Grid level outages can be highly disrupting. Though definite findings about the causes of a countrywide blackout in Spain a few days ago are yet to come out, one thing certain is that the grid operators require adequate resources (capacity) in the system at all times to handle such contingencies. Particularly, flexible resources and adequate interconnection capacities become critical.
India is now coming out of the era of shortages and aspiring for achieving the Loss of Load Probability of 0.2% as prescribed in Resource Adequacy guidelines published in June 2023. However, achieving the goal of electricity supply of desired reliability standards can lead to higher costs if the commercial arrangements for procurement of wholesale electricity are not structured appropriately.
The subject matter of capacity markets is getting increasing attention now in view of the large uncertainties of demand and generation being faced by the power systems. The imperatives of global warming and electrification of energy services as a strategy for energy transition are resulting in difficulties in assessing the demand on grid with certainty.
For example, the short-term Resource Adequacy outlook published recently by National Load Despatch Center for FY26 informs a very wide range of likely demand in non - solar hours of May 2025 from 200 GW to 260 GW. Wide variations in wind generation even in its peak season are well known. These uncertainties in generation are going to increase further as the share of Variable Renewable Energies rises. The consequence could either be blackouts if the system has less than the capacity required for meeting the less probable yet higher range of demand for resources on the grid, or over-procurement by the Discoms resulting in stranded fixed costs. Generally, Discoms in India are reluctant to enter into 25-year long PPAs (power purchase agreements).
PPAs have misaligned incentives
Apart from the problem of stranded fixed costs, another major challenge with the conventional PPAs is that power generators have no obligation to support the power system in terms of ‘capacity’ and ‘ancillary services’ when system is in stress either due to higher-than-expected demand or lower-than-forecast renewable generation, because such generators are assured of their fixed costs based on availability calculated on an annual basis. Therefore, unless we tweak our market design, India may also face blackouts.
World over the developed electricity markets have generally adopted some sort of capacity remuneration mechanism for ensuring that peaking capacities remain available on demand for the power system without burdening the utilities by fixed costs of long-term PPAs beyond a level.
Various types of capacity remuneration mechanisms offer a market/regulatory process discovered capacity payment to the participating generator/storage/demand response for being available to the system as per contractual obligations which are designed to ensure their availability at the most stressed time blocks expected during the system operations.
As opposed to conventional PPAs where penalties even for liberal availability computed over a year are mild, default penalty for not being available to a ‘capacity’ can be as high as refund of four times of capacity payments received if the default was during a period of extreme stress in the system. Participating entities quote/are paid their capacity payments after assessing what revenues they can earn from energy and ancillary markets. In this way, ‘missing money’ problem of the investors is addressed. Key benefit of capacity procured in this manner is that these can be pooled for /traded by the procuring utilities for optimisation of the cost.
Standardised contracts and resource adequacy obligations
Capacity markets also have potential to correct the installed capacity mix towards optimality because these provide the right incentives to peaking capacity investments. For example, the results from a modelling exercise for the Madhya Pradesh power system were presented recently in a high level Roundtable in Delhi. Key message was that significant saving of about Rs 36,000 crores in ten years up to 2035 in overall system expansion and operations cost ( approx. 6.3% of total costs) was feasible in just one state if battery storage capacities of adequate size were added at the scientifically selected substations over the period. In that scenario, coal based capacity requirements also reduced from 23.37 GW to 16.50 GW.
Policy makers in India have already taken steps in this direction. A high-level Expert Group on development of electricity market in India submitted its report to the Ministry of Power in March 2023 which recommended that during the next two years, standardised exchange-based capacity contracts be introduced for short term trades.
Though India is witnessing some sort type of capacity contracts in the award of contracts for stand-alone battery storage capacities being procured at state levels, and for the pumped storage projects on a long-term basis, but this does not provide a credible framework of capacity markets for trading of capacities in the short term, or a price signal for investors to set up merchant capacities in advance.
Electricity regulators in India should move to set up proper capacity markets (with standard contracts so as to make these tradeable) starting first from short-term and then gradually moving on to longer durations.
I am not saying capacity contracts will fully replace new bilateral PPAs. Bilateral contracts of various durations and various types (just capacity or capacity with energy) will still continue to cover 70-80% requirements. But we will not achieve the stage of adequate liquidity unless the system has adequate capacity. Hence the capacity markets are the part of the solution we are seeking.
About 18 years ago, CERC took a bold decision to launch power exchanges even in the period of far larger shortages. It needs to make another similar bold move to launch short-term capacity contracts on exchanges with standardised contracts. This will have to be accompanied with enforcing the resource adequacy obligations on utilities to demonstrate that they have procured enough capacities to meet the projected demand.
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