Coal-based capacity is the largest contributor to power generation in India with a share of around 70 per cent in 2022-23 (till January 2023). The drawback of the higher share of coal-based power generation capacity is the emission of pollutants such as sulphur oxide (SOx), nitrogen oxide (NOx) and particulate matter (PM). In order to control the levels of these emissions, the Ministry of Environment, Forest and Climate Change (MoEFCC) notified emission norms for thermal power plants (TPPs) in December 2015. In line with this, gencos have been chalking out a number of strategies to ensure that their units comply with the new norms. They are deploying various emission control systems including flue gas desulphurisation (FGD), selective catalytic reduction (SCR), selective non-catalytic reduction (SNCR) and electrostatic precipitators (ESPs). However, the overall progress in complying with these norms has been slow so far.
Emission norms
The MoEFCC notified the revised emission norms for SOx, NOx and PM for TPPs in December 2015, mandating TPPs to install emission control systems by December 2017. Owing to the financial and implementation challenges as well as the sheer volume of work, the deadline for meeting these norms has been extended many times. Notably, in April 2021, the MoEFCC issued a location-based staggered deadline up to December 2024 for compliance with the emission norms. Subsequently, 600 coal-based units were divided into three categories – 67 coal-based units under Category A (plants within a 10 km radius of the NCR or cities that have a million-plus population) with a compliance deadline of December 31, 2022; 72 under Category B (plants within a 10 km radius of critically polluted areas or non-attainment cities) with a compliance deadline of December 31, 2023; and 461 under Category C (which includes the remaining plants) with the deadline of December 31, 2024. The ministry also introduced an environment penalty on non-retiring TPPs for non-compliance beyond the timeline. The maximum fine for defaulting plants under Category A 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.
Later, in September 2022, the MoEFCC extended the deadlines for TPPs by two years to cut sulphur emissions. For coal-based units that fall under Category A, the deadline for emission norm compliance has been extended till December 31, 2024; for TPP units under Category B, the deadline has been pushed to December 31, 2025; and for all other TPPs falling under Category C, the deadline has been extended till December 31, 2026. Further, the TPPs retiring before December 31, 2027 will not be required to meet the SO2 emission norms in case such plants submit an undertaking to the Central Pollution Control Board (CPCB) and the Central Electricity Authority (CEA) for exemption on grounds of retirement. Also, TPPs declared to retire before December 31, 2022 (Category A) or December 31, 2025 (Categories B and C) will not be required to meet the specified norms other than SO2 emissions, in case such plants submit an undertaking to the CPCB and the CEA for exemption on grounds of retirement. Besides this, the environment compensation to be levied on non-compliant power plants for operation beyond the timeline has been revised to Re 0.20 per unit, Re 0.30 per unit and Re 0.40 per unit for 0-180 days, 181-365 days, and 366 days and beyond respectively.
Progress report
SOx emissions: FGD systems have been commissioned and 22 units with a total capacity of 9,280 MW are operational, as of February 2023. Meanwhile, bids have been awarded for 219 units aggregating 100,430 MW in capacity. Technology-wise, wet FGD based on limestone is one of the most frequently used technology for reducing SOx, with about 90 per cent SOx removal efficiency. A large number of TPPs, including the 1,320 MW Solapur super TPP, the 1,320 MW Tanda Stage II project, and the 2,000 MW Simhadri Super TPP Stages I and II projects, are installing wet FGD technology to control SOx emissions. Dry sorbent injection (DSI) is another post-combustion SOx removal technique that is preferred for plants with unit size in the range of 60-250 MW. Notably, NTPC has opted for DSI at its 4×210 MW Dadri power plant. DSI system erection work is at advanced stages in two units of NTPC’s Tanda Stage I (4×110 MW).
Studies done by ICRA Limited demonstrate that the installation of FGDs in TPPs entails an investment of Rs 5 million-Rs 7 million per MW. There has been an increase in the cost of FGD systems as per developers due to unprecedented rise in commodity prices such as steel, cement, nickel, aluminium and copper. Moreover, there are additional energy charges towards reagent consumption. Additionally, generating stations are required to shut down for two to three months for the installation of an FGD system. The additional capex required for FGD along with the higher operations and maintenance cost and higher auxiliary consumption is expected to increase the levellised cost of generation by 24 paise to 28 paise per unit.
NOx emissions: Techniques such as combustion modification processes are being used to reduce NOx outflows to 300-600 mg per Nm3. However, improved control methods, such as SCR and SNCR, are needed to further reduce emission levels by 100-300 mg per Nm3. While SCR and SNCR are established technologies for NOx emissions reduction with respect to low ash coal, they have not yet been cleared for the abrasive and high-ash Indian coal. NTPC is conducting several pilot tests and studies to determine if SCR technology is appropriate for Indian coal. NTPC Limited has awarded NOx combustion modification tenders for over 21.5 GW of capacity, of which combustion modification works have been completed for 13.3 GW capacity, including three Jhajjar units and two Dadri units. The remaining combined capacity of 8.2 GW is at various stages of commissioning for combustion modification works.
PM emissions: The majority of TPPs currently have indigenous ESPs for controlling PM emissions, which have been commercially successful. However, to meet the stricter emission standards, improved ESP systems are needed. The CEA has published a thorough proposal explaining the strategy for the augmentation of ESPs for PM control up to 2024. NTPC has planned for renovation and modernisation (R&M) of ESPs aggregating 15,960 MW capacity, out of which work has been completed for 12,100 MW, and is in progress for the remaining 3,860 MW.
Regulatory updates
The Central Electricity Regulatory Commission (CERC), vide its order dated August 13, 2021, has finalised the mechanism for recovering the cost incurred to comply with the revised emission norms by TPPs. The mechanism is applicable to competitively bid projects under Section 63, and projects wherein power purchase agreements (PPAs) do not provide any pre-specified formula for relief under change in law during the operating period. The recovery of costs will be in the form of supplementary capacity charges and supplementary energy charges. The recovery is assumed to happen over the useful life of the emission control equipment, which is considered as 25 years; and therefore, the returns for developers that have plants with a balance useful life of less than 25 years could be adversely impacted. The CERC has allowed developers to recover the increased cost on account of an increase in auxiliary consumption as well as the landed cost of reagent at the generating station and specific reagent consumption.
Notably, a few orders issued by state-level regulators did not approve revised emission norms as a change in law event. However, these orders were later overturned by the Appellate Tribunal for Electricity (APTEL). For instance, the Uttar Pradesh Electricity Regulatory Commission (UPERC) declined to approve the revised emission norms as a change in law event for a private independent po-wer producer. The developer appealed against this order before APTEL, which set aside the order issued by UPERC and noted the notification of revised emission norms as a change in law event. Similarly, the Punjab State Electricity Regulatory Commission had rejected the petitions of two private IPPs pertaining to approval of revised emission norms as a change in law event, which were overturned by APTEL.
Issues and challenges
For power producers, one of the key challenges in the implementation of revised emission control norms is the regulatory uncertainty with regard to full recovery of additional capital and operational expenditure incurred towards emission control equipment. Further, the loss of revenue during downtime, the reluctance of lenders in extending debt funding amid large stressed portfolios as well as ESG considerations and the lack of willingness of promoters to bring in equity add to the challenges. Other challenges include untied PPA capacities or PPAs not extending over the entire useful life of emission control equipment, and possible downgrades in merit order despatch.
Apart from this, TPPs aggregating around 72 GW in capacity (mostly comprising units under 500 MW) face space constraints for installing emission control equipment. Besides this, inadequate availability of raw material (limestone) and issues related to disposal of by-product (gypsum) add to the challenges in operating FGD systems. Import restrictions, inadequate domestic technology and capacity to meet the demand for emission control equipment have led to delays in commissioning of FGD systems.
Conclusion
While emission control equipment is essential to comply with the tightened norms, effective tracking of the operating parameters of power plants is useful for the early discovery of deviations and flaws in power plant performance, thereby minimising harmful emissions and improving operational performance. With more efficient operations and maintenance practices, power plants will generate more electricity while utilising less coal, which will result in minimal production of undesirable emissions.
Compliance with emission norms has been sluggish so far and as such, rigorous adherence to the implementation schedule is required, especially in light of India’s commitment to net zero emissions. Besides, considering the crucial role played by TPPs in maintaining a stable grid, it is essential to ensure that plants operate in an environmentally safe manner.