Importing Coal Is Not That Simple Or Cheap; And That’s Just One Part Of The Problem
India could do with a good monsoon to shore up hydroelectricity generation, besides aiming for higher renewable energy numbers in FY23.
The Power Ministry has allowed independent power producers that use imported coal to pass on the higher cost to buyers, till December. The higher cost of imported coal is on account of a spike in global energy prices. Customers who entered into fixed cost power-purchase agreements have to pay extra.
By doing this, the Ministry has granted a fresh lease of life to the idling 18,000 MW imported coal-based capacities. The aim of the Ministry’s decision is to increase the buffer stock which has depleted by roughly 40 million tonnes (MT) due to an identical decline in imports in 2021-22 (FY22).
With domestic coal supply and generation from renewable sources (excluding large hydro) growing at a record pace; a little import support can keep the power supply scenario steady.
As directed by the government, central sector genco NTPC is back into the import market after nearly two years. They imported 1 MT of fuel in FY21. For FY23, the company so far issued firm orders and tenders for nearly 7 MT (4 per cent of its annual consumption), for blending purposes.
State utilities of highly industrialised Maharashtra, Gujarat and Tamil Nadu announced plans to import another 10 MT of coal. Every 5 MT fuel supports nearly 1000 MW of power generation.
However, this might not mean the end of India’s power woes. Common sense suggests imports may not be that easy to materialise. A good rain and sustained production growth by the renewables segment might be needed to save India's day.
First and foremost, the power sector was shortsighted to have dumped imported fuel as soon as the global prices started firming up in mid-2021.
They are gearing up to enter the market when prices are on fire. The benchmark Newcastle coal futures is now ruling at around $330 a tonne, up from 137 a tonne on 1 July 2021. A staggered purchase during the period would have kept the total costs down.
The import prices started moving wildly from January when Indonesia imposed an export ban. The Ukraine crisis, the embargo on Russian coal by Europe, the flood in Australia and stock building exercise by China, in the face of stagnant domestic supply, did the rest.
Sea freight was already at a record high. The recent Covid restrictions in China can take it to newer heights. Things can go haywire in the coal market if Indonesia declares another export ban, which is anticipated for some time.
The delayed entry will therefore have a shock impact on the potential buyer. According to media reports, Andhra Pradesh recently cancelled two separate tenders for importing a total of 1.25 MT fuel, citing high prices. India’s largest coal trader Adani was the lowest bidder.
India met approximately 30 per cent of its 853 MT thermal coal demand through imports in the pre-Covid year of FY20. The gross majority of the imported fuel is used by industry (other than power). While segregated data is not available, the peak import dependence of the power sector shouldn’t be more than 10 per cent.
From a macroeconomic perspective, therefore, high import prices shouldn’t impact the average price of electricity at the consumer end significantly. Such logic applies to both the market economy and command economy. The Indian power sector doesn’t follow either.
Repeated policy change at the centre and states led to varying levels of regulation and price structure both at the power sales (PPA) and fuel procurement end. The competitive politics in states to give cheap or free power, ignoring financial discipline or contractual obligations, made the situation even more complex.
Imported-fuel-based plants were set up in the coastal areas as per a 2006 policy to ensure energy security of states like Punjab, Rajasthan, Tamil Nadu etc., which are 1000-1500 km away from India’s coal mining zone.
Today, the import-based IL&FS Tamil Nadu Power Company is idling and the state Chief Minister, M K Stalin is requesting an additional allotment of rakes to procure more fuel from Odisha. Complying with the demand would mean an increase in the average turnaround time of rakes and a delay in coal supply to power stations located closer to the mine.
During the first wave of Covid in 2020, Punjab unilaterally suspended PPAs with multiple independent power producers (IPP), citing high costs.
In October 2021, the state further issued notices to public sector Damodar Valley-run units in Durgapur (200MW), Raghunathpur (300MW), Bokaro (200MW) for scrapping PPAs. All three plants are located on the pit-head with an abundant supply of fuel. Punjab is now complaining about the fuel crisis at its state utility run plants.
The extra emphasis on running state government-owned plants, which are on average old and inefficient (burns more fuel to produce the same amount of electricity), is a countrywide phenomenon. The reason lies in the poor fiscal health of state distribution utilities (Discom).
According to India Ratings, Punjab has been suffering from low growth, high fiscal deficit and very high debt-GSDP ratio. This month the newly elected state government offered 300 units of free electricity to households, which practically eliminates the cost of running one air-conditioner apart from all other regular electrical gadgets.
Considering the stress on finances, market procurement of electricity is difficult. Coal dues cannot be left outstanding for an indefinite period. But state government-run gencos can share part of the cash deficit of the Discoms.
The question is simple: Those who cannot pay for power and coal under normal circumstances, can they pay for costlier imported fuel? Even rich states owe thousands of crores to gencos and coal companies. Should we take their tall import promises at face value?
The answer is anybody’s guess. India should better pray for good rains to shore up hydroelectricity generation this monsoon. The generation of large hydel projects (including imports from Bhutan) was stagnant in FY22. Their share in total generation was down from 11.5 per cent in FY21 to 10.6 per cent.
Renewables (solar, wind, small hydro, biomass etc.) played the saviour in FY22, by generating more electricity than large hydro. Solar grew by 20 per cent, wind by 14 per cent. Overall, RE generation contributed 11.3 per cent of the total. Let's hope that the growth momentum will continue in FY23, thereby replacing the import needs.
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