New Finds

Exploration and production scenario

India’s demand for oil and gas is only partly met by domestic production. The shortfall in supply due to limited indigenous gas production is increasingly being met by liquefied natural gas (LNG) imports. The country imports over 75 per cent of its crude oil requirement and 40-45 per cent of its gas needs. This reliance on imports renders the economy vulnerable to global adversities that impact energy markets.

However, recent times, marked by low crude prices, have been very favourable for net importing countries such as ours. Easing of sanctions by the West, commencement of crude oil imports from the US, as well as the acquisition of promising hydrocarbon assets abroad have been other pluses towards achieving energy security.

On the domestic front though, the production scenario remains grim due to a host of factors such as ageing fields, low prices discouraging investments by exploration and production companies, etc.

Indian Infrastructure examines the domestic production and supply of crude oil, natural gas and other petroleum products, and import dependencies…

Crude oil

During 2016-17, India produced 36 million tonnes (mt) of crude oil, thereby registering a slight decline over the 36.9 mt produced in the preceding fiscal year. During the first two months of the current fiscal year (2017-18), crude oil production was reportedly around 6 mt, roughly the same level recorded during the first two months of 2016-17. Considering the overall trend during the past five years (2012-13 to 2016-17), crude oil production registered a decline of 1.3 per cent.

There are several factors responsible for the low production of crude oil. Production from major fields, particularly in the western offshore and onshore fields in Gujarat and the Northeast, is low as these fields are old. Further, there has been lower-than-planned production from newly drilled wells.

Looking at a company-wise scenario, India’s largest crude oil producer, the Oil and Natural Gas Corporation’s (ONGC) output was 22.22 mt, which is 2.41 per cent lower than the target for the five-year period 2012-13 to 2016-17 and 0.63 per cent lower than the production during the corresponding period of 2015-16. The shortfall was primarily due to a delay in the deployment of the mobile offshore production unit – Sagar Samrat – in Western Offshore-16, slow progress of the Western Periphery of the MHS (ZC) project, and a natural decline in the matured fields of Western Offshore.

Another major oil producer, Oil India Limited (OIL) also reported a decline. The company produced 3.26 mt of crude oil in 2016-17, which is 6.38 per cent lower than the target for the five-year period 2012-13 to 2016-17 but 0.99 per cent higher than production during the corresponding period of the previous year (2015-16). The key reasons for the shortfall in production are the less-than-planned contribution from high producing areas like the Greater Hapjan, Shalimar, Chandmari and Moran fields and less-than-planned contribution from newly drilled wells.

Private and joint venture (JV) companies (the key ones being Cairn India, Reliance Industries Limited [RIL] and the Gujarat State Petroleum Corporation) together produced 10.53 mt, which is 2.83 per cent lower than the target for the five-year period 2012-13 to 2016-17 and 7.25 per cent lower than the production in 2015-16. The following were the reasons for the decline in production by key producers – production from Mangala (Rajasthan) was less due to liquid cutback for rectification of the 14 inch Mangala Processing Terminal-Central Polymer Facility feedwater line and a few high water cut wells being closed; poor reservoir performance of Bhagyam; Panna-Mukta platform shutdown for riser remedial work since February 2017; a natural decline in the Ravva oilfield output; and the CY-ONN-2002/2 block of the Cauvery basin being under test production. The shortfall in crude oil production is compensated for by imports, which stood at 213.9 mt in 2016-17, 5.45 per cent higher than the imports in 2015-16.

Natural gas

From 2013-14 to 2016-17, gross natural gas production declined at a compound annual growth rate (CAGR) of 3.42 per cent. In 2016-17, gross domestic gas production was 31,897 million metric standard cubic metres (mmscm), registering a decline of 1.09 per cent over the previous year.

The net natural gas production (gross gas production excluding flare and loss by gas producing companies) too witnessed a declining trend during the period under consideration (CAGR of -3.73 per cent). In 2016-17, net gas production in India was 30,848 mmscm, a decline of about 1 per cent over the previous year.

The key reasons for the decline in production are lower production from Bassein (the output from the field has seen a slight improvement in the past one year) and satellite fields, the M&S Tapti and Panna-Mukta fields; underperformance of MA wells in the Krishna Godavari (KG)-DWN-98/30 field; restricted production due to repair of pipelines in Gujarat and Andhra Pradesh; and lower offtake by potential customers, particularly in Assam, Rajasthan and Tamil Nadu.

In the first two months of 2017-18 (April-May), the gross gas production was 5,302 mmscm vis-à-vis 5,146 mmscm during the same period of the previous year. Offshore production accounted for a 51 per cent share in total domestic gas production during 2016-17 (up to December 2016). Total production from offshore fields has come down over the past few years (both from public as well as private and JV companies). Its share in total production too has come down from a high of 83.5 per cent in 2010-11. In onshore production, Rajasthan, Gujarat and Assam are the key contributing states. Two public sector companies, ONGC and OIL, dominate natural gas production, and together, they accounted for over 78 per cent of the domestic natural gas production in 2016-17. ONGC is India’s biggest gas producer.

RIL is the largest producer among private sector producers. It is also the second largest producer of natural gas after ONGC. When KG-D6 gas production was at its peak, the company had displaced ONGC’s position to become the largest gas producer. The other important producers are the British Gas-RIL-ONGC JV and Cairn.

Other petroleum products

In 2016-17, the total production of petroleum products in the country stood at 242.7 mt (provisional) – about 5 per cent higher than the 231.2 mt recorded in 2015-16. During the five years 2012-13 to 2016-17, the production of petroleum products registered a CAGR of about 3 per cent. For 2017-18 (April and May), the production of petroleum products was reported to be 40.8 mt, higher than the 39.6 mt recorded during the corresponding period of 2016-17.

India not only imports but also exports petroleum products. The total import of petroleum products for 2016-17 was 35.9 mt, significantly higher than the 29.5 mt that was registered during the preceding fiscal year. Liquefied petroleum gas imports account for over 30 per cent of the total imports. Total exports of other petroleum products in 2016-17 were 65.5 mt, increasing from 60.5 mt during 2015-16.

Exploration status

Under the New Exploration Licensing Policy (NELP) regime, a total of 360 blocks were offered for exploration. Till date, 254 production sharing contracts (PSCs) have been signed under the NELP. Of these, 114 are located onland, 58 are in offshore shallow areas and 81 in deepwater areas. Further, about 310 exploration blocks have been awarded so far under various bidding rounds (pre-NELP and NELP), 112 blocks/fields are operational, 138 exploration blocks have been relinquished and 53 blocks are in the process of being relinquished. About 15 blocks under nomination are being operated by ONGC and OIL.

The NELP bidding rounds have not only attracted public sector undertakings (PSUs), but many private and foreign companies as well. A total of 35 exploration and production companies (five PSUs, and 15 private and 15 foreign companies) were functioning in the nomination and pre-NELP regimes. After the conclusion of nine rounds of NELP bidding, the total number of companies increased to 117 (11 PSUs, 58 private and 48 foreign companies as operators and non-operators/consortium partners).

Under the nine rounds of NELP bidding held so far, the committed exploration investment is about $11.73 billion. As against this, an investment to the tune of $16.02 billion was made by the contractors for exploration activities, mainly 2D/3D seismic surveys and exploratory drilling, in the awarded blocks. In addition, a cost of about $9.71 billion has been incurred by contractors for carrying out development activities, primarily drilling and the setting up of production facilities.


The past year witnessed a number of reform and policy initiatives by the government to incentivise the exploration and production of hydrocarbons in the country. In March 2016, the government announced a more progressive exploration policy, the Hydrocarbon Exploration Licensing Policy (HELP), which replaces the NELP. HELP provides much greater flexibility and clarity on revenue sharing, along with a uniform licensing framework and an open acreage policy. Besides HELP, the government has also announced other reform measures which will benefit the exploration and production segment. Chief among these are the grant of marketing and pricing freedom, extension of PSCs for 28 small- and medium-sized discovered fields, and appraisal of about 1.5 million square km of unappraised sedimentary basins.

However, the sector will have to overcome some key challenges pertaining to the development of a comprehensive seismic data repository for all sedimentary basins; the exploration and production of unconventional hydrocarbon resources such as environmental and geological concerns, land and water availability, technological challenges, insufficient investment due to low natural gas price environment, slow development of natural gas infrastructure, etc; and low crude oil and natural gas price environment which could discourage players, particularly global companies, from investing large amounts for exploring reserves; and geological risks in terms of difficulty of extraction and the possibility that the accessible reserves are smaller than estimated.


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