Coal-based power generation continues to be a mainstay in India, accounting for around 70 per cent of the country’s total generation. However, in the last couple of years, the plant load factor (PLF) of coal-based plants has been declining. Capacity addition in the segment has also become subdued. This is, in part, attributable to falling renewable energy tariffs, the must-run status of renwable energy plants leading to backing down of coal-based plants, and fuel availability issues. With the growing integration of renewables in the grid and the changing energy mix, the role of coal-based generation is evolving in the Indian power sector.
Size and growth
India’s total installed capacity across all sources of generation stood at 382.15 GW as of March 2021. Coal- and lignite-based power accounted for the highest share (55 per cent) at nearly 209.29 GW, followed by renewables at 94.43 GW (24.71 per cent) hydropower at 46.21 GW (12.09 per cent).
The installed coal-based capacity has grown from 165 GW in March 2015 to 209 GW in March 2021, recording a compound annual growth rate of 4.02 per cent. Some of the power plants commissioned during 2020-21 include the 660 MW Unit 2 of the Nabinagar Super Thermal Power Project, the 660 MW Tanda thermal power station (TPS), and the 270 MW Unit 3 of Bhadradri TPS. The capacity addition of coal-based plants has declined in recent years – the net capacity addition stood at 3,950 MW in 2020-21 and 6,765 MW in 2019-20, vis-à-vis a peak of about 18.5 GW in 2011-12. The major players in the coal-based segment are already on the path of diversification. NTPC Limited has announced its decision to stop land acquisition for greenfield thermal projects, which essentially implies that no new coal-based projects will be taken up in the future (except those already under construction or planned).
Coal-based power generation stood at 951 BUs during 2020-21, marking a decline of around 1 per cent over the previous year. Meanwhile, the PLF of coal-based plants stood at 55 per cent, almost equivalent to the previous year (56 per cent) but a significant decline from the high of 73 per cent recorded in 2011-12. The declining PLF is attributed to a host of reasons, including declining renewable energy tariffs and the must-run status of renewable energy plants leading to backing down of coal-based power plants.
Recent key developments
Guidelines for exiting PPAs: In March 2021, the Ministry of Power (MoP) issued guidelines enabling discoms to either continue with or exit from power purchase agreements (PPA) after the PPA’s term is completed, that is, after 25 years or the period specified in the PPA. As per the guidelines, the first right to take power from central generating stations (CGSs) beyond the term of the PPA will continue to be with the states/discoms. Willing states/discoms may relinquish their share from a CGS after the expiry of the terms of their PPAs. State discoms that have long-term PPAs with a CGS for a capacity allocated by the central government can opt to relinquish the entire allocated power post the completion of the terms of the PPAs by giving notice six months in advance, if the PPAs have expired or are due to expire in the near future. Any CGS whose share of power has been relinquished will be free to sell such power through various avenues such as tie-ups with other buyers through the long-, medium- or short-term routes; the competitive bidding route; power exchanges; or reallocation of the power to willing buyers at regulated tariffs.
Update on emission norms: In April 2021, the Ministry of Environment, Forest and Climate Change (MoEFCC) extended the timelines for complying with the emission norms for coal-based TPPs by one to three years. The amended rules allow TPPs within 10 km of the National Capital Region and those in cities with a population greater than 1 million to comply with the new emission norms by December 31, 2022; and TPPs in non-attainment cities and those within 10 km of critically polluted areas to do so by December 31, 2023. TPPs in other areas have to comply with the norms by December 31, 2024. TPPs declared to retire before December 31, 2025 are not required to meet the specified norms in case such plants submit an undertaking to the Central Pollution Control Board and the Central Electricity Authority for exemption on ground of retirement. Such plants will be charged environment compensation at the rate of Re 0.20 per unit of electricity generated if they continue to operate beyond the date specified in the undertaking. In addition to the extension of timelines, the new rules will levy an environment penalty on non-retiring TPPs for non-compliant operation beyond the specified timeline. The maximum fine for not complying with the norms by the deadline is 20 paise per unit for plants in Category A, 15 paise per unit for plants in Category B, and 10 paise per unit for plants in Category C.
Revised LPS rules: In March 2021, the MoP issued the Electricity Late Payment Surcharge (LPS) Rules, 2021. LPS charges are payable by a distribution company to a generating company or an electricity trader for power procured from the latter, or by a user of a transmission system to a transmission licensee on account of a delay in the payment of monthly charges. With the new rules, the central government has lowered the LPS levied by power and transmission developers on discoms by linking it to the State Bank of India’s lending rate. The rules have been notified in view of the prevailing low rates of interest so that the LPS rates accurately reflect the current cost of borrowing. In the current scenario, this would imply reducing the LPS to 12-15 per cent per annum, according to analysts.
Biomass mission: In May 2021, the MoP decided to set up a National Mission on Use of Biomass in Coal-based TPPs to help solve the problem of air pollution due to the burning of farm stubble as well as to reduce the carbon footprint of TPPs. The main objectives of the mission are to increase the level of co-firing from the current 5 per cent in order to have a larger share of carbon-neutral power generation from TPPs; to take up research and development activities in boiler design to handle the higher amount of silica and alkalis in the biomass pellets; to facilitate the removal of constraints in the supply chain of biomass pellets and agro-residue and their transport to the TPPs; and to consider regulatory issues in biomass co-firing. The proposed mission is likely to be implemented for a period of five years, and the modalities of operation, as well as the structure of the mission, are likely to be finalised soon.
Fly ash management norms: In April 2021, the MoEFCC issued draft notifications for the utilisation of fly ash and bottom ash at TPPs. The notification stipulates that power plants should supply fly ash to nearby construction units free of cost, if they have been unable to dispose of the ash through other means. TPPs shall also issue notices to nearby user industries to inform them of the availability of surplus fly ash. Construction units within a 300 km radius of a TPP will be responsible for the utilisation of that TPP’s fly ash if they do not have pre-existing tie-ups. The notification also proposes a penalty of Rs 1,500 per tonne on fly ash using industries for non-compliance and a penalty of Rs 1,000 per tonne on power generators if the residue is not disposed of in time. Moreover, the notification details the procedure for supply of ash and ash-based products, as well as for enforcement, monitoring, auditing and reporting to ensure compliance with the provisions.
The Association of Power Producers, in a letter to the MoEFCC, has sought a relaxation in the implementation of the fly ash utilisation norms. APP has requested that the requirement of 100 per cent fly ash utilisation be waived for 2020-21 and 2021-22, and no financial penalties be imposed on thermal power plants during this period. The APP has stated that the demand for fly ash from cement plants, brick manufacturing units and road construction agencies came to a complete stop during the lockdown period, starting March 2020. While demand was showing some signs of recovery in the intervening period, it crashed again during the second wave of the pandemic and the lockdown/curfew imposed across the country.
Issues and challenges
The coal-based segment also continues to face a number of challenges. There are 30-40 GW of stressed assets in the system, and their resolution remains slow despite efforts by lenders and the government. Further, the pandemic has made it difficult for resolved stressed assets to generate adequate cash flows.
Another challenge that coal-based units have to prepare for is flexible operation. Coal-based plants will need to transition their operation regimes from baseload to cyclic as more renewables are integrated into the grid. This implies that plant components will not only deteriorate at a faster rate, but there will also be higher operations and maintenance (O&M) expenses due to the reduced life of components, additional costs owing to an increase in the heat rate and in auxiliary power consumption, and an increase in oil consumption on account of frequent start/stops. Further challenges include managing the performance of old and vintage units, and tighter O&M regimes, especially in the post-Covid business environment.
The role of coal-based generation is evolving in the Indian power sector. While these plants were once the main source of stable baseload power to meet the country’s electricity demand, they are now expected to play a supportive role in order to balance the intermittent generation by renewable energy sources. However, due to the growing integration of renewables, the PLFs of coal-based plants have fallen to technical minimum levels and are expected to decline further. The gencos will thus need to carry out necessary modifications to operate at low PLFs. Since TPPs will be used as balancing resources, gencos will have to invest heavily in flexibilisation. Another important aspect will be digitalisation. In terms of the operating strategy, developers need to decide which units to operate and which ones to ramp down/up. Asset management digital solutions will be key. Various complex decisions can be taken based on the data generated from a plant’s operational parameters, as well as daily demand patterns.
Going forward, with a number of coal-based power plants retiring and a limited number of new-build projects expected, the segment is expected to become more technology-driven in the next few years. As an affordable generation source, coal-based power is expected to play an increasingly supportive and balancing role as demand picks up.