Complying with the revised emission norms is one of the key priorities for Indian thermal power producers. The revised emission norms (for particulate matter, sulphur dioxide and oxides of nitrogen) were notified by the Ministry of Environment, Forest and Climate Change (MoEFCC) in December 2015 with a deadline of December 2017, which was subsequently extended till 2022.
However, thermal power producers have been facing numerous challenges in meeting the deadline mainly owing to supply chain issues due to the Covid-19 pandemic, equipment import restrictions, minimum local component condition under the Aatmanirbhar Bharat Abhiyaan, liquidity crunch and credit refusals by lenders. Taking cognisance of developers’ concerns, the MoEFCC, in April 2021, extended the timelines for complying with the emission norms for coal-based thermal power plants (TPPs) by one to three years. The new rules have also introduced a penalty mechanism for non-compliant operations by power plants beyond the specified timeline.
Revised timelines
As per the Environment (Protection) Amendment Rules, 2021 notified recently, power stations will be divided into three categories – A, B and C. Category A TPPs, comprising plants within a 10 km radius of the NCR or cities that have a million-plus population, are required to meet the emission norms by December 2022. Category B plants are those located within a 10 km radius of critically polluted areas or non-attainment cities, and have to meet the norms by 2023. Meanwhile, Category C is made up of the rest of the plants, which have been given an extension till 2024. A task force will be constituted by the Central Pollution Control Board (CPCB) to categorise TPPs in three categories on the basis of their location. Apart from this, TPPs declared to retire before December 31, 2025 are not required to meet the specified norms. Such plants need to submit an undertaking to the CPCB and the Central Electricity Authority (CEA) for exemption on the ground of retirement. Such plants will be levied environment compensation at the rate of 20 paise per unit of electricity generated in case their operation is continued beyond the date as specified in the undertaking.
In addition to the extension of timelines, the new rules will levy an environment penalty on non-retiring TPPs for operation beyond the timeline. The maximum fine for plants in Category A that do not comply with the norms by the deadline is 20 paise per unit, whereas it is 15 paise per unit for plants in Category B and 10 paise per unit for plants in Category C.
According to the Centre for Science and Environment (CSE), about 28 per cent of the total capacity (58 GW) falls under Category A, which has to meet the norms by 2022. Another 28 per cent falls under Category B, which has to meet the norms by 2023. Meanwhile, a major capacity of 44 per cent (89.5 GW across 82 plants) falls under Category C, which has been given an extended deadline till 2024-25. With regard to the penalty, as per the CSE, in terms of per MW cost, the maximum penalty for any plant in Category A comes out to be Rs 1.1 million per MW. Meanwhile, for Category C plants, which are already given extended deadlines, the penalty would be about Rs 0.5 million per MW.
Current status
According to the CEA, as of February 2021, FGD systems have been commissioned and are operational for 2,160 MW of capacity – four units of NTPC’s Dadri project (4×210 MW) and two units at CLP India’s Jhajjar project (2×660 MW). Meanwhile, bids have been awarded for 155 units aggregating 68,660 MW in capacity. This represents 40.5 per cent of the total planned capacity. Sector-wise, bids have been awarded for 114 units in the central sector, 29 units in the private sector and 12 units in the state sector. Apart from this, a notice inviting tender (NIT) has been issued for 131,327 MW.
Regarding NOx emissions from TPPs, an important development took place last year when the Supreme Court allowed power stations commissioned between December 2003 and 2016 to emit 450 mg per Nm3 of NOx as against a cap of 300 mg per Nm3 earlier. The Ministry of Power had proposed this revision because meeting the earlier limit was not possible for TPPs operating at partial load. At present, various NOx control technologies are available such as selective catalytic reduction (SCR) and selective non-catalytic reduction (SCNR) systems, and over fire air systems and low NOx burners. With the change in NOx limits, TPPs commissioned between 2003 and 2016 will not be required to implement advanced de-NOx technologies such as SCR or SNCR as an NOx emission level of 450 mg per Nm3 can be achieved by combustion modification.
For the control of PM emissions, most of the power plants have already installed electrostatic precipitators (ESPs) since Indian coal has a high ash content; however, upgraded systems could be required for the existing projects. In addition, the environment ministry’s decision to do away with coal washing makes it more important for TPPs to invest in efficient PM control technologies.
Initiatives by gencos
NTPC, the country’s largest power generating company, has taken the lead in the implementation of FGD systems as well as NOx control technologies. NTPC has commissioned a wet FGD system in Stage V of the Vindhyachal super TPP (STPP). Further, FGD systems based on dry sorbent injection (DSI) systems have been commissioned at four units of its Dadri project and are at an advanced stage of erection in two units of Tanda (Stage I). Overall, the total thermal capacity for FGD implementation by NTPC exceeds 62 GW. Of this, FGD tenders for around 59 GW worth Rs 290 billion are under implementation, while FGD systems for around 5 GW of capacity are under tendering. During 2019-20, NTPC awarded contracts for wet limestone-based FGD systems for a capacity aggregating 25,810 MW.
In the case of Gujarat State Electricity Corporation Limited (GSECL), 3,140 MW of coal/lignite-based capacity is compliant with the particulate matter norms and implementation is under way for the remaining 2,020 MW. All units of GSECL meet the NOx norms except the 800 MW Unit 8 of the Wanakbori TPP. In addition, GSECL has decided to address NOx issues after reviewing the results of NTPC’s pilot projects. Further, a detailed project report is under preparation for the installation of FGD systems at 14 old units aggregating 2,785 MW. Bids have been invited for another 1,000 MW and an order has been placed for the installation of an FGD system at Unit 8 of the Wanakbori TPP. Meanwhile, Haryana Power Generation Corporation Limited (HPGCL) is in discussion with equipment manufacturers for NOx control through modification in the combustion chamber of the boiler. HPGCL has already completed the work of rectifying the ESPs in almost all its thermal units.
In addition, the utility is meeting the norms of specific water consumption and mercury. The company issued NITs during April-June 2019 for the installation of FGD at HPGCL’s power plant, where the company went for an international bidding process, in which all participants were from China. Now, in order to comply with the Atmanirbhar Bharat Abhiyaan, the ongoing bidding process has been scrapped and the process has been reinitiated through domestic bidding. However, this has resulted in time delays.
Another state genco, West Bengal State Electricity Distribution Company Limited is also deploying FGD systems at its power plants. The installation of FGD systems at its Bakreshwar TPP, Santaldih TPP and Sagardighi TPP is at the tendering stage, while the utility has installed dry solvent injection systems at the Kolaghat TPP and Bandel TPP.
Challenges and the way forward
The market for emission control equipment, especially FGD systems, is evolving in India and there is limited availability of vendors. The overbooking of suppliers has resulted in an increase in manufacturing time for FGD systems equipment. There is dependency on imports and certain import restrictions have also been imposed. Apart from this, there are a number of financial constraints for developers. Considering an average price of Rs 5.5 million per MW, the capex requirement for installing an FGD (for 170 GW of existing thermal capacity, 10 GW of commissioned capacity after the preparation of the phasing plan, and 58 GW of under-construction capacity) is estimated at Rs 131 trillion.
Further, the uncertainty regarding cost recovery of emission control equipment is a key challenge for developers. To overcome this, it is crucial for regulators to formulate a transparent and well-defined compensation mechanism to ensure that costs are duly recovered through tariffs. A mechanism to help recover the costs incurred to comply with the revised emission norms under the change in law mechanism is likely to be finalised soon by the central regulator. This would ease lenders’ concerns who have thus far been reluctant to lend to the thermal power segment and facilitate credit supply to developers.
Going forward, the industry is likely to see an uptake in emission control systems as issues are likely to get resolved through policy and regulatory reforms.