Besides, other factors are now in play that demand more flexibility in pricing norms. What happens, for instance, if a discom wants to include more renewable energy
in its portfolio? Or if captive generation through rooftops or other non-conventional sources reduces demand? Should the discom remain contractually bound to buy coal-based power under a PPA it signed years ago?
Many of these issues were visible in April 2020, the first full month of the nationwide lockdown. Expectedly, electricity demand across industrial, commercial and office consumers fell substantially. Plant Load Factor (PLF), which indicates a plant’s capacity utilisation, was a woeful 42.4 per cent for 56 per cent of the country’s generation capacity that is based on coal and lignite.
It is not as though PLFs were great pre-lockdown. In fact, the annual average PLF of these units has been below 70 per cent since 2011-12. This, the government says, is a combination of rising generation capacity and better efficiencies in power utilisation. However, the annual growth in energy generation from conventional sources peaked in 2014-15 at 8.43 per cent and slowed to 0.26 per cent in 2019-20, an indicator of slowing demand. If the economy, which was decelerating before the pandemic, slips into recession, the reverberations will be felt in the power sector.
Apart from muted growth in power demand, the addition of renewable power, which constitutes 36 per cent of capacity — including hydropower, which operates under a “must-run” status (which means the power plant must supply electricity to the grid under all conditions) — has certainly impacted PLFs of coal-based units.
Rajiv Srivastava, managing director and chief executive officer, India Energy Exchange, an power trading platform, says the power market operates with limited flexibility. “If your cost through the (power) exchange is cheaper than what you pay when you generate power, then you really don’t need to generate it. What has happened in the last two months is a good representation of the manner, in which the financials of the power sector is operating,” he says.
The cost discovered on IEX in May was Rs 2.4-2.6 a unit (kilowatt per hour) at one point, which is much lower than, say, the Rs 3.68 average marginal cost borne by Uttar Pradesh on June 28 for power supply in the state.
In June, IEX launched a real-time market in power where requirements and purchases can be made for the next few hours instead of the day-ahead market. “People will eventually get out of 25-year PPAs and want to exercise a choice of where and whom they will buy from and what sources. We are moving to absolute consumerisation of power and giving in to a way to give choices to everyone,” he predicts.
Srivastava’s views may not find takers both among generators and discoms. A chief executive in a private generation company, which sells renewable and coal-based power under PPAs, says merchant power sales can only fill gaps and cannot be the norm. “It is impossible to reverse tariff-based bidding because it is important for bringing transparency in public perception,” he says on condition of anonymity.
Besides, he argues, conventional power plants take at least seven years to be set up and an assured demand prediction, which only the bidding out of PPAs can ensure. “If power demand grows 5 per cent annually, the energy demand will increase 60 per cent in 10 years and that would require at least doubling of capacity. For such an investment, PPAs and planning are essential,” he adds.
Currently, the all-India installed generation capacity from all sources is little over 370 GW, while demand even at its peak was 184 GW in 2019-20. This means that half the capacity was used when demand was at its highest, suggesting below optimum utilisation primarily because of grid losses, the infirm nature of renewable power and outages at power plants. The era of the PPA regime may have partly outlived its utility and a more flexible regime that gives lowest cost power for a more competitive economy is needed.