Domestic gas prices have seen consistent half-yearly downward revisions in April 2015-April 2017 following which the prices have halved to $2.48/mmbtu (GCV basis) in H1FY18 from $5.05/mmbtu during November 2014-March 2015. The prices, however, increased to $2.89/mmbtu in H2FY18 and $3.06/mmbtu in H1FY19 in line with the rise in global gas benchmarks.

Albeit domestic gas prices are not lucrative, the government has provided marketing and pricing freedom (subject to a price ceiling) to players operating in deepwater, ultra-deepwater and high pressure-high temperature areas. The natural gas price ceiling for such challenging areas are $6.78/mmbtu as of now. But this may keep varying in line with the prices of substitute fuel (fuel oil and naphtha prices may increase as crude oil prices rise) as provided in the pricing formula. The latter, along with the marketing freedom, could improve the viability of gas discoveries in challenging fields and could lead to higher domestic gas production over the longer term.

We expect domestic natural gas production to increase to ~110 MMSCMD by FY22 and to ~143 MMSCMD by FY27 from the current level of ~90 MMSCMD. Apart from marketing and pricing freedom for gas discoveries, the government has also announced various reforms like the revenue-sharing model, a uniform licensing framework and an open acreage policy under the new hydrocarbon exploration licensing policy (HELP) and; reduction in royalty rates for the deepwater and ultra-deepwater areas, which could aid in incremental domestic gas production over the long term.

Despite the significantly high potential across several sectors, the realisable demand for natural gas will be a function of several factors: gas supplies in the market, price competitiveness of gas as compared with alternative fuel, timely commissioning of the proposed transmission pipeline infrastructure and regulatory initiatives in the power sector like implementation of time-of-day tariff.

Overall, unconstrained gas demand is expected to rise to ~260 MMSCMD by FY22 and to ~285 MMSCMD by FY27 from the current demand potential of ~230 MMSCMD. Actual consumption has been much lower at around 140-145 MMSCMD over the last 4 years due to st­e­ep fall in domestic gas supplies and dest­ruction of demand from some of price sensitive segments like power.

As for the total natural gas supply potential, it is expected to increase significantly over 5-6 years with higher domestic gas production and commissioning of firm re-gasification capacities during FY18-22. With the increase in supplies, the difference between the projected demand and supply potential is expected to narrow FY20 onwards.

Further, the demand for R-LNG may be affected because of significant competition from some of the cheaper liquid fuels and as a result the actual consumption of R-LNG could be lower, leading to significant competitive pressures in the re-gasification sector over the medium term.

Upcoming LNG capacities may operate at relatively lower utilisation (~50 per cent or even lower) than the current utilisation of re-gasification capacities (above 85-90 per cent on an aggregate basis) in the country. If many re-gasification terminals, as planned, come on stream over 4-5 years, the new entrants would face significant pressure on volumes and margins as they will have to compete with the existing terminals and brownfield expansion, which are more cost efficient because of lower capital intensity.

Sub-optimal capacity utilisation and lower re-gasification margins could also put significant pressure on the returns and credit profiles of new entrants, especially in the initial years of operations. Sponsors with significant captive demand for R-LNG such as for refineries and CGD ventures will, however, be able to partly buck the trend. Expansion of the LNG market to non-traditional applications such as fuel for buses/HCVs, inland waterway vessels and coastal movements will be key to alleviate pressure on utilisation.