One of the top priorities for thermal power plant (TPP) developers is to comply with the tightened emission norms notified by the Ministry of Environment, Forest and Climate Change (MoEFCC) in December 2015. The overall progress in complying with these norms has been slow so far and many power plants are yet to firm up plans for upgrading their emission control infrastructure. Bringing much relief to the developers, in April 2021, the MoEFCC notified graded implementation of emission control measures and an extension of one to three years has been provided in the implementation timeline. The government has also put in place a mechanism to penalise non-compliant TPPs by prescribing a graded penalty for each category of TPP.
Progress so far
According to the Central Electricity Authority’s (CEA) data, as of February 2021, flue gas desulphurisation (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 Haryana project (2×660 MW). Meanwhile, bids have been awarded for 155 units aggregating 68,660 MW of 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, representing 76.5 per cent, 21.8 per cent and 7.2 per cent of the total planned capacity respectively. Apart from this, a notice inviting tender has been issued for 131,327 MW.
NTPC, the country’s largest power generating company, has taken the lead in the implementation of FGD systems as well as nitrogen oxide (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 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 selected 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.
NTPC currently controls the production of NOx in its coal-fired plants by adopting the best combustion practices (primarily through excess air and combustion temperature optimisation). Under NTPC’s de-NOx action plan, combustion modification has already been implemented at five units aggregating 2,480 MW – two units at Dadri, two units at Jhajjar and one unit of the Vindhyachal STPP. For further reducing NOx emission levels combustion modification is at various stages of execution for 44 GW of capacity. For low-NOx combustion systems, contracts have been awarded for 18 GW of capacity.
Under the guidance of the Ministry of Power (MoP), NTPC set out to test selective catalytic reduction (SCR)/selective non-catalytic reduction (SNCR) technologies at 11 of its locations on a pilot basis to assess the viability of these technologies for Indian coal. It has been found in trials that NOx reduction in the range of 450-750 mg per Nm3 is achievable from combustion modification. For SNCR technology, NOx reduction is in the range of 20-30 per cent only. Further, it was found that while NOx reduction of around 80 per cent is achievable, it is not consistent due to part-load operation of power plants.
The project will help the power plants comply with the government’s initiative of reducing emission levels for improvement in the overall quality of air. GE Power India Limited will set up combustion modification technology for all the steam generators in Units 8 and 9 of Barauni Stage II, to meet the NOX emission limit of 450 mg per NM3 and comply with the government’s environmental requirements. Supporting the Aatmanirbhar Bharat initiative of the government, all the major components for the project will be manufactured in India.
In a key development, in April 2021, the MoEFCC extended the timelines for complying with the emission norms for coal-based TPPs by one to three years. As per the Environment (Protection) Amendment Rules, 2021, power stations will be divided into three categories. 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 TPPs, or those within a 10 km radius of critically polluted areas or non-attainment cities, have to meet the norms by 2023. Category C is made up of all other plants, that have been given an extension till 2024. A task force will be constituted by the Central Pollution Control Board to categorise TPPs.
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 timelines. The maximum fine 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.
According to the Centre for Science and Environment (CSE), about 28 per cent of the total capacity 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 large capacity – 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 have already been given extended deadlines, the penalty would be only Rs 0.5 million per 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 December 2016 to emit 450 mg per Nm3 of NOx, as against a cap of 300 mg per Nm3 earlier. The MoP 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 SCR and SCNR systems, 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 through combustion modification.
Challenges and the way forward
From the developers’ perspective, one of the major issues in the implementation of deadlines is the uncertainty regarding the cost recovery of FGD equipment. There is a lack of clarity regarding the tariff implications of the capital expenditure incurred towards the installation of emission control equipment and towards subsequent operational expenditure. Following the advisory issued by the MoP regarding the cost pass-through of capital expenditure towards emission control equipment, the Central Electricity Regulatory Commission has issued orders approving the capital cost of FGD systems on a provisional basis for power generating companies. However, similar regulations from the state electricity regulatory commissions are also required in a timely manner. Apart from this, there is no clarity on the mechanism for the recovery of FGD-related costs for projects that sell power through short-term power purchase agreements (PPAs). As per industry estimates, an operational private thermal capacity of around 20 GW does not yet have long-term PPAs.
Another challenge in the implementation of emission control equipment is the lack of adequate funds. Generating companies are expected to rely on debt funding from banks and financial institutions to meet a substantial part of the capital cost towards the installation of emission control systems. However, lenders have been apprehensive of extending credit to generating companies, especially private independent power producers (IPPs), due to the lack of regulatory certainty with respect to the tariff implications of this capex. Thus, securing debt financing could be a challenge for projects that do not have long-term PPAs, for projects that have unviable tariffs under their PPAs, or those that have a remaining PPA tenor of less than 12 years.
Apart from this, the implementation of emission control equipment has been hampered owing to the supply chain disruptions caused by the Covid-19 pandemic. Due to the limited domestic emission control equipment manufacturing capacity, many TPPs were forced to scout for overseas vendors through international competitive bidding tenders. The onset of the global pandemic last year severely impacted the global supply chain, resulting in many bidders expressing their inability to meet timelines as committed, and many tenders being cancelled.
To conclude, the extension of the timeline provided by the MoEFCC has come as a relief for thermal IPPs amid the sluggish progress in compliance with the revised emission norms. However, it is desired that there is no further slippage in the implementation timelines, and penalty is strictly imposed for non-compliance. Besides, it is essential to expedite a transparent and well-defined compensation mechanism, which will ensure the recovery of FGD implementation costs through tariffs. Overall, the creation of a time-bound approval process by both the central and state regulators for additional tariffs under change in law remains important in order for TPPs to secure funding and complete their installations.