Over the period 2010-16, consumption of natural gas in the country has been growing steadily. The share of regasified liquefied natural gas (R-LNG) in total natural gas consumption, despite R-LNG being more expensive, has been rising steadily since 2010-11. This could be attributed to multiple factors including a consistent fall in domestic gas production, an increase in regasification capacity, and lower spot liquefied natural gas (LNG) prices over the past two years as well as renegotiations of long-term LNG contracts. With regard to supply, domestic natural gas production decreased from 143 million metric standard cubic metres per day (mmscmd) in 2010-11 to around 88 mmscmd in 2015-16.
The procurement of gas by city gas distribution (CGD) players has been under pressure over the past few years. The demand for piped natural gas (PNG) has been impacted by the low competitiveness of R-LNG against competing liquid fuels and an industrial slowdown. Moreover, the growth of compressed natural gas (CNG) production has slowed down following low motor spirit and diesel prices.
CGD players have slashed prices multiple times in the past two years, and this reduction has been largely passed on to CNG and PNG (domestic) consumers. Meanwhile, to meet commercial and industrial demand, PNG is being supplied through imported R-LNG sourcing via spot or long-term contracts. Post January 2016, with RasGas halving the price of LNG, long-term rates and spot rates have almost converged. The CNG and PNG (domestic) segments have been accorded first priority in the allocation of natural gas since February 2014. Thus, CGD players submit monthly requirements for these segments and are allocated adequate quantities at the prevailing domestic gas prices.
Regional pipeline connectivity, a key issue, is expected to be addressed over the medium to long term. The western and northern regions of the country are well connected, while the eastern and southern regions have limited gas pipeline connectivity. In September 2016, the government approved viability gap funding of 40 per cent (about Rs 51.7 billion) of the estimated capital outlay of Rs 129.4 billion to GAIL (India) Limited for the development of the 2,539 km long Jagdishpur-Haldia-Bokaro-Dhamra gas pipeline. Work on the pipeline is being synchronised with the government’s efforts to revive three fertiliser units along the route of the pipeline. The government’s commitment towards the project has been reaffirmed by budgetary allocations of Rs 4.5 billion for 2016-17 (revised estimate) and Rs 12 billion for 2017-18 (budget estimate).
The Petroleum and Natural Gas Regulatory Board (PNGRB) has plans to revamp the CGD policy to increase the consumption of piped gas. Under the revised guidelines, bidding criteria for new gas could undergo changes. Two separate committees have been set up to consider an alternative bidding process and smoothen out CGD operations. The first committee will make the bidding process more effective by suggesting a replacement to the current process in which only a few cities receive bids during auctions and all the bids offer the same tariff. The second committee will suggest ways to deal with key obstacles CGD companies face such as high restoration charges levied by local authorities and delays in obtaining permissions.
Given the likelihood of improved prospects, interest in recent bid rounds has been high. Most bidders have bid aggressively at the lowest possible network and compression charges of Re 0.01 per million metric British thermal units (mmBtu) and Re 0.01 per kg. Low network and compression charges result in higher business risks for the bid winners post the marketing exclusivity period of five years. Bids have been received for Round 7 and authorisations are expected shortly. However, of the five geographical areas (GAs) offered, three – Jaipur, Udaipur and Bhopal – have been excluded/deferred from the bidding by the PNGRB due to a lack of pipeline connectivity.
Most awards in Rounds 4-6 have been decided by the highest bid bond criterion, resulting in large performance bank guarantees (PBGs) being submitted to secure the award, with the highest PBGs submitted in Round 4. High PBGs are a long-term risk for CGD players given the tough minimum work programme and service standards set by the PNGRB.
In Round 6, competition during bidding for certain GAs was high on account of their having better prospects, as in the case of Dahej, Goa and Rewari. Some GAs failed to receive any bids due to relatively lower volume prospects. There were also instances of encashment of bid bonds by the regulator due to non-compliance with bid conditions.
The demand for LNG is expected to increase to approximately 250 mmscmd by 2019-20 and around 280 mmscmd by 2024-25. The total supply potential is expected to increase significantly over the next eight years following the increase in regasification capacity. Further, the gap between projected demand as well as domestic and long-term contracted LNG supply is likely to be 90-100 mmscmd by 2024-25.
The current operational regasification capacity is about 18 million tonnes per annum (mtpa) (against a nameplate capacity of 25 mtpa). According to ICRA estimates, the R-LNG supply potential is expected to increase significantly to around 47.5 mtpa (~166 mmscmd) by 2019-20 and around 63.5 mtpa (~220 mmscmd) by 2024-25 owing to upcoming regasification terminals witnessing encouraging progress. However, some of the key challenges include financial closures without long-term tie-ups with LNG suppliers and offtakers, competition faced by R-LNG from liquid fuels, booking capacity on a tolling basis, and the completion of projects without material, time or cost overruns.
Going forward, the dependence on R-LNG is expected to increase with limited domestic gas availability. Higher prices for difficult fields and reforms in exploration and production could lead to an increase in developmental capex. The incremental production of natural gas is expected to come from, among others, the Oil and Natural Gas Corporation’s blocks in the Krishna-Godavari basin (KG-DWN-98/2), B and C clusters; Daman offshore blocks, and North and South Redevelopment Phase 3 of Mumbai High; Cairn Energy’s Rajasthan blocks; Northeast blocks of Oil India Limited; the Gujarat State Petroleum Corporation’s Deen Dayal block; and coal bed methane blocks. However, prudent bidding and the adoption of risk mitigation measures will be key to the long-term viability of the CGD segment.