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Coal power’s trilemma: Variable cost, efficiency, and financial solvency

The study has been authored by Karthik Ganesan and Danwant Narayanaswamy
The timelines for compliance with pollution norms have been repeatedly stretched, with plants being asked to present affidavits of retirement deadlines, if they have any, and benefit from a more lenient treatment.(Reuters file photo)
Published on Oct 21, 2021 02:31 PM IST
ByCouncil on Energy, Environment and Water

It was a ‘lost-decade’ (2010–2020) for coal-based power generation in India. There was much promise at the beginning of the decade and generation capacity was added at a breakneck pace. Eventually, low economic growth and poor growth in power demand ended up bankrupting the sector that was already teetering on the brink. Today, non-performing assets (NPAs) abound in the sector and recovery of dues is a challenge throughout the value chain. We are at crossroad, where at the global stage, India is contemplating its net-zero emissions timelines, while the only strategy presented thus far has been increasing the installed capacity base of renewable energy (RE). What about our thermal fleet then? The timelines for compliance with pollution norms have been repeatedly stretched, with plants being asked to present affidavits of retirement deadlines, if they have any, and benefit from a more lenient treatment. While air pollution legislation has been given prominence, soil and water pollution emanating from millions of tonnes of ash pile up still goes unnoticed. The Covid-19 pandemic has also dented demand growth and many assets, which are in advanced stages on construction, are in a grip of uncertainty.

Alongside, a new market-based economic dispatch (MBED) mechanism for procuring bulk power has been proposed to begin in April 2022. By dispatching power through a central clearing mechanism, MBED aims to reduce power procurement costs by INR 12,000 crore (MoP, 2021). All these developments point to an undercurrent of a storm brewing in the sector, and it is at this moment we ask the question—Can India rethink how it manages its coal-based power generation fleet from here on? Reviewing the thermal setup We began this study with an examination of the performance—thermal, financial, and operational—of nearly 194 GW of coal-based generation capacity over the course of 30 months leading up to the start of the Covid-19 pandemic in India. We explored how assets are being utilised and segment them by vintage and ownership. We observed that older plants are generating a disproportionate share of electricity and, unsurprisingly, private sector plants bear the brunt of under-utilisation challenge the sector is facing. When exploring the cost distribution of plants, we find that not only do older plants have low fixed costs but they also have low variable costs and outcompete younger plants in the merit order stack. Even in cases where plants incurring low variable costs are available, plants with higher variable costs are dispatched as they are contracted and preferred by utilities, given their lock-in clause in the contracts. The net impact of the current strategy of utilisation of assets is that the thermal efficiency of the generation fleet in India is an abysmal 29.7%t, which in turn points to regulators being lax about such poor technical performance.

Given the inefficient operations of the thermal fleet, we wanted to assess what exactly determines power plant efficiency and the variable costs of generation. Towards this end, we carried out a parametric regression assessment of these two metrics. We find that age, plant load factor (PLF), and the average size of units in a plant play an important role in determining how efficient a plant is. In the case of variable costs, we find that it is largely driven by the cost of delivered coal and to a lesser extent by operational characteristics of a plant such as station heat rate (SHR) and auxiliary consumption. These reinforce the theory that newer vintage plants, if operated more consistently, would yield better outcomes to achieve system efficiency and possibly also lower variable costs. This in turn implies better environmental outcomes—lower greenhouse gas (GHG) emissions, reduced output of criteria pollutants, or lesser quantity of ash generated. But the financial implications of this proposition remain to be seen.

Our approach to determining the criteria for dispatch In a bid to conceive of a system where efficiency is rewarded, we demonstrate an approach to dispatch power, based on an efficiency merit order and not the one based on stated variable costs. We chose efficiency as the criterion for dispatch because variable costs are distorted by fuel costs and fuel supply contracts, among others. The order based on variable costs does not mirror efficiency, as evident in our descriptive assessment of the system. As a first step in our approach, we assign higher PLFs to newer vintages, which is inherently a logical step—from operational and financial standpoints of the system. We order plants in an increasing order of estimated SHR, based on the parametric function we established in the first step. Generation schedules are assigned to plants at a daily resolution level, without factoring in spatial and temporal constraints in the movement of power but only providing for the energy demanded in a day. This is a significant limitation, but it is important to understand the nature of unconstrained opportunities existing in the Indian thermal fleet. If the proposed efficiency-based dispatch is employed, the Indian coal fleet would be able to cater to the average energy demanded from it (over the assessment period) at an improved thermal efficiency of 6% over the baseline (the current scenario in action). This implies that the generation efficiency goes up to 31.6%. As a corollary, we find that the reassignment results in an annual saving of nearly 42 MT of coal and a concomitant reduction in GHG and criteria pollutant emissions. The overall fleet also operates at a higher overall PLF of 78%, with significant room for providing more generation should the system require it.

Outcome of our assessment: a more efficient and lower cost generation mix We have structured an efficient generation mix, but does it financially make sense? The drivers of overall variable costs are delivered cost of coal, SHR, auxiliary consumption, unit size and age. In our assessment, we find that the delivered cost of coal in the reassigned scenario increases the overall cost of generation, as 20% of the pit-head plants do not generate in the reassigned scenario. However, plants consume less energy, operate at a higher load factor, and as a result there are significant savings on variable costs of generation. The total savings on variable costs in this reassigned scenario amounts to 8,944 crore. Against the overall cost of power procurement by discoms, this is a small fraction, though significant enough to give much needed breathing room for their finances.

As a key outcome, we find that nearly 50 GW of capacity could be deemed as surplus to the requirements of the system, for the energy demand it caters to. Even when considering power delivered, the retained generation capacity could provide for the quantum of peak power required (143 GW in the analysis period) from the thermal fleet. We propose that 30 GW of the surplus capacity, which represents the older and some of the least efficient assets, be taken up for accelerated decommissioning as these have been identified in the National Electricity Plan (2018) for decommissioning during the course of this decade (2021-2030). Each passing year of delay increases the burden on us with a higher electricity bill and more air, water, and soil pollution to manage. It also results in a one-time saving of 10,200 crore in avoided pollution-control retrofits, which would otherwise be needed should some of these plants continue to operate. Nearly 20 GW of capacity can be considered for mothballing and based on a more rigorous assessment, it can be decided where they would be called upon to generate if contingencies are likely to arise. We also observe that the system has significant slack, outside of this assessed stock of plants, to manage contingencies and demand growth over the course of this decade. With nearly 36 GW of thermal power in various stages of construction, we find that meeting the electricity and power demand in later years of this decade should not be a matter for concern. Given some key limitations in terms of the spatial and temporal resolution in our study, there is a need to carry out a more rigorous assessment of the opportunities identified in this study. Equally, there is a need to assess electricity demand over the course of this decade and the prospects of RE materialising to the extent that it is currently anticipated in existing studies, in order to conclusively decide on decommissioning and its benefits.

 

The study has been accessed by clicking here.

(The study has been authored by Karthik Ganesan and Danwant Narayanaswamy)

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