in case of solar pv it has drastically fallen from around Rs 15 p.u. in 2010-11 to around Rs 5 p.u. Fall in tariff in case of solar pv has also been helped by the fact that as against preferential tariff route in wind, the tariff in solar are determined through bid process, which results in competitive environment.
Keeping in view the falling tariff in solar pv there has been talk of having competitive bidding in wind power also, however it would be a challenge to opt for competitive bidding in case of wind as the wind power is very site specific even in locations which are high wind zone as compared to solar which is more wide spread phenomenon. The wide variation in PLF in case of wind power is another factor as compared to Solar PV where the variation in PLF among different sites are of narrower range. Further, the identification of high wind locations is usually minimum of 2 to 3 years process as it involves putting wind mast for collection of wind data for at least one or two yearly cycle. Moreover, majority of better wind zone locations are already acquired or taken on lease by the WTG manufacturers and are subsequently put on sale by them. This model of pre-owning the wind power locations is one of the biggest stumbling block among other reasons, in opting for competitive bidding in wind power as it would lead to arm twisting by the WTG manufacturers of a developer who would be L1 in the competitive bidding and scouting for the winds sites.
Wind power developers are already facing challenges in state like Tamilnadu, Rajasthan and Maharashtra where they generate energy which is more than the RPO requirements of these states. In the state of Tamilnadu the wind IPPs have suffered in recent past – first due to delayed realisation of their dues by around 1year and subsequently due to congestion in evacuation corridor as well as shutting down of local sub-stations, due to which they were not able to pump in power, leading to loss in revenue. The situation continued even though some of the wind IPPs migrated from preferential tariff regime selling to state DISCOMs to private companies through group captive mode as they were still not able to evacuate power on account of continuing congestion in the evacuation corridors. This is on top of the cross subsidy charges levied by the state power utilities which can be as high as Rs 2 p.u. in some states. In states like Maharashtra the wind IPPs have not been paid for the last 8 to 10 months. The situation is also not good in MP where delay in payments to wind IPPs frequently reach 4 to 6 months.
Experience of Solar PV cos
As of now the Solar PV companies are able to get their dues nearly on time. First, as the installed capacity is less compared to wind and secondly, being the flavour of the time – what with central govt having full focus on it, no state wants to rock the boat. However, going forward this may not be the case as the proposed huge Solar PV addition to the grid without proper storage has the potential to destabilise the grid. Secondly, the sale rate of power from Solar PV are still higher then the ‘Average Price of Pooled Power’ (APPC) of most of the state or the prevailing rate for power (Day Ahead Market – DAM) at Energy Exchange. Thirdly, in case of surplus power in the grid, despite ‘must flow’ status of renewable power, it would make commercial sense to the DISCOMs to back down the power from solar PV, as backing thermal power being sourced through long term PPA would still entail payment of fixed charges, which would be a double whammy for cash starved DISCOMs (as currently being done by some states). Presently, the DISCOMs are not obligated to compensate for loss of revenue to the renewable power in case of back down. This is an irony as the renewable power has the status of ‘must flow’ and must not be backed down. The proliferation of roof top solar in the cities would further expedite it as it would directly replace the power being supplied by the DISCOMs to creditworthy city users, leading to loss of business to these DISCOMs.
With huge capacities planned in Solar PV, sooner or later many of these power plants would be facing delays in getting sales revenue or worse loss of revenue on account of refusal from DISCOMs to off-take the power on one pretext or other as being faced by other sub-sectors of power viz. coal/gas based, biomass power projects and presently being faced by the wind power projects. As most of these Solar PV plants are financed by lenders on non-recourse basis to the tune of around 60 to 80% of the completed cost, it would in turn erode the capability of the plants to pay their dues to the lenders on time and may become sub-standard. Even if a capacity of around 50 GW to 60 GW is commissioned as against the target of 100 GW, with a 70% debt it would amount approximate debt of Rs 1,900 billion to 2,300 billion (with a per MW cost of ~Rs 5.50 crs), which may stare at becoming stressed.
This would shake the confidence of the investors, which includes many marque names in the Private Equity field. After the sordid fate of investors in the thermal IPPs, a setback in renewable sector would shake the confidence of the investors in the entire Indian power sector for times to come.
Power from renewables is inflation free, sustainable, available in abundance and above all carbon free. For a country like India which imports majority of fossil fuel, harnessing the renewables for power would lead to self reliance and saving on foreign exchange. Govt of India has rightly stepped up the target of adding power from renewable and due focus is being given in tweaking the policies from time to time to achieve the increased target. States have also realised the importance of renewable and are encouraging its development by facilitating land acquisition and expediting approvals.
Among the renewables, Solar PV is more widespread, modular, scalable with low gestation period and easy to maintain. The disadvantage is its largely infirm nature, which needs to be taken care as not to destabilize the grid and would therefore require storage mechanism. One, for short duration, say for ½ hour to 1 hour to take care of sudden inclement weather and second, for 4 to 6 hours to shift the energy from off peak hours (noon hours) to peak hours (evening and night). As the option currently for such storage is through batteries which would escalate the cost of power from renewables drastically, not much serious thought on this issue has been given by the DISCOMs. In any case most of the DISCOMs in the country are in financial mess and are being bailed out from bankruptcies by the govt from time to time. Though the issue is being discussed at various forums, no concrete plan has emerged till now. There is not much push from regulators or planners also on this account on the apprehension of increase in power tariffs. In some isolated grids like Andaman Island Solar PV is being planned with enough storage to take care of night load, as it would replace the DG power sets which are majorly powering the present power needs of the island. There are reports of ‘Central Electricity Authority’ (CEA) planning for Pump Storage hydro schemes, a viable option for long term sustainable mass storage for infirm renewable power, it would take anywhere from 5-6 years to 8-10 years before such pump storage hydro projects are commissioned.
As the pace of addition of Solar PV capacity to the grid gathers steam, without storage, the Indian power sector is definitely staring at a catastrophe in the times to come, which would inturn trap the investors as well as create stressed assets for the lenders. It is high time that the planners, policy makers and Regulators ensure that the DISCOMs or for that matter any institution which is inviting solar pv bids e.g. ‘Solar Energy Corporation of India’ (SECI), NVVN etc, reserve some part of the capacity under bidding with storage. Start with ½ – 1 hours storage and gradually increase it to 4 to 6 hours. Initially there would be a lot of reluctance as this would lead to spike in the bids but ultimately the advantage of grid management and stabilization would override it. With proliferation of storage devices (read batteries as of now) it’s cost would come down as it has happened in the case of Solar PV projects. In the long run, hydro power projects – conventional storage or pumped storage including pure pump storage would be a viable and sustainable mass storage in the Indian context, till a new mass storage technology emerges which is both i.e. financially viable and environmentally friendly.
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