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Non-performing Power Sector Assets

Signalling a Larger Crisis

C P Chandrasekhar (cpchand@gmail.com) is with the Centre for Economic Studies and Planning, Jawaharlal Nehru University,
New Delhi.

Desperate attempts to prevent liquidation of power sector assets in companies that are defaulters point to a deeper crisis afflicting neo-liberal growth. A sector that was plagued by shortages was opened up to private participation, leading to rapid expansion in the expectation of large profits from liberalised prices. Public sector banks were called upon to finance that expansion with the government being complicit. Now, however, firms find themselves trapped between inadequate demand at prevailing prices and rising costs that precipitate default.

Having overcome a legacy of ext­reme shortage of supply, India’s power sector is in the midst of a crisis with ramifications of a wholly diff­erent kind. The crisis arises because firms accounting for a significant proportion of power sector assets have defaulted on their debt-servicing commitments, and banks are not able to find ways of rest­r­u­cturing that debt or recouping their money. So the Reserve Bank of India’s (RBI) guidelines require that the assets should be liquida­ted to recover whatever is possible and compensate banks from which these firms had taken loans, and then defa­ulted. But the assessment is that liquidation would yield the banks little, if anything at all.

There are 34 projects that have been ide­n­tified as stressed, accounting for 24,405 MW of commissioned capacity and another 15,725 MW of capacity that is still under construction. The total outstanding debt in these projects is `1.74 lakh crore. The projects are stressed either because the loans concerned have been declared as non-performing assets (NPAs) or are identified as being potential NPAs. Gross NPAs in the power sector were, at the end of June 2017, placed at `37,941 crore, of which as much as `34,244 crore was in generation. But the magnitude of NPAs is set to rise in the coming weeks and months.

Banks are not keen on going in for liquidation, as they expect the “haircut” or the loss that they would incur to be substantial, because the receipts from the sale of assets would fall short of payments due to them. But as per the February guidelines issued by the RBI, banks had 180 days from the first date of default on payments to settle the matter. That deadline has passed in late August for many firms in the power sector, requiring the banks to move for liquidation of assets.

To avoid that outcome, the concerned banks had approached the RBI to give them some flexibility as they seek to find alternative ways of recouping better value from these assets. But the RBI has turned down the request. Large losses seem unavoidable. That would erode the capital base of the banks and necessitate recapitalisation. The government as ow­ner must take a call and recapitalise the banks with taxpayers’ money. In the final analysis, the losses, much of which are incurred by new privately promoted projects, are being socialised.

This peculiar situation raises a number of questions. To start with, the default by multiple players needs explaining. Given the scale of the problem and the large number of players involved, it cannot be attributed to mismanagement alone. Nor could it be attributed to government inte­r­­vention. Both the electricity sector (esp­eci­ally after the passage of the Electricity Act, 2003) and the coal sector (after the Supreme Court quashed all but four coal allocations, and the government moved to auctioning coal res­ources) have been subject to a major shift in policy to a market-friendly regime. Ele­­ctricity tariffs are subject to some regulation no doubt, but tariffs are based on actual costs to which is added a needed return. So if generating companies are able to justify their cost claims, which in the case of these mainly thermal power projects in­clude a substantial coal cost component, recommended tariffs are set on that basis. The generating companies enter into power purchase agreements (PPAs) with supplying firms that then reach the power to consumers whether through their own or hired distribution facilities.

Liberalised Prices

A core problem app­ears to be that post liberalisation, power capacity has expanded so fast that not all generators are able to tie up PPAs at prices that are reasonable. There has been a growth of short term and spot market sales arrangements with relatively low prices on offer. This trend has been stren­g­thened by the emergence of unutilised capacities. At the end of fin­ancial year 2001–02, before the Electricity Act, 2003 liberalised entry into the sector, installed generation capacity stood at 1,05,046 MW. That figure rose to 1,32,329 MW at the end of March 2007, 1,99,877 MW at the end of March 2012 and to a remarkable high of 3,29,298 MW in March 2017. Clearly, expecting to gain from the opening up of a sector characterised by shortage, private investors had rushed in without a clear assessment of market demand at the higher, liberalised prices. The Ministry of Power claims that despite this growth of capacity, there is no surplus in times of peak power demand. But, there clearly is substantial surplus during off-peak hours, since the plant load factor of thermal power plants has fallen from 79% in 2006–07 to 60% in 2016–17. Part of the problem seems to be that the depressing effects of higher (post-liberalisation) prices on demand had not been factored in when demand projections were made.

Moreover, some firms had either not provided for the possibility that they may not have assured access to reasonably priced coal or had presumed that they would be able to cushion the effects of higher-priced coal by hiking prices fixed in PPAs. This did work for some, but not for all. Many of the firms that are defaulting have not been able to enter into PPAs, and are dependent on short-term markets. Distribution companies too have woken up to the fact that they can access cheaper power outside of PPAs.

One indicator of the state of play is that, wanting certainty with regard to coal supply, firms faced with a competitive power market have been willing to negotiate PPAs in which power is priced, based on zero coal cost. The government adopted a special reverse auction process for those bidding for captive coal blocks from the power sector, where the prices are regulated through PPAs or price fixing authorities. The winner was the bidder who was willing to set coal price at its lowest for calculation of power tariffs to be included in the PPA. Bidders had to compete to offer discounts relative to the price of equivalent grade coal charged by Coal India Limited (CIL), which was set as the ceiling price. If no coal block auction had been held, CIL’s price would define the coal cost taken into account when pricing electricity, irrespective of the actual cost of extracting coal from the captive coal block that supports electricity production. Under the reverse auction scheme, the bidder quotes a price equal to or below the CIL benchmark, which would be taken into consideration when pricing electricity produced with coal extracted from the block being auctioned. Besides this, the bidder must offer to pay the government of the state in which the block is located a fee quoted per tonne for the coal extracted. The reserve or minimum fee to be paid to the state government was set at `100 per tonne. What is surprising is that in the case of many blocks, bidders have agreed to set the fuel cost in the power tariff calculation at zero. That amounts to absorbing the costs of extraction by reducing the margins they receive. In addition, these bidders have, in an associated bid, offered to pay the state government much more than the `100 per tonne reserve price. Competition was clearly depressing the margins garnered by the generators.

Distressed Loans

Those without access to captive blocks have not been free of problems either, because the price of coal from other sources such as imports, for example, has been rising. Trapped between depressed power tariffs and falling demand, on the one hand, and rising coal prices or inadequately compensated coal costs, on the other, the industry has found its profits eroded, leading to the failure to meet debt service commitments. The problem is that with banks having financed the expansion of capacity in this sector to a substantial extent, they are taking the hit. Promoters are walking away, leaving the banks to fend for themselves.

However, unable to find a buyer whose offer pleases all lenders, the banks have not been able to meet the government’s deadline for resolution, and are now required to take the assets to liquidation. Thus, the Power Finance Corporation (PFC) was looking to recover the distressed loans by selling three power units (GMR Raikheda with 1,370 MW, KSK Mahanadi with 2,400 MW, and Avantha-owned Jhabua Power with 600 MW) it had partly lent to. But, other lenders were not willing to accept any of the available bids since they were too low. With few takers for these assets, especially those in firms without PPAs and assured coal supplies, potential buyers are keeping their offers low and waiting for liquidation to win bargains at discounts (implying haircuts for the banks) that are huge. Among the bidders for the three projects that the PFC was involved in, for example, were Adani Power, Ved­anta, JSW Energy, JM Financial, Bank of America Merrill Lynch, and Edelweiss—big players looking to buy cheap and profit hugely from operations or resale at a later date.

In a last ditch effort, the government through the Rural Electrification Corporation attempted to set up an asset reconstruction company (ARC) under a Power Asset Revival through Warehousing and Rehabilitation (or PARIWARTAN) scheme. Lenders can park the stressed assets with the ARC, making the required provision in their books, and avoid liquidation. The assets would be transferred at book value in return for a “warehousing” receipt. The ARC can hold the assets for 60 months, during which, with the help of a professional operations and maintenance company, it would attempt to revive the units concerned and find a buyer willing to pay a price that does not short-change the banks too much. However, where would the funds to run the ARC come from and how would the banks manage the provisioning when they are getting nothing for those assets till much later? Besides provisioning, the lenders are expected to support the ARC to the tune of 15% of the value of the assets to be transferred. Since some lenders are not willing to financially back the ARC, bringing the idea to fruition is proving difficult. Meanwhile, liquidation day app­roaches.

Thus, if an attempt is made to unravel the debt conundrum in the power sector, it becomes clear that the NPAs are merely a symptom of the crisis afflicting the industry. The crisis itself is due to the fact that liberalisation, which was justified on the grounds that it would accelerate capacity creation and overcome the pre-liberalisation shortages of power resulting from inadequate public capital formation, had rendered the industry unviable. The burden of the crisis is not being mainly borne by the promoters of these projects, but by public banks and the state exchequer. Further, if liquidation takes place, bargain hunters from within the industry would have the last laugh and the money.

 

Having overcome a legacy of ext­reme shortage of supply, India’s power sector is in the midst of a crisis with ramifications of a wholly diff­erent kind. The crisis arises because firms accounting for a significant proportion of power sector assets have defaulted on their debt-servicing commitments, and banks are not able to find ways of rest­r­u­cturing that debt or recouping their money. So the Reserve Bank of India’s (RBI) guidelines require that the assets should be liquida­ted to recover whatever is possible and compensate banks from which these firms had taken loans, and then defa­ulted. But the assessment is that liquidation would yield the banks little, if anything at all.

There are 34 projects that have been ide­n­tified as stressed, accounting for 24,405 MW of commissioned capacity and another 15,725 MW of capacity that is still under construction. The total outstanding debt in these projects is `1.74 lakh crore. The projects are stressed either because the loans concerned have been declared as non-performing assets (NPAs) or are identified as being potential NPAs. Gross NPAs in the power sector were, at the end of June 2017, placed at `37,941 crore, of which as much as `34,244 crore was in generation. But the magnitude of NPAs is set to rise in the coming weeks and months.

Banks are not keen on going in for liquidation, as they expect the “haircut” or the loss that they would incur to be substantial, because the receipts from the sale of assets would fall short of payments due to them. But as per the February guidelines issued by the RBI, banks had 180 days from the first date of default on payments to settle the matter. That deadline has passed in late August for many firms in the power sector, requiring the banks to move for liquidation of assets.

To avoid that outcome, the concerned banks had approached the RBI to give them some flexibility as they seek to find alternative ways of recouping better value from these assets. But the RBI has turned down the request. Large losses seem unavoidable. That would erode the capital base of the banks and necessitate recapitalisation. The government as ow­ner must take a call and recapitalise the banks with taxpayers’ money. In the final analysis, the losses, much of which are incurred by new privately promoted projects, are being socialised.

This peculiar situation raises a number of questions. To start with, the default by multiple players needs explaining. Given the scale of the problem and the large number of players involved, it cannot be attributed to mismanagement alone. Nor could it be attributed to government inte­r­­vention. Both the electricity sector (esp­eci­ally after the passage of the Electricity Act, 2003) and the coal sector (after the Supreme Court quashed all but four coal allocations, and the government moved to auctioning coal res­ources) have been subject to a major shift in policy to a market-friendly regime. Ele­­ctricity tariffs are subject to some regulation no doubt, but tariffs are based on actual costs to which is added a needed return. So if generating companies are able to justify their cost claims, which in the case of these mainly thermal power projects in­clude a substantial coal cost component, recommended tariffs are set on that basis. The generating companies enter into power purchase agreements (PPAs) with supplying firms that then reach the power to consumers whether through their own or hired distribution facilities.

Liberalised Prices

A core problem app­ears to be that post liberalisation, power capacity has expanded so fast that not all generators are able to tie up PPAs at prices that are reasonable. There has been a growth of short term and spot market sales arrangements with relatively low prices on offer. This trend has been stren­g­thened by the emergence of unutilised capacities. At the end of fin­ancial year 2001–02, before the Electricity Act, 2003 liberalised entry into the sector, installed generation capacity stood at 1,05,046 MW. That figure rose to 1,32,329 MW at the end of March 2007, 1,99,877 MW at the end of March 2012 and to a remarkable high of 3,29,298 MW in March 2017. Clearly, expecting to gain from the opening up of a sector characterised by shortage, private investors had rushed in without a clear assessment of market demand at the higher, liberalised prices. The Ministry of Power claims that despite this growth of capacity, there is no surplus in times of peak power demand. But, there clearly is substantial surplus during off-peak hours, since the plant load factor of thermal power plants has fallen from 79% in 2006–07 to 60% in 2016–17. Part of the problem seems to be that the depressing effects of higher (post-liberalisation) prices on demand had not been factored in when demand projections were made.

Moreover, some firms had either not provided for the possibility that they may not have assured access to reasonably priced coal or had presumed that they would be able to cushion the effects of higher-priced coal by hiking prices fixed in PPAs. This did work for some, but not for all. Many of the firms that are defaulting have not been able to enter into PPAs, and are dependent on short-term markets. Distribution companies too have woken up to the fact that they can access cheaper power outside of PPAs.

One indicator of the state of play is that, wanting certainty with regard to coal supply, firms faced with a competitive power market have been willing to negotiate PPAs in which power is priced, based on zero coal cost. The government adopted a special reverse auction process for those bidding for captive coal blocks from the power sector, where the prices are regulated through PPAs or price fixing authorities. The winner was the bidder who was willing to set coal price at its lowest for calculation of power tariffs to be included in the PPA. Bidders had to compete to offer discounts relative to the price of equivalent grade coal charged by Coal India Limited (CIL), which was set as the ceiling price. If no coal block auction had been held, CIL’s price would define the coal cost taken into account when pricing electricity, irrespective of the actual cost of extracting coal from the captive coal block that supports electricity production. Under the reverse auction scheme, the bidder quotes a price equal to or below the CIL benchmark, which would be taken into consideration when pricing electricity produced with coal extracted from the block being auctioned. Besides this, the bidder must offer to pay the government of the state in which the block is located a fee quoted per tonne for the coal extracted. The reserve or minimum fee to be paid to the state government was set at `100 per tonne. What is surprising is that in the case of many blocks, bidders have agreed to set the fuel cost in the power tariff calculation at zero. That amounts to absorbing the costs of extraction by reducing the margins they receive. In addition, these bidders have, in an associated bid, offered to pay the state government much more than the `100 per tonne reserve price. Competition was clearly depressing the margins garnered by the generators.

Distressed Loans

Those without access to captive blocks have not been free of problems either, because the price of coal from other sources such as imports, for example, has been rising. Trapped between depressed power tariffs and falling demand, on the one hand, and rising coal prices or inadequately compensated coal costs, on the other, the industry has found its profits eroded, leading to the failure to meet debt service commitments. The problem is that with banks having financed the expansion of capacity in this sector to a substantial extent, they are taking the hit. Promoters are walking away, leaving the banks to fend for themselves.

However, unable to find a buyer whose offer pleases all lenders, the banks have not been able to meet the government’s deadline for resolution, and are now required to take the assets to liquidation. Thus, the Power Finance Corporation (PFC) was looking to recover the distressed loans by selling three power units (GMR Raikheda with 1,370 MW, KSK Mahanadi with 2,400 MW, and Avantha-owned Jhabua Power with 600 MW) it had partly lent to. But, other lenders were not willing to accept any of the available bids since they were too low. With few takers for these assets, especially those in firms without PPAs and assured coal supplies, potential buyers are keeping their offers low and waiting for liquidation to win bargains at discounts (implying haircuts for the banks) that are huge. Among the bidders for the three projects that the PFC was involved in, for example, were Adani Power, Ved­anta, JSW Energy, JM Financial, Bank of America Merrill Lynch, and Edelweiss—big players looking to buy cheap and profit hugely from operations or resale at a later date.

In a last ditch effort, the government through the Rural Electrification Corporation attempted to set up an asset reconstruction company (ARC) under a Power Asset Revival through Warehousing and Rehabilitation (or PARIWARTAN) scheme. Lenders can park the stressed assets with the ARC, making the required provision in their books, and avoid liquidation. The assets would be transferred at book value in return for a “warehousing” receipt. The ARC can hold the assets for 60 months, during which, with the help of a professional operations and maintenance company, it would attempt to revive the units concerned and find a buyer willing to pay a price that does not short-change the banks too much. However, where would the funds to run the ARC come from and how would the banks manage the provisioning when they are getting nothing for those assets till much later? Besides provisioning, the lenders are expected to support the ARC to the tune of 15% of the value of the assets to be transferred. Since some lenders are not willing to financially back the ARC, bringing the idea to fruition is proving difficult. Meanwhile, liquidation day app­roaches.

Thus, if an attempt is made to unravel the debt conundrum in the power sector, it becomes clear that the NPAs are merely a symptom of the crisis afflicting the industry. The crisis itself is due to the fact that liberalisation, which was justified on the grounds that it would accelerate capacity creation and overcome the pre-liberalisation shortages of power resulting from inadequate public capital formation, had rendered the industry unviable. The burden of the crisis is not being mainly borne by the promoters of these projects, but by public banks and the state exchequer. Further, if liquidation takes place, bargain hunters from within the industry would have the last laugh and the money.

Updated On : 21st Sep, 2018

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