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transport of coal with ash content higher than 34% over more than 500 km. Historically, no comprehensive effort has been made to develop equipment for coal washing, resulting in the use of foreign equipment inappropriate for Indian coal. More recently, CIL and the MoC have sponsored several R&D programmes and currently most of the equipment available for washing coal in India is suitable. Despite the improvement, an effort to build further washing capacity and develop washing technology specific for Indian coal would pay off, considering the specific characteristics of Indian coal and the prospects for long-term utilisation of coal in India.

CIL operates 15 coal washeries, with a capacity of 37 Mt per year, of which 12 are for coking (23 Mt per year) and the others are for non-coking (14 Mt per year, compared with over 500 Mt of annual production). CIL plans to build 9 new washeries for coking coal and 9 non-coking washeries to add more than 93 Mt per year of washing capacity.

Washing is not an option for coking coal used for metallurgical purposes, but instead an obligation, as the steel-making process requires low-ash coal to produce coke suitable for use in the blast furnace.

Local air quality policies

By international comparison, India has some of the highest levels of air pollution, caused by a range of different local sources (see Chapter 3 on energy and sustainable development). Burning solid fuels like firewood and dung-cakes at home is a major source of pollution, besides emissions from transport, crop burning and construction. Coal use in power generation is another large emitter, responsible for 60% of industrial particulate matter (PM) emissions, 45% of sulphur dioxide (SO2) emissions and 30% of nitrogen oxide (NOX) emissions (CSE, 2018).

In order to reduce adverse effects of thermal generation on the environment, the GoI has adopted stringent environmental norms for air pollutants and water consumption.

In order to decrease pollution from coal power plants, in 2015 the MoEFCC adopted standards to limit the concentration of SO2, NOX, PM and mercury in stack emissions for coal-fired power plants. Existing plants were to meet the standards within a period of two years (by December 2017). These standards were amended in 2018.

Around 150 GW of thermal capacity (out of the total coal fleet of 194 GW), involving 400 units, needed to install air quality control systems. By the expiry of the deadline in 2017, no existing plant had complied with the standards and the government postponed the implementation deadline to 2022. The Supreme Court ruled that the implementation should ensure that the most-polluting plants comply by 2021, while at the same time postponing the further tightening of the standards. The 2015 standards specified the further tightening of air pollution limits for NOX and SOX emissions (with NOX limits falling to 300 milligrammes per normal cubic metre [mg/Nm3] and SOX to 100 mg/Nm3). In August 2019 the Supreme Court annulled this tightening of SOX and NOX emission limits.

In December 2017 the CEA published the implementation guidelines for air quality control systems. It prepared a phasing plan for the implementation of the standards at identified thermal power plant units: 66 GW of output requires the augmentation of electrostatic precipitators (to meet PM limits) and 166 GW the retrofitting of flue-gas desulphurisation and combustion modification/optimisation, with other plants upgraded in collaboration with

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the Regional Power Committees. As of March 2019 tenders had been issued for the installation of flue gas desulphurisation in around 96 GW of capacity, more than half of the capacity requiring this retrofit (IISD, GSI and CEEW, 2019).

The cost of implementing the standards is estimated at USD 12 billion. The GoI ruled that the investment costs of retrofitting pollution control installations and the associated operational costs can be passed on to utilities and consumers by the State Electricity Regulatory Commissions. Despite this regulatory clarity, the practical implementation is challenged by the poor financial health of the DISCOMs and consumers. Declining capacity load factors and the financial stress of the state-owned DISCOMs and some of the IPPs (see the Chapter 7 on electricity) has left the power sector with poor financial health. This is considered to be a significant barrier to passing on the costs to consumers and swiftly implementing the pollution limits. In 2019 the Ministry of Power proposed to the Ministry of Finance a financial subsidy package of USD 11.2 billion in order to avoid power price increases.

The benefits of compliance to public health outweigh the costs by far. Moreover, there are benefits in using by-products of the air quality control systems, both economical and environmental, as fly ash is a valuable product that reduces the CO2 footprint of cement making. Another by-product, gypsum, can be used in construction, reducing the environmental footprint compared with using gypsum mined from a quarry. If met, these emission standards would reduce pollution in India substantially, at low costs by international comparison.

While air pollution is the main environmental problem of coal power plants in India, it is not the only one. Water pollution and consumption by thermal plants is another one. The MoEFCC notified new environmental protection rules with stricter limits for water consumption from existing, constructed and new thermal power plants. Plants built after 2017 shall not exceed water consumption of 3 m3/MWh and existing plants not more than 3.5 m3/MWh. Plants installed after 2017 are required to achieve zero waste water discharge. Better management of pollutants, higher efficiencies and dry air cooling will help this.

India’s climate commitments and the role of coal

India’s National Determined Contribution (NDC) under the Paris Agreement sets out plans to reduce the emissions intensity of the economy by 33-35% by 2030 from 2005 levels; to reach 40% of power generation capacity from non-fossil fuels; and to create an additional carbon sink of 2.5-3 billion tonnes of CO2 equivalent through additional forest and tree cover. The GoI has expressed certainty on reaching at least the two energy-related targets sooner than 2030. Thanks to progress made in the implementation of these targets, the emissions intensity of India’s gross domestic product has already decreased by around 20% over the past decade (2005-15). At the same time, total energy-related CO2 emissions are expected to rise.

The National Electricity Plan of India of 2018 included plans to build 94 GW of new coalfired capacity (mainly supercritical coal units) between 2017/18 and 2026/27 (CEA, 2018). However, to date only 22 GW have been permitted amid weak economics, while 50 GW are under construction. Given the slow progress, the CEA’s 2018 plan did not foresee the construction of any additional new coal plants. However, the CEA has outlined in its draft

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2019 generation optimisation plan a large potential investment in new coal plants up to 2030 (105 GW of pithead plants and 44 GW of load-centred plants) (CEA, 2019).

The 2018 National Electricity Plan includes a new target for the closure of 48.3 GW of end- of-life coal plants. Specifically, the plan forecasts the closure of the oldest 22.7 GW of coal power plants up to 2021/22. This would include 5.9 GW of normal end-of-life retirements and 16.8 GW of early closures because of non-compliance with air quality regulations. An additional 25.6 GW of coal capacity is being considered for early retirement in the five years from 2021/22 to 2026/27.

India’s power system is experiencing rapidly rising shares of variable renewable electricity, which has two different impacts on the economics of existing coal power plants. On the one hand, it means less generation from these plants will be needed, which brings more economic and financial stress for many producers. On the other, flexibility requirements of the electricity system will rise. Many coal plants in India were not designed to follow load, but to provide baseload power. The GoI is currently identifying the plants that can and need to provide such flexibility. The deployment of other sources of flexibility, such as natural gas, pumped hydro storage or nuclear remain below expectations. The implementation of the new power market reforms are important to support flexibility and CERC has proposed reforms of ancillary services and short-term markets and economic dispatch (see Chapters 7 and 8 on electricity and system integration).

Carbon capture and storage

In 2007 the Department of Science and Technology initiated a national programme of research into carbon sequestration (carbon capture and storage [CCS]). R&D in CCS is being pursued by CSIR laboratories and academic institutions under the programme.

As part of Mission Innovation, India has initiated a funding opportunity in the Carbon Capture Innovation Challenge (IC#3) for joint R&D in the field of CO2 capture, separation, storage and CO2 value-added products to be taken up jointly by Department of Biotechnology and Department of Science and Technology with member countries of Mission Innovation.

The Intergovernmental Panel on Climate Change special report on CCS identified the need to obtain much more information on storage capacity in India (IPCC, 2005). Large areas of the Indian subcontinent may not be suitable for onshore CO2 storage due to high seismic activity and population density, and any CO2 storage activity would need to protect subsurface aquifers, which are vital source of ground water for agriculture.

NTPC’s Energy Technology Research Alliance (NETRA) initiated a project with IIT Mumbai to establish a 10 MW equivalent plant to capture flue gas CO2 and use it in the production of soda ash, urea or methanol. NTPC-NETRA signed a memorandum of understanding with India’s Oil and Natural Gas Corporation (ONGC) to establish a carbon capture plant at NTPC Jhanor Gandhar gas-fired power plant and the utilisation of CO2 in enhanced oil recovery in ONGC’s Jhanor field.

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