Natural gas pricing has been subject to a lot of discussion in the recent past. Natural gas is used by the power sector, fertilisers, in refineries, city gas distribution and the steel and petrochemicals sectors. India's proven gas reserves currently stand at 1.45 trillion cubic metres, which is 0.77% of the world's total proven gas reserves. In 2010-11, the production of gas in the country was 52.22 billion cubic meters (bcm) while imports constituted 12.35 bcm.
There are two pricing regimes in the country, one under the Administered Pricing Mechanism (APM), and the other for the non-APM or free-market gas. Regarding non-APM gas, there are two categories, the first, imported Liquefied Natural Gas (LNG), and the second comprising of the domestically-produced gas from New Exploration Licensing Policy (NELP) and pre-NELP fields. NELP was launched in 1998 to increase domestic and international private investment in oil and gas. Eight rounds of auctioning have led to contracts covering 48% of Indias sedimentary basins, with discoveries of more than 600 million metric tonnes (MMT) of oil and oil equivalent gas. Although initial rounds of NELP led to a substantial number of contracts, few have reached the production stage. While the KG basin is said to have proven reserves of over 10 trillion cubic feet (tcf), current yields are around 22.7 million standard cubic meter daily (mmscmd).
Between 1997 and 2005, various committees were appointed to work out an effective pricing mechanism for gas, and administered prices were increased a few times, notably in 1992, 1997, and 2005 (although the prices remained well below costs of production). Between 2005 and 2010, APM gas prices remained frozen, with state-owned companies and the central government taking on the burden of subsidies. Since May 2010, the government has decided to increase APM prices from $1.7/million British thermal units (mmBtu) to $4.2/mmBtu. The price increase in gas is an administered increase, and has been carried out only on the upstream side.
As far as LNG imports are concerned, India started importing natural gas in 2004 with construction of LNG terminal at Dahej. India has a long-term LNG contract with Qatar's Ras Gas and also with Australia, Malaysia, Oman, and Turkmenistan. LNG prices are determined on the basis of long-term and short-term contracts, and spot purchases. For LNG imports, Qatar prices could be taken as the long-term contract prices, while prices for the rest of the world (Oman, Nigeria, Algeria, Australia, Trinidad and Tobago, Egypt, Malaysia, etc) can be taken as the spot prices prevailing during the time.
The pricing of D-6 gas was the first example of gas pricing under NELP. The gas price under NELP was discovered as a notional market price through a procedure outlined in the NELP contractual provisions. The price of APM gas is determined on a cost-plus basis and has been fixed at $ 4.2/mmBtu (inclusive of royalty) with effect from June 1, 2010. In the Northeast, the price is 60% ($2.52/mmBtu) of the APM price elsewhere.
The dual pricing system introduced by the terms of NELP is relatively complex and has led to a differentiated gas price for the country. Thus, for OIL and ONGC, the import or the production price is $4.2/mmBtu, while for the LNG long term contract (at Dahej) it is $3.12/mmBtu. For RIL, C-Fields and Panna Mukta Tapti Fields, the price is $4.215, $5.25 and $5.73/mmBtu respectively. The LNG spot price in 2010 varied between $5-6/mmBtu. Recently, for its LNG plant at Kochi, PLL signed a long-term contract for the supply of LNG from the Gorgon fields of Australia. As per the formula agreed between PLL and Ras Gas, the LNG costs $10.44/mmBtu while the supply from Gorgon fields is estimated to cost $13.62/mmBtu.
The Twelfth Plan documents suggest that over 50% of the natural gas requirement is expected to be met by imports in 2016-17. The Rangarajan Committee appointed to examine the production-sharing contract mechanism in the petroleum industry has recommended a net-back approach to gas pricing in 2012. It has suggested that since there are several sources of gas imports, the average of the net-back (calculated as the imported LNG price minus the liquefaction costs at the port minus the transportation and treatment costs of natural gas from well-head to liquefaction plant) of import prices at well-heads can be taken as the average global price for Indian imports.
The fertiliser and the power sector get priority in the allocation of domestically produced gas. From the petrochemical sector point of view, the relevant gas prices is the APM gas price which is fixed at $4.2/mmBtu for supply from KG D-6, while for supply from RIL Gandhar and Nagothane the gas price vary between $5.25-5.50/mmBtu. For Panna-Mukta and Tapti PSCs, the gas price is linked with an internationally traded fuel oil basket, with a specified floor and ceiling price of $2.11/mmBtu and $3.11/mmBtu respectively. The supply varies in the range of $5.65-5.79 /mmBtu for Panna-Mukta-Tapti fields for the petrochemical sector.
It needs mentioning that for the petrochemical sector, rich gas (containing greater ethane, propane and butane contents) is preferable. The only rich gas available in India is from Uran, which supplies gas to RIL (Nagothane), while ONGC (Gandhar and Pata) supplies to RIL (Gandhar) and GAIL (Auriya). The other user-groups such as power and fertiliser use lean gas (methane-rich). Thus, as and when greater amounts of KG-D6 gas come into the market, reallocation amongst supply sources would be desirable. Rich gas from the APM fields could be used by the petrochemical sector, while lean gas from East India (KG Basin) used by the other important end-users. Shortfall in gas in the KG-D6 basin should not, in this case, affect the availability of gas for the petrochemical sector but gas from KG-D6 could reduce the import requirement of the other sectors.
Saon Ray is senior fellow, Amrita Goldar is research associate and Swati Saluja is consultant, ICRIER