For the period until battery energy storage becomes more widely available and affordable in India, some of the country's existing gas-based power plants could be used to serve the peak demand or provide grid-balancing ancillary services.
Operating 12.5GW of existing gas capacity as peaking plants, complemented by 20GW of four-hour battery storage systems, could help India meet the maximum peak demand anticipated in the financial year 2029/2030.
With additional domestic gas supply expected in 2023, the Indian government should consider revising its gas allocation policy to supply domestic gas for peaking power.
India's 24.9 gigawatts (GW) of gas-based power plants are either stranded or operating at sub-optimal levels due to the non-availability of affordable fuel. A total of 31 gas-based power plants with a combined capacity of 14.3GW are stranded. These plants were built at a cost of almost Rs650 billion (US$8.2 billion), of which banks have funded Rs500 billion (US$6.3 billion).
In the early part of the 2000s, India was betting big on new gas discoveries. In 2002, Reliance Industries Limited (RIL) announced that it had discovered 10.5 trillion cubic feet of gas in the Krishna-Godavari (KG) basin off the country’s eastern coast. The government’s bullishness toward the fuel triggered a rush by private companies to set up gas-based power plants.
As the years ticked by and the company dug more wells, the promise of domestic gas production kept growing. From an initial estimate of 40 Million Metric Standard Cubic Meters Per Day (MMSCMD), RIL raised production estimates to 80MMSCMD by 2009, when it actually began production.
However, gas production from the KG-D6 basin, as it came to be known, fizzled out well before reaching the expected peak. In fact, the output of 69.44MMSCMD in March 2010 was the highest before it started dipping, reaching a low of 5.5MMSCMD in the fiscal year (FY) 2017/18.
The lack of domestic supply was the key reason for the decline in gas-based power production. Further, the explosive growth of coal-based thermal power plants and over-expectation of electricity demand growth also resulted in gas-based power losing out.
By 2013, the Indian government had even switched the priority allocation of domestic gas from the power sector to the city gas distribution (CGD) sector. Since then, gas-based power plants have not received any gas from the KG-D6 basin. As a result, power plants had to depend on liquefied natural gas (LNG) to meet their fuel needs.
Doing so has made gas-based power uncompetitive against other fuel-based power and renewables, which have been on a declining cost trend in the last decade. In 2018, the power tariff from LNG at US$7.5-8.0/Metric Million British thermal units (MMBtu) came to Rs8/kilowatt-hours (kWh). On the other hand, the tariff for coal-based power was Rs1.97-5.73/kWh and for solar was Rs2.44-3.34/kWh. The global supply disruptions and rising global prices in recent times further weaken the case for using LNG for power generation.
Giving fresh impetus towards extracting natural gas from the KG-D6 basin along with its partner BP, RIL now expects to ramp up production from three new fields in the KG-D6 basin. At its annual general meeting recently, the company said it is exploring three new fields – MJ, R-Cluster and Satellite Cluster – that could raise production to 30MMSCMD by 2023, or 30% of India’s domestic natural gas production.
There is a case for directing domestic gas or blended gas to power plants to utilise them for meeting India’s peak demand requirements.
But this is no longer 2009. India has ambitious goals for decarbonising its economy. So how do natural gas, another fossil fuel, and electricity produced by burning it fit in with the country’s goals?
There is a case for directing domestic gas or blended gas to power plants to utilise them for meeting India’s peak demand requirements. Even with the high rates of domestic gas of US$6.1/MMBtu in April 2022, gas-based power emerges as the most economical among the other prevailing short-term market options or contracts of less than one-year period, including bilateral trades, trades through power exchanges and through deviation settlement mechanism (DSM). With the recently revised domestic gas prices of US$8.57/MMBtu from regular fields utilising domestic gas would still be economical than other short-term options for supply of power during peak hours or grid imbalance with the power tariffs at around Rs 6.2/kWh.
Gas-based power plants can also help in providing flexible power and help manage grid balancing while battery energy storage systems scale up and become more affordable. Operating 12.5GW of gas-based capacity could be useful to meet maximum peak demand in FY2029/30, complemented with battery energy storage systems.
The government may also look to adapt a scheme it had proposed in 2019 that sought to bundle gas-based power produced using LNG with solar power. For the blending scheme, the proposal was that GAIL would import the required gas. GAIL had indicated LNG would cost US$6/MMBtu at a delivery price of US$8/MMBtu for power generation at Rs4/kWh with proposed waivers. This was to be blended with solar power, which was about Rs2.75/kWh then, and the power ministry was hopeful of finding enough buyers for the scheme.
The government should expedite efforts to utilise green hydrogen for fertiliser production instead of grey hydrogen produced from natural gas.
This scheme could now be implemented for domestic gas and solar power instead of LNG. With the LNG prices expected to remain above US$25/MMBtu for the rest of the year and not below US$10 MMBtu till 2027, it would be impossible to make any economics of power supply work with LNG. Companies can benefit from blending domestic gas-fuelled electricity and solar power to reach an average rate way under Rs5/kWh rather than buying at Rs12/kWh as capped in the spot market for now. This would considerably increase power supply reliability, and the country will not have to go into bouts of load shedding witnessed in the summer months of April-July 2022.
Finally, the government should expedite efforts to utilise green hydrogen for fertiliser production instead of grey hydrogen produced from natural gas. It could allocate the required domestic gas to the power sector instead under the “no cut” category.
The government’s proposal for setting up a separate higher price market to allow sellers with high variable costs, including gas-based power plants and battery storage developers, is an important step towards serving peak demand. Researchers have noted that the Time-of-Day Tariff will provide an incentive for gas-based capacity to operate, and this proposal of a higher tariff could be useful.
Any transitional use of gas should be limited to sectors with no competitive alternatives or where gas use supports renewable energy uptake or helps maintain grid flexibility.
We believe any transitional use of gas should be limited to sectors with no competitive alternatives or where gas use supports renewable energy uptake or helps maintain grid flexibility. For instance, until storage options are more widely available and affordable, gas-based power plants could be used to serve the peak demand or provide grid-balancing ancillary services.