The Ministry of Power (MoP) notified new guidelines in March 2021, paving the way for distribution utilities to exit power purchase agreements (PPAs) upon expiry of their terms by giving six months’ notice. This is an important development for states that were procuring relatively costly power from the central generating stations. Post the discoms’ exit, the generating companies have the flexibility to sell power in any mode – long term, medium term or at the power exchanges. Industry stakeholders share their views on the likely impact of these guidelines on the states, discoms and gencos, and the future power procurement strategy of discoms…
What will be the likely impact of these guidelines on the states, discoms and gencos?
Sachin Gupta
The MoP, on March 22, 2021, issued guidelines enabling discoms to exit PPAs after the completion of 25 years or the period specified in the PPA. The guidelines also allow gencos the flexibility to sell their power in any mode after a state/discom exits a PPA. Further, any discom relinquishing its share of power from a central generating station (CGS) would be required to clear all its past dues and obtain an approval from the corresponding state electricity regulatory commission, which would evaluate the adequacy of power post such relinquishment.
It is understood that over the past couple of years many states/discoms have requested the power ministry to allow them to surrender a share of their capacity from CGSs, citing costly power or excess power availability as reasons. Also, one of the arguments in favour of these guidelines is the reallocation of such PPAs to power-deficit states. In this context, the issuance of the guidelines is a step in the right direction. It was usually seen that CGSs were able to get the PPAs renewed for their old projects, leading to discoms having to continue to buy expensive power. Post their exit from costly PPAs, discoms will be able to participate more actively in the market, with the flexibility to purchase power from competitive bilateral contracts, power exchanges, etc. While these guidelines are still recommendatory in nature, their real impact would largely be visible once a regulatory mechanism is placed around them.
As for gencos, while they were able to recover the fixed cost of plants during long-term PPA tenors, the renewal of PPAs beyond the original tenor enabled them to generate incremental profits, given that these were cost-plus PPAs. As a result of the new guidelines, gencos with old units (ranking low in merit order despatch) will face PPA exits by discoms. The challenge will be particularly steep for units that are inefficient and/or very distant from coal mines, thus necessitating higher freight charges, making their variable costs uncompetitive. CGSs, which hitherto had the comfort of tied-up cost-plus PPAs, will be exposed to the vagaries of market dynamics. The government has indicated that CGSs will have to reorient their sales strategies and will be free to sell in the short-term market. However, it remains unclear as to what will happen on the fuel supply front. Any absence of coal linkage and exposure to short-term trade would clearly be negatives for such CGSs.
“While these guidelines are still recommendatory in nature, their real impact would largely be visible
once a regulatory mechanism is placed around them.”–Sachin Gupta
Sabyasachi Majumdar
Once implemented, these guidelines would enable discoms to relinquish power from older CGSs with a relatively high cost of generation. While the capacity charges for such projects are relatively low, given the depreciated asset base, the fuel cost of generation is generally high, considering the vintage nature of the plants and their suboptimal operating efficiency compared to newer supercritical units.
With the significant reduction in solar power tariffs to Rs 2-Rs 2.20 per unit, the cost of procurement from solar power plants remains lower than the variable cost of generation for many thermal power plants. Despite the expected increase in solar power tariffs arising from the imposition of basic customs duty on imported cells and modules, the tariffs are likely to remain well below Rs 3 per unit, and thus will continue to remain cost competitive from the off-takers’ perspective. For state-owned utility offtakers, the average power purchase cost and the variable cost of power purchase (bottom 25 per cent in merit order despatch) remain in the range of Rs 4-Rs 5 per unit and Rs 3-Rs 3.50 per unit respectively in the key renewable energy generating states. Thus, the replacement of high-cost power from old central thermal stations with relatively cheaper power from solar power projects would result in savings in power purchase cost for discoms. However, one must note that thermal units are required to meet baseload demand, while generation from solar power projects is only available during the day and is susceptible to variation depending on weather conditions. Therefore, discoms must ensure adequate tie-up of PPAs to meet the baseload demand, and/or adopt solar power with storage, which has achieved competitive tariffs (Rs 3.50-Rs 4.30) in the tenders awarded by the Solar Energy Corporation of India (SECI).
The share of renewables in pan-Indian electricity generation has been witnessing a healthy growth, from 5.6 per cent in 2015-16 to 10.7 per cent in 2020-21, amidst the strong policy push and improving tariff competitiveness. Given the must-run status for these projects, discoms have to back down thermal units, leading to subdued plant load factors (PLFs) for these projects. However, discoms would continue to bear the fixed cost obligations (linked to plant availability) under long-term PPAs. The relinquishment of the older PPAs will enable the discoms to reduce the fixed cost obligations to some extent.
The Government of India has set a target of increasing the country’s installed renewable power capacity to 175 GW by December 2022 and 450 GW by 2029-30 from the current levels of 94 GW as of March 2021. As per ICRA’s estimates, the share of renewables in the installed power generation capacity is expected to increase to 34 per cent by March 2025 from 25 per cent as of March 2021, and the share of renewables in the all-India generation mix is expected to increase to 16-17 per cent by 2024-25 from 10.7 per cent in 2020-21. As a result, a large portion of the incremental demand is expected to be met through renewables. In this context, the procurement strategy of discoms is expected to revolve around renewables and renewables plus storage. Given the challenges in integrating solar and wind power with the grid, the discoms would have to plan their procurement strategy to include a mix of renewable and storage, comprising battery storage or pumped storage, to enable efficient integration of renewables with the grid. Also, the flexibility of thermal power stations has to be improved in terms of the ramp-up and ramp-down rates, so that the stations can act as grid balancing sources.
From the central gencos’ perspective, exit from long-term PPAs for older units may impact the returns for these assets unless the projects are able to tie up long-term or medium-term PPAs with other states at competitive tariffs. This is considering the subdued tariffs in the short-term market and the subdued PLFs in the thermal power segment. While PLFs are expected to witness an improvement in 2021-22, led by a recovery in electricity demand growth, they are still likely to remain below 60 per cent and may face a downside risk in case of a prolonged impact of the second wave of Covid-19.
“Discoms must ensure adequate tie-up of PPAs to meet the baseload demand, and/or adopt solar power with storage, which has achieved competitive tariffs in the tenders awarded by SECI.”–Sabyasachi Majumdar
Ganesh Srinivasan
These guidelines will pave the way for discoms to procure power competitively, as well as give opportunities to generators to sell power in open markets. This positive step aims to balance the interests of utilities, generators and consumers. Since most of the plants that have been in operation for over 25 years are coal and gas based, this will also give a much-needed incentive to the renewable sector to pitch in, thereby helping the environment in the process. The additional power, if available and competitive, can be traded through the power exchange, the merchant route, etc., thereby contributing towards the development of the sector as a whole. In the case of Delhi, the Government of the National Capital Territory of Delhi and the Delhi Electricity Regulatory Commission (DERC) have supported the exit of discoms from central generating plants that have outlived their useful life and are operating at high costs.
What is your outlook on the power procurement strategy of discoms going forward?
Sachin Gupta
The implementation of the guidelines will provide flexibility to discoms in terms of power procurement plans. Discoms that have adequate availability of power are likely to exit old PPAs. Such a move will reduce the power purchase cost of discoms that are otherwise stuck with high-cost power from inefficient old plants. The discoms are also likely to engage in medium- to short-term purchases, including greater procurement through power exchanges, where tariffs can be competitive. Over the past four years, buoyed by adequate availability of power (sub-2 per cent base energy deficit) and low merchant tariffs, discoms have not been coming up with long-term PPAs. We expect the trend to continue, aided by such guidelines from the government nudging the sector towards more competitive procurement.
“Since most of the plants that have been in operation for over 25 years are coal and gas based, it will
give a much-needed incentive to the renewable sector to pitch in.”–Ganesh Srinivasan
Ganesh Srinivasan
Discoms are all attempting to reduce power procurement costs, which form close to 80 per cent of the average cost of supply. As far as thermal power plants are concerned, a cost escalation is expected due to the installation of flue gas desulphurisation systems. This is under regulatory scrutiny/adjudication with the Central Electricity Regulatory Commission. In addition, due to cost escalations in the administrative price mechanism/regasified liquified natural gas rates/ freight or coal charges, power purchase costs have seen an increasing trend. To minimise and avoid such escalations in power procurement cost in the future, we would like to shift more towards renewable energy procurement. The company will be receiving around 300 MW from solar and around 50 MW from wind energy in the near future, based on projects that are under commissioning. Going forward, Tata Power-DDL will procure more renewable power as per its demand requirements, renewable purchase obligations mandate, and load curve. We are also in the process of procuring power through the hybrid (solar plus wind) mode, for which we have sought approval from the Ministry of New and Renewable Energy and the DERC. We are also eagerly tracking the cost of battery storage, as well as the solar and storage tenders of SECI, as that will give us the opportunity to procure firm renewable power. If all goes well, we do not intend to sign up for any incremental coal/gas-based power plant in the future.
The company had exported up to 200 MW of power to Kerala and Tamil Nadu during the winter of 2020 under banking arrangements. This power shall now be returned by these states to Tata Power-DDL in the summer months of 2021. Additionally, non-solar renewable power has been arranged from Himachal Pradesh. Any further requirements will be met through the power exchange/ green markets.