Emission Control Solutions

Deployment by TPPs and industry concerns

The thermal power industry is facing severe headwinds as the deadline to install emission control equipment draws nearer. The central government’s latest order banning the import of power equipment from China and mandatory testing of all imported equipment has further constrained the gencos’ ability to install SOx and NOx control systems in a timely manner. As such, the progress on this front was sluggish from the beginning, owing to various regulatory and financial challenges being encountered by thermal power producers, many of which were already under considerable stress.

Power Line takes stock of the current status of deployment of emission control solutions by thermal power plants (TPPs) and industry concerns…

SOx update

As per the Central Electricity Authority (CEA), flue gas desulphurisation (FGD) systems, which aid in SOx emission control are to be deployed by 437 thermal units aggregating nearly 166 GW in a phased manner by 2022. Similarly, electrostatic precipitators (ESPs), which help in controlling particulate matter (PM) emission, are to be installed in 220 units, totalling 63.4 GW by 2022. The deadline for the installation of emission control equipment in captive power plants (CPPs) was June 2020. The compliance status, as of March 2020, is quite poor with only four units totalling 1,740 MW having commissioned FGDs or just 1 per cent of the targeted capacity. However, tenders have been issued for 113.6 GW of capacity and bids have been awarded for nearly 40 GW.

Various industry bodies including the Association of Power Producers (APP) and the Federation of Indian Chambers of Commerce and Industry (FICCI) have written to the Ministry of Power (MoP) detailing the issues and challenges in meeting emission norms and seeking extension of the 2022 deadline by two to three years.

As per APP, as many as 77 per cent of the thermal units for which FGD is planned (corresponding to 51 per cent of the central, 99 per cent of the state and 85 per cent of the private sector units) have not yet awarded contracts. These units are expected to miss their timelines for the installation of FGDs. The APP ascertains that such a high level of default across the central, state and private sector TPPs is not due to neglect by gencos or any lack of effort but due to systemic impediments. Gencos are increasingly facing regulatory issues and financial institutions are wary of additional exposure to the power sector owing to the uncertainty of cash flow due to investments in FGDs. The sector is already under stress as many TPPs are awaiting pending dues from discoms for the period prior to August 2019 (before the implementation of the letter of credit mechanism).

These issues have been compounded by the Covid-19 pandemic as widespread disruptions in the global supply chain and manufacturing has hampered progress on ongoing projects. Further, the MoP has announced a ban on the import of power equipment from China, which houses some of the largest and affordable suppliers of FGD systems, as well as mandatory testing of all imported equipment. Following this development, the Haryana government has reportedly cancelled two FGD contracts awarded to Chinese companies through the international competitive bidding (ICB) route by Haryana Power Generation Corporation Limited. The contract for the DeenBandhuChhotu Ram thermal power station in Yamunanagar was awarded to Beijing SPC Environment Protection Tech Co. and the one for the Rajiv Gandhi TPP in Hisar was awarded to the Shanghai Electric Corporation. Now, Haryana Power Generation Corporation Limited plans to invite fresh tender for FGD, limiting participation to only domestic companies. Similar moves are expected by other states like Maharashtra, Uttar Pradesh, Uttarakhand and Madhya Pradesh as the demand to boycott Chinese equipment is rising by the day.

These developments have also created regulatory uncertainty as the current framework suggests that engineering, procurement and construction tenders for FGDs should be carried out through the ICB mode. Certain developers are now facing an issue whether the contract can still be awarded to the L1 bidder irrespective of the country of origin, or L2 bids may be considered even if the price of the bid is higher. Further, in cases where orders have already been placed (especially with Chinese manufacturers), there is uncertainty whether the contractor will be able to meet the agreed timelines.

NOx update

The NOx norms for TPPs have recently been revised. In July 2020, the Supreme Court allowed relaxation of the NOx norms for TPPs installed between January 1, 2004 and December 31, 2016 from 300 mg per Nm3 to 450 mg per Nm3. The MoP had proposed revising the norms as TPPs were unable to meet the existing limit (of 300 mg per Nm3 and below) at varying load conditions. The Central Pollution Control Board monitored emissions at seven of NTPC’s power plants for a specific period and the results were found to be in line with the MoP’s observations.

As per NTPC’s pilot projects, it has been found that NOx reduction achievable from combustion modification is around 750 mg per Nm3 to 450 mg per Nm3. For selective non-catalytic reduction (SNCR) technology, NOx reduction is in the range of 20-30 per cent only. Further, it was found that while a reduction in the NOx of around 80 per cent is achievable, it is not consistent due to only part load operation of TPPs. As per the de-NOx action plan of NTPC, a combustion modification has already been implemented at five units of 2,480 MW capacity. Combustion modification contracts have been awarded/under execution at 42 units with 18,080 MW capacity. Further, de-NOx contracts for three units totalling 1,000 MW are currently at the tendering stage.

With the change in NOx limits, TPPs commissioned between 2004 and 2006 will not be required to implement advanced de-NOx technologies like selective catalytic reduction (SCR) or SNCR as a NOx emission level of 450 mg per Nm3 could be achieved by combustion modification. The NOx limits for TPPs commissioned after January 1, 2017 at 100 mg per Nm3 and 600 mg per Nm3 are also under the Ministry of Environment, Forest and Climate Change’s (MoEFCC) review.

PM updates

The revised environmental norms require several existing TPPs to upgrade their ESPs to control PM emissions. Even though most of the power plants have already installed ESPs since Indian coal has a high ash content and leads to significant generation of PM, there are concerns over the efficacy and operational performance issues, which means that upgraded systems could be required for the existing projects. In addition, the recent decision by the environment ministry to do away with coal washing makes it more important for TPPs to invest in efficient PM control technologies.

The CEA has prepared a phasing plan for ESP upgradation for 220 units totalling 63,425 MW up till 2022. So far, NTPC has taken major steps in ESP augmentation and has already planned/ undertaken extensive renovation and modernisation (R&M) of ESPs in units installed before 2003. Further, the company has identified 94 units requiring R&M implementation. As of now, 53 units, out of a total of 15,320 MW capacity, have implemented R&M of ESPs, commissioned before December 31, 2003. For units commissioned after December 31, 2003, only two units have completed its implementation.

Some of the key issues with ESP implementation are generation loss, inadequacy of land, constraints in civil works (especially for additional foundation works), and delays in material supply and mobilisation.

Issues and concerns

There are several other regulatory and financing bottlenecks for FGD implementation, as per FICCI. For instance, though the MoP has issued directions to treat the requirement of installation of FGD as “change in law” and pass on the costs, and the Central Electricity Regulatory Commission (CERC) has also passed favourable orders on a case-to-case basis, these orders are being challenged by discoms. Without prior approval from discoms, lenders are unwilling to finance FGDs in view of the uncertainty about cost recovery. Further, there is uncertainty regarding the return on equity (RoE) as well. The CERC’s tariff regulation provides for RoE equal to the cost of debt but it is next to impossible to get equity at the prevailing interest rates for debt, which would lead to a penalty on investors who have already invested large sums of equity in projects. In addition, for plants without power purchase agreements, many of which are under financial stress, there is no way forward regarding how these would be compensated for FGD costs. The industry also points out that though the Ministry of Environment, Forest and Climate Change had notified the emission norms for TPPs in December 2015, technical specifications for FGD installation were finalised by the CEA only by June 2018.

The case of CPPs is even more challenging as industries cannot pass through the escalated cost burden to end consumers as prices of most of the products are market linked. There is a high capex/opex (Rs 500-Rs 700 million per MW of capital investment) required for FGDs, which increases the electricity generation cost and, in turn, affects industrial production costs. Also, most industries had set up existing CPPs without planning for the space required for FGD installation and, therefore they need more time to identify the land required for FGD after techno-feasibility studies. Further, installation of FGDs in operational CPPs is a complex and time-consuming process, requiring around three years with shutdown of the CPP units and industrial operations for around three months (to carry out lining inside chimneys to handle wet flue gas from FGD absorber). With the pandemic already hampering industrial operations, any further shutdowns could prove devastating for the industry.

Key recommendations and the way forward

In the backdrop of these challenges, thermal power gencos have urged the MoP to extend the deadline for meeting emission norms by two to three years. This would also augur well for the central government’s vision of a self-reliant India, as it would give time to domestic equipment manufacturers to ramp up their capacity to meet the domestic demand. The APP estimates that the move would open orders worth Rs 480 billion for domestic equipment suppliers including BHEL, L&T, GE India, ISGEC and Thermax. However, a shift to domestic sourcing of equipment would lead to an increase in capital costs by 20-25 per cent, thereby impacting power tariffs.

Alternatively, a committee can be set up with representatives from the MoP, MoEFCC and CEA to examine each TPP on a case-by-case basis and recommend specific revised timelines for each TPP based on the progress. Also, the CERC should speed up the formulation of guidelines for a provisional tariff mechanism for pass-through of FGD costs. It has been doing the same on a case-to-case basis so far, but in April 2020, it agreed to issue a discussion paper on the compensation mechanism and tariff implications. The process has not yet begun and may take several months to complete. The MoP’s intervention may be required to expedite the process as the timely implementation of the compensation mechanism is necessary to enable bankers to provide the necessary credit to gencos and avoid further delays.

Furthermore, there is a need to devise a mechanism of cost recovery for TPPs selling power in the power exchange or under short-term contracts through bidding under the e-portal DEEP (Discovery of Efficient Electricity Price), along with extension in time for FGD installation. Last but not the least, an immediate time extension is sought by the industry for the installation and commissioning of FGDs by CPPs that may be exempted against any adverse action for non-compliance of the new emission norms, in view of the June 30, 2020 deadline.

Of late, concerns have also been raised by certain non-governmental organisations owing to the adverse impact of wet FGD technology on the environment – though the technology reduces SOx emissions, it leads to carbon dioxide generation, which exacerbates global warming. In addition, there are issues related to gypsum disposal with these systems. Therefore, a thorough assessment of the FGDs’ impact on the environment needs to be made.

Net, net, the thermal power industry is facing challenges from all sides and the government’s intervention in this regard is keenly awaited.

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