Gaining Momentum

Policy and regulatory developments drive growth in the gas segment

After a hiatus of almost three years, the city gas distribution (CGD) segment has witnessed multiple regulatory interventions. The Petroleum and Natural Gas Regulatory Board (PNGRB) has reinitiated the process of awarding CGD licences by offering 14 geographical areas (GAs) in eight states and two union territories under Round 4 bidding. These are Rangareddy and Medak, Nalgonda, and Khammam (Andhra Pradesh); Ernakulum (Kerala); Bengaluru (Karnataka); Raigarh, Pune and Thane (Maharashtra); Shahjahanpur (Uttar Pradesh); Guna (Madhya Pradesh); Panipat (Haryana); Amritsar (Punjab); Daman, and Dadra & Nagar Haveli. The last date for submitting bids has been revised to July 10, 2014 from the earlier deadline of May 12, 2014.

The regulator is also expediting the issuance of licences for the third bidding round. It has already authorised Jay Madhok Energy Limited, GSPC Gas Limited and Gujarat Gas Limited to lay, build and operate CGD networks in Jalandhar, Jamnagar and Bhavnagar districts respectively. The remaining four cities under the bidding round are also expected to be authorised soon.

Another major policy move by the PNGRB was the amendment of bidding criteria in June 2013. The modified norms specify an increased share of network tariff and compression charges. Under the revised bidding criteria, the weightage of network tariffs has been increased to 70 per cent from 40 per cent, and the weightage of compression charges has been revised to 30 per cent from 10 per cent. In addition, the variation in the proposed network tariff and compression charges between two consecutive years should not exceed 10 per cent.

At the same time, no weightage has been assigned to parameters related to the inch-km of pipeline to be laid and the number of domestic connections to be provided. Instead, the PNGRB has specified the minimum works programme (MWP) for both these parameters in the first five years of operation. The MWP is based on the following formula: the target for infrastructure for piped natural gas (PNG) connections has been fixed at 5 per cent of the population for a particular GA (as against 15 per cent households in the previous guidelines); and the inch-km target has been fixed at 1.5 per cent of the GA’s total area (as against 2.696 per cent).

Further, the petroleum ministry has clarified that deemed entities do not require the PNGRB’s authorisation for setting up compressed natural gas (CNG) stations and laying spur lines in their GAs. Further, there is a need to encourage the development of green corridors to incentivise the replacement of CNG vehicles by heavy vehicles on highways.

In another positive development, the government has recently notified that the CNG and PNG requirements of the existing CGD companies should be met through domestic gas sources. The Gujarat High Court, in its November 2013 directive, issued guidelines to GAIL (India) Limited to supply gas to all CGD entities across the country at a uniform rate for domestic and commercial consumers. GAIL has executed the order for the allocation of similar proportions of CNG and PNG to all CGD entities, subject to the resolution of certain modalities for gas transmission to the different entities. Consequently, entities with a high allocation of administered pricing mechanism (APM) gas were expected to witness a reduction in their quota in a bid to reallocate APM gas among CGD entities across the country. However, Mahanagar Gas Limited’s allocated supplies could not be reduced as the taxi union in Mumbai secured a stay from the Bombay High Court against the existing gas reallocation policy. APM gas allocations to other CGD entities – Indraprastha Gas Limited and Maharashtra Natural Gas Limited – were reduced and reallocated.

Industry experts are of the opinion that although the reallocation of domestic gas would have a positive impact on the CGD segment, it will  impact non-core sectors such as steel, refineries and petrochemicals only marginally.

The gas supply scenario in India has changed during the past couple of years. The supply of natural gas, which had recorded a continuous increase since 2003-04, began to decline in 2011-12 and 2012-13. In 2012-13, the net availability of gas stood at 147 million standard cubic metres per day (mmscmd), of which domestic production accounted for 106 mmscmd and liquefied natural gas (LNG) imports for 41 mmscmd. A sharp increase in gas supply was witnessed during 2009-10 and 2010-11 due to the increased consumption requirement by power plants and fertiliser plants. These plants sourced gas from the D6 block in the Krishna-Godavari (KG) basin.

However, the decline in gas production from the KG-D6 block resulted in a decrease in supplies in 2011-12. Reliance Industries Limited’s D6 block in the KG basin has been registering a continuous fall in its gas production levels. In 2010-11, its production stood at 55.9 mmscmd, declining to 42.7 mmscmd in 2011-12. It decreased further to 26 mmscmd in 2012-13 and stood at 10-12 mmscmd in December 2013. The share of LNG imports, which stood at a little over 1 per cent in 2003-04, increased to over 27 per cent in 2012-13. LNG imports have been on the rise except for a marginal blip in LNG imports in 2008-09 when consumers decided to switch to naphtha due to a substantial decline in naphtha prices.

Earlier, in May 2012, the government set up the Rangarajan Committee to determine the basis for establishing the price of domestic natural gas. In December 2012, the committee submitted its report on the production sharing contract mechanism and gas pricing. The price of domestic gas determined as per the formula will be applicable for five years and will be revised every quarter. The revised domestic gas price is based on the trailing 12-month average of two components:

  • Weighted average of netback prices of Indian LNG term imports (excluding spot imports).
  • Weighted average of prices prevailing at the three hubs or balancing points of the major markets – the hub price at Henry Hub in the US (for North America), the price at the National Balancing Point of the UK (for Europe) and the netback price at the sources of supply for Japan.

In a recent development, the oil ministry, in a note to the Cabinet Committee on Economic Affairs, has proposed to implement the new gas pricing formula for only incremental gas production. As per the proposal, the average gas production for 2013-14 will be considered as the base level. Any excess production will qualify for higher gas prices. Also, the principle for gas pricing will be applicable to all natural gas produced locally, irrespective of the source – conventional, shale or coal bed methane.

Although industry experts are not very optimistic about the dual product pricing model, they are of the opinion that the current strategy is to incentivise production as well as prevent an increase in input costs in the power and fertliser sectors – the two key gas consuming sectors.

The hike in gas prices will drive investments in the upstream segment due to improved economics. The last revision in gas prices took place in June 2010, and the price of APM gas, which accounts for the bulk of the domestic gas produced, was raised to $4.2 per million British thermal unit (mmBtu) in the last revision. Industry experts estimate that higher gas prices will bring in investments, and increase commercial production as well as government revenues. For instance, a price of $8 per mmBtu will increase domestic gas production to 30 trillion cubic feet. The bulk of the production will come from existing producing fields, and associated gas and onshore/shallow water gas fields with a limited focus on deep-water discoveries.

An increase in gas production will also lead to an increase in supplies to the CGD segment. This will be driven by two factors: increased domestic gas production at higher prices and slow uptake of gas by the power and fertiliser sectors.

A hike in CNG and PNG prices has historically been passed on to consumers. Revised CNG prices may still be competitive for personal and commercial vehicles as against fuels such as motor spirit and high speed diesel. In the PNG segment, industrial and commercial consumers will not be impacted by a price hike as these consumer categories have been serviced mostly through more expensive LNG imports. However, PNG supplies to the domestic consumer segment may be rendered uncompetitive as compared to liquefied petroleum gas (LPG), which is available under a subsidised scheme.

Further, huge amounts of subsidy will have to be provided to the power and fertiliser sectors to compensate for price escalation due to increased input costs. To conclude, the CGD segment is expected to witness robust growth in the next few years, given that gas is the most eco-friendly and cost-efficient fuel as compared to other alternative fuels. Despite the proposed increase in prices, domestic gas will still be the most affordable option given the reduction in LPG subsidies as well as the proposed subsidy cutback for diesel.

On the operating side, issues related to asset management and distribution systems, trunkline connectivity, network safety, leakage detection, inefficient metering, etc. will have to be addressed for effective operations of the CGD network.

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