Of these power plants, about 2,178 MW are state-owned generating stations while private players have about 7,190 MW of operating capacity, either commissioned or under construction. These projects were built on the government promise that gas will be allocated to them, on a first-come-first-served basis, when they are ready for generation.
However, for these plants to function, they will need about 40 million metric standard cubic metre per day of gas assuming operating levels of 85% plant load factor. Analysts at Morgan Stanley say that while they expect the KG D6 volumes to rise to 30 mmscmd by FY17, the increased supplies will first be dedicated to increasing the PLF of existing plants rather than bring in the stranded assets.
PLFs of existing gas plants have been badly battered; from > 60% in FY10 and FY11, the PLFs have gone down to the mid-20s. This, the analysts say, has largely happened on the back of declining KG D6 gas volumes where gas production has fallen from 56 mmscmd in FY11 to 13 mmscmd currently.
There are 1,086 MW of existing gas-based power plants operated by state-owned and private players such as ONGC Tripura Power and Neepco, which has prompted analysts to say that companies with stranded assets such as Lanco, Reliance Power and Torrent Power will remain under the cloud of lower gas supplies for a longer period.
As such, gas supply is skewed across the country, with some states getting more gas and some, pretty less. States which have a gas source or a pipeline infrastructurelike Gujarat, Maharashtra, UP, Andhra Pradeshhave gained from higher availability of gas whereas states such as Punjab, Haryana, Jharkhand, Uttarakhand, Karnataka, Kerala, Bihar, Chhattishgarh, have not been able to utilise the benefits of gas due to lower gas availability and inadequate pipeline infrastructure. Of the stranded projects, about 900 MW are in the states which do not have ready access to the natural resource.
The shortage in natural gas supply has hampered the capacity addition and performance of the existing plants. Allocation of domestic gas to the power sector will remain constrained due to competing demand pressures from the fertiliser and petrochemical sectors, says a 2013 report by the Petroleum and Natural Gas Regulatory Board.
While supply is limited, demand is only growing. The PNGRB report says natural gas demand is set to grow significantly at a CAGR of 6.8% from 242.6 mmscmd in 2012-13 to 746 mmscmd in 2029-30. Gas-based power projects will account for 36% to 47% of this demand.
The supply of natural gas is likely to increase in the future with the help of increase in domestic gas production and imported LNG, the board said. It had shrugged off the possibility of exploring natural gas opportunities through non-conventional sources such as shale gas due to lack of data on possible opportunities, regulatory policy and inadequate domestic infrastructure.
The ministry of petroleum and natural gas expects supply of natural gas to grow at a CAGR of 7.2% between 2012 and 2030, reaching 400 mmscmd by 2021-22 and 474 mmscmd by 2029-30. Still, the demand-supply gap would be about 272 mmscmd by 2029-30.
As project gets stranded for want of gas, Morgan Stanley analysts suggest blending RLNG could be a possible solution, however, its high cost is a key deterrent. While domestic gas supplies were priced at $4.2 per million metric British thermal units, landed RLNG is available at $15/mmbtu (spot prices can be even higher). If power plants were to blend domestic and RLNG in an equal proportion, power tariffs are likely to be in the range of R5-5.5/unit which is unpalatable for state electricity boards, they said.
With the demand for gas-based power generation highly price-sensitive, the PNGRB had said that the power sectors ability to absorb higher priced
RLNG will likely need assistance from power sector reforms. But the reforms, happening in fits and starts, is off little help to the stranded projects.