The document provides an overview of India's natural gas history and current scenario. It discusses India's limited natural gas reserves compared to its population size and growing energy needs. The document outlines the historical development of India's natural gas industry since the 1800s. It also summarizes key details on India's natural gas resource base, production, consumption trends, major projects and developments, regulations, and future prospects to meet growing demand.

1. The Gas History, Current Scenario &
Future Prospects.
Sector
2012E03 Appra Zaifrani MBA, Batch of 2012-2014.
2012E11 Karthik Madhavan Symbiosis Centre for Management
and Human Resource Development.

2. TABLE OF CONTENTS
SNo. Title Page No.
1. HISTORY AND OVERVIEW 2
2. Resource Base 3
3. OIL AND GAS COMPANIES 6 Page | 1
4. ACQUISITION OF OIL & GAS ASSETS ABROAD 7
5. PRODUCTION 11
6. The Krishna Godavari KG-D6 Field 12
7. CONSUMPTION 14
8. Major Gas Based Projects 15
9. CNG, LNG, LPG 16
10. APPLICATIONS 20
11. CURRENT INDUSTRY DEVELOPMENTS 26
12. FDI in Petroleum And Natural Gas Sector 34
13. FUTURE PROSPECTS 34
14. New Exploration Licensing Policy 35
15. IMPORT 39
16. INFRASTRUCTURE - PIPELINES 41
17. REGULATIONS & REGIME 44
18. Bhopal Disaster 49
19. Conclusion 49

3. HISTORY & OVERVIEW
The natural gas industry provides one of the cleanest burning alternative energy fuels. The oil and
gas sector plays a key role in the economic and political scenario of the globe. The limited oil and gas
reserve along with increasing energy requirement across the globe has led to spiraling of price
Page | 2 resulting in supply related concerns for countries around the world.
The structure of the natural gas industry has undergone a dramatic change over the past 15 years. In
the past, the structure of the natural gas industry was simple, with limited flexibility and few options
for natural gas delivery. Exploration and production companies explored and drilled for natural gas,
selling their product at the wellhead to large transportation pipelines. These pipelines transported
the natural gas, selling it to local distribution utilities, which in turn distributed and sold that gas to
its customers. The prices for which producers could sell natural gas to transportation pipelines was
federally regulated, as was the price at which pipelines could sell to local distribution companies.
State regulation monitored the price at which local distribution companies could sell natural gas to
their customers.
The high economic growth in the past few years and increasing industrialization have created a lot of
concern for India’s energy scenario. India has 0.5% of the oil and gas resources of the world and 15%
of the world’s population. This makes India heavily dependent on the import of the crude oil and
natural gas. India’s crude oil production has not shown significant growth in the last 10 or more
years whereas its refining capacity has grown by more than 20% over the last 5 years. Oil
consumption is growing at approximately 4.1% per year and natural gas consumption at 68% per
year.
The fact that India has not made any major breakthroughs in the field of renewable sources of
energy, oil and natural gas would continue to hold a place of key importance in India’s economy.The
prospects of Indian oil industry are for more exciting than any other, which India being among the
least explored countries in the world at a well density of 20 per 10000 km2. India is the third largest
oil consumer in Asia, even though on per capita basis the consumption is mere 0.1 tons per year, the
lowest in the region. Of the 26 sedimentary basins only eight have been explored so far. All this
makes India the desired destination in terms of opportunities.
India had 38 trillion cubic feet (Tcf) of proven natural gas reserves as of January 2007.The total gas
production in India was about 31,400 mcm in 2002-03 compared with 2,358 mcm in 1980-81. At this
production level, India's reserves are likely to last for around 29 years; that is significantly longer
than the 19 years estimated for oil reserves. Almost 70% of India’s natural gas reserves are found in
the Bombay High basin and in Gujarat. Offshore gas reserves are also located in Andhra Pradesh
coast (Krishna Godavari Basin) and Tamil Nadu coast (Cauvery Basin). Onshore reserves are located
in Gujarat and the North Eastern states (Assam and Tripura).
The search for oil in India began way back in 1866 in Upper Assam. While oil was struck at Digboi in
1889 marking the beginning of oil production in India, discoveries were made in Nahorkatiya and
Moran oilfields in the late 1950s and early 60s in the north-eastern region. In view of the growing
demand of crude oil, the Government formed Oil & Natural Gas Commission (ONGC) in 1956 to
boost the exploration of oil and gas in the country. ONGC made the first discovery in 1958 in the
Cambay onshore basin in Gujarat. During the 1960s, oil production in the country was confined to
only Assam and Gujarat.
Gas demand was very low until the 1970s but started to pick up when ONGC’s Bombay High started
producing in 1974 which opened up a new vista for oil and gas exploration and production in India.

4. Subsequently, more discoveries were made in the Krishna-Godavari, Cauvery and Rajasthan
sedimentary basins. While the responsibility of carrying out exploration and production activities in
the country was entrusted to the national oil companies (NOCs) almost till the beginning of 1990’s,
wherein they used to be granted the Petroleum Exploration License (PEL) on nomination basis, the
Centre’s liberalised economic measures opened up a few acreages to private and joint venture
companies through various exploration bidding rounds for development of discovered fields.
Page | 3
RESOURCE BASE
India has 26 sedimentary basins with an area of 3.14 million sq. km. Considering the entire 3.14
million sq km of sedimentary area, inland as also shallow and deep offshore in the country, the
resource base of hydrocarbons is estimated to be about 29 billion tonnes of oil and oil equivalent gas
(O+OEG). Out of this, only 6.8 billion tonnes of in-place hydrocarbon has so far been established
through exploration.
The sedimentary area covering Assam, Gujarat and Rajasthan (onshore), Mumbai High (offshore)
and Krishna – Godavari and Cauvery (onshore and offshore) wherefrom oil and gas are commercially
produced, fall in Category I basin. The total area in these basins is about 0.52 million sqkms, i.e.,
about 17 per cent of the entire sedimentary area. There is no commercial production from the other
sedimentary basins that constitute about 83 per cent of the total sedimentary area. Based on their
hydrocarbon potential, these basins are classified as category-II (i.e. basins having hydrocarbon
indications without any commercial production), category-III (i.e. basins, which on geological
considerations are assumed to be prospective) and category-IV (basins, which on analogy with
similar producing basins in the world are deemed to be prospective) basins. Owing to its risk-reward
perspectives, different basins or parts of the same basin, are in different stages of exploration. The
areas that were to be brought under active exploration, inter alia, include logistically difficult and
geologically complex regions. The perceived geological risk involved in carrying out the exploration
for hydrocarbons in these areas is rather high. Thus, in order to expose these areas to active
exploration requires huge financial investment and induction of high technologies. The order of
investment required in the upstream sector in the next 15 years is estimated to be about US$ 60
billion.
The Indian gas market is expected to be one of the fastest growing in the world over the next two
decades: the IEA forecasts gas demand to increase at 5.4% per annum over 2007-30 (IEA, 2009)
reaching 132 bcm by 2030. Indian primary energy supply is currently dominated by coal (37%),
biomass and waste (27%) and oil (26%) while the share of natural gas is only 6%. Natural gas use in
India really started to grow in the late 1970s after the first major gas finds in the western offshore
and the development of the first transmission pipeline in the northern region.
Before 2009, gas demand potential was estimated to be 20 or 30 bcm higher than actual use as
consumption had been constrained by the lack of supply for over a decade (MoPNG, 2000). To
address the supply shortfall, the Indian government passed some reforms at the end of the 1990s to
encourage domestic production and the construction of liquefied natural gas (LNG) terminals. In
particular, the New Exploration Licensing Policy (NELP) opened Exploration & Production to private
and foreign companies. This has been relatively successful: after stagnating since the early 2000s,
Indian gas production is expected to double between 2008 and 2011 due to the start of the Krishna
Godavari KG-D6 field in April 2009. The year 2009 therefore marks a turning point for the Indian gas
market: with new supplies available, Indian gas consumption increased to 59 bcm in FY 2009/10,
from 43 bcm in FY 2008/09.1. Meanwhile, a third LNG terminal is expected to start in 2010. But
challenges remain, illustrated by NELP’s failure to attract the major international oil companies and

5. the long battle over the allocation and price of KG-D6 gas. The government is now considering
introducing an Open Acreage Licensing Policy (OALP).
The potential for growth of the natural gas market in India is tremendous; however, this is a very
price sensitive market as the ability of customers to pay differs between sectors. The power
generation and fertiliser sectors are the main consumers. Fertiliser producers are subsidised by the
Page | 4
government and have limited ability to absorb higher prices. In the power generation sector, gas has
to compete against coal for base-load generation. Any change in the power sector or in coal markets
will have a huge impact on whether gas is used as a base-load option or for peak purposes, and
therefore on future gas demand in the power sector. City gas and industrial users show greater price
flexibility, but they are still emerging markets. Historically, gas had been allocated in priority to
fertiliser and power plants, while city gas, compressed natural gas (CNG) and industrial had the
remainder. Furthermore, fertiliser producers and power generators were allocated gas at low
Administrative Price Mechanism (APM) prices determined by the government. But the recent pricing
reforms that took place mid-2010 mean the end of low APM prices, and that new gas supplies are
likely to be more expensive.
The Indian gas sector, like the whole energy sector, is dominated by state-owned companies. Oil and
Natural Gas Corporation (ONGC) and Oil India Ltd (OIL) have dominant upstream positions, while
until 2006; Gas Authority of India Ltd (GAIL) alone had been responsible for pipeline gas transport.
The state has also a very important role in the regulatory framework and gas policy, in particular the
allocation and pricing of gas. Recent reforms have brought more private investors in the upstream
and downstream sectors, but a more transparent regulatory framework will be critical to incentivise
future private investments.
The Indian gas market is therefore at a crossroads in 2010. Despite the dramatic increase of
domestic production, last year has witnessed a tough battle over the allocation and the pricing of
KG-D6 gas, which could have far-reaching consequences for many stakeholders. In order for the
Indian gas market to reach its potential, there are still many hurdles to be solved on pricing, supply,
infrastructure, regulation and policy.
Gas pricing: India has a rather unusual dual gas pricing and supply policy, with APM gas produced by
state-owned companies and non-APM gas from private companies and joint ventures (JVs). Until
May 2010, prices differed widely from around USD 2/MBtu for APM gas to almost USD 6/MBtu for
the most expensive non-APM gas. Such a gap was pushing towards changes. Increasing private
supply of gas has been indeed a major policy challenge for the government as the pooling of gas
prices was limited by the declining availability of APM gas. Moreover, any effort to keep domestic
gas prices low would act as a disincentive for more upstream investment.
Two major changes took place in May 2010. APM prices were increased from USD 1.8/MBtu to USD
4.2 MBtu, and ONGC and OIL were allowed to market gas discovered in new fields allocated to them
at market prices. This decision will have consequences for producers, and is an important step
forward in order to encourage further investments in the upstream sector. Furthermore, if India
wants to attract additional LNG in the long term, it would have increasingly to compete on global gas
markets at prices potentially higher than the current ones. Meanwhile, the Supreme Court
announced its verdict on the five-year battle between Reliance Industry (RIL) and Reliance Natural
Resources (RNRL) regarding the price at which RIL was to sell its KG-D6 gas to RNRL: the Court
decided that only the government had the right to fix the price in the Production Sharing Contract
(PSC) (fixed at USD 4.2/MBtu) when an arm-lengths price is impossible to find. It remains to be seen
whether or not such a decision could deter private or foreign upstream investment. Pricing is also
key for the demand side due to some sectors’ limited ability to absorb high prices: gas-fired plants

6. compete with coal-fired plants while fertiliser producers depend on international urea price and
government subsidies. A market approach based on comparison with alternative fuels should be
taken.
Insufficient supplies: The bulk of India’s supplies is produced domestically but demand for gas is
increasing while production from the old fields has been dwindling. While most gas production used
Page | 5
to be produced by state-owned companies, this is changing rapidly: JVs and private companies
represent an increasing share of domestic production. Although domestic production will double
between 2008 and 2012, developing domestic gas resources is critical to increase supplies to the
Indian market. Even if NELP has resulted in a certain number of discoveries, including the major
Krishna Godavari KG-D6 field, it also has some shortcomings. India is also likely to see imports
increasing over the next two decades. Although India is also located near significant resources of gas
in Turkmenistan and Iran, pipeline interconnections remain a distant prospect. India has been
turning to LNG instead and is building new regasification terminals, adding to existing capacity.
Future supplies in the coming five years will therefore continue to be based on two sources:
domestic production and LNG imports.
Regulation and policy:The challenges faced by the Indian energy sector and by the gas sector in
particular are tremendous. Insufficient supplies remain a policy issue despite a relative
improvement. Meanwhile, the downstream gas market is quite underdeveloped so that significant
investments will be needed in order to give access to gas to more consumers. This implies attracting
investments from both public and private companies; private companies will require a stable and
transparent regulatory framework and an equal treatment compared to state-owned companies.
The Petroleum and Natural Gas Regulatory Board (PNGRB) Act, 2006 is a step in the right direction
but needs to be further enhanced.The recent decision of the Delhi High Court, in early 2010, puts
PNGRB’s role in question and casts new uncertainties on the regulation of downstream gas markets.
Transmission/Infrastructure:India is a vast country and the pipeline network has been developed
mostly in the northwest region. In 2008, a pipeline was built to link a new production region in the
East to the existing network. In order to further develop the use of gas, it is critical to extend the
transmission infrastructure to supply new cities and develop distribution networks. In both cases,
the regulatory framework, in particular transport tariffs, should give adequate incentives for the new
infrastructure to be built.
This IEA Working Paper aims to provide a detailed yet non-exhaustive overview of the Indian gas
market, highlighting the current challenges. It first looks at the industry structure, presents the main
players from industry as well as government, and gives an overview of the regulatory framework.
The issue of pricing remains crucial for both upstream and downstream development. For this
reason, this Working Paper analyses both supply – domestic production and LNG imports – and
demand.
X 1990 2000 2008 2009
Share in TPES (%) 3 5 6 Na
Domestic production (bcm) 12 28 32 46
LNG imports (bcm) 0 0 11 12
Pipeline imports (bcm) 0 0 0 0
Consumption (bcm) 12 28 42 59
% of power generation 37 44 40 Na
% of industry 59 44 47 Na

7. OIL & NATURAL GAS COMPANIES
ONGC Oil and Natural Gas Corporation Ltd. (ONGC)is engaged in E&P activities both in Onshore and
Offshore. The Corporation is now venturing out to new areas i.e. deepwater exploration and drilling,
exploration in frontier basins, marginal field development, optimization of field development plan
Page | 6 field recovery and other allied areas of service sector.
Indian Oil Corporation Limited. 18th largest petroleum company in the world and has a current
turnover of `247,479 crore (US $59.22 billion), and profit of `6963 crore (US $ 1.67 billion) for fiscal
2007. The IndianOil Group of companies owns and operates 10 of India's 19 refineries with a
combined refining capacity of 60.2 million metric tonnes per annum (MMTPA, .i.e. 1.2 million barrels
per day). These include two refineries of subsidiary Chennai Petroleum Corporation Ltd. (CPCL) and
one of Bongaigaon Refinery and Petrochemicals Limited (BRPL).
Cairn Energy Cairn is an Edinburgh-based oil and gas exploration and production company listed on
the London Stock Exchange since 1988. There are two arms to the business: Cairn IndiaIndia is an
autonomous business listed on the Bombay Stock Exchange and the National Stock Exchange of India
and has interests in a total of 14 blocks in India and Sri Lanka and Capricorn.
Oil India Limited Oil India Limited (OIL) is a premier National oil company, engaged in the business
of exploration, production and transportation of crude oil and natural gas. Oil India Limited is a
"Schedule A" company under the Ministry of Petroleum and Natural Gas, Government of India.
HPCL is a Fortune 500 company, with an annual turnover of over ` 1,03,837 Crores ($ 25,142
Millions) during FY 2007-08, 16% Refining & Marketing share in India and a strong market
infrastructure. Corresponding figures for FY 2006-07 are: ` 91,448 crores ($20,892 Million). The
Corporation operates 2 major refineries producing a wide variety of petroleum fuels & specialties,
one in Mumbai5.5 MMTPA capacity and the other in Vishakapatnam, (East Coast) with a capacity of
7.5 MMTPA. (West Coast) of
Engineers India Limited was established in 1965 to provide engineering and related technical
services for petroleum refineries and other industrial projects. In addition to petroleum refineries,
with which EIL started initially, it has diversified into and excelled in other fields such as pipelines,
petrochemicals, oil and gas processing, offshore structures and platforms, fertilizers, metallurgy and
power. EIL now provides a range of project services in these fields and has emerged as Asia's leading
design and engineering Company.
BPCL Bharat Petroleum Corporation Limited engages in refining, storing, marketing, and distributing
petroleum products in India. It also involves in the exploration and production of hydrocarbons. The
company offers various products, including liquefied petroleum gas (LPG), naphtha, motor spirit,
special boiling point spirit/hexane, benzene, toluene, polypropylene feedstock and more.
GAIL (India) Limited GAIL (India) Limited operates as a natural gas company in India and
internationally. The company involves in the exploration, production, processing, transmission,
distribution, and marketing of natural gas. It also offers LPG and other liquid hydrocarbons, and
petrochemicals. The company owns approximately 5,800 kilometers of natural gas high pressure
trunk pipeline.
Reliance The Reliance Group was founded by Dhirubhai H. Ambani (1932-2002). The group's annual
revenues are in excess of US$ 34 billion. The flagship company, Reliance Industries Limited, is a
Fortune Global 500 company and is the largest private sector company in India.

8. The Company's operations can be classified into four segments namely:
Petroleum Refining and Marketing business
Petrochemicals business
Oil and Gas Exploration & Production business
Others Page | 7
Adani Group has forayed into the Oil & Gas sector and has been awarded two oil & gas blocks in
Gujarat and AssamGujarat and another block with an area of 95 sq. kms. is situated in Assam. under
the recently concluded NELP VI and also plans to participate in the upcoming NELP VII bids and is
actively looking at oil and gas blocks overseas. One Block with an area of 75 sq. kms is situated in
Cambay,
Simon Carves as a part of its offshore development, projects have been carried out in India and
Indonesia in providing oil and natural gas development facilities. In gas processing they have carried
out projects in Singapore, Indonesia and India in providing natural gas processing facilities and gas
field developments. A key part of many of these projects is the provision of pipeline and tanks where
in conjunction with Punj Lloyd they have considerable expertise in the design and construction of
these facilities in often very difficult environments.
Petronet LNG Limited, one of the fast growing companies in the Indian energy sector, has set up the
country's s first LNG receiving and regasification terminal at Dahej, Gujarat, and is in the process of
building another terminal at Kochi, Kerala. The Dahej terminal has a nominal capacity of 5 million
metric tonnes per annum (MMTPA) [equivalent to 20 million standard cubic meters per day
(MMSCMD) of natural gas], the Kochi terminal will have a capacity of 2.5 MMTPA (equivalent to 10
MMSCMD of natural gas)
ACQUISITION OF OIL & GAS ASSETS ABROAD
ONGC VIDESH LIMITED
ONGC Videsh Limited (OVL) was rechristened on 15th June 1989 from the erstwhile Hydrocarbons
India Private Limited, which was incorporated on 5th March, 1965. Over a period of time, OVL has
grown to become the second-largest E&P Company in India both in terms of oil production and oil
and gas reserve holdings. The primary business of OVL is to prospect for oil and gas acreages abroad
including acquisition of oil and gas fields, exploration, development, production, transportation and
export of oil and gas. OVL is a wholly-owned subsidiary of Oil and Natural Gas Corporation Limited
(ONGC) - the flagship national oil company of India.
Starting with the exploration and development of the Rostam and Raksh oil fields in Iran and
undertaking a service contract in Iraq, a major breakthrough was achieved by OVL in 1992 in
Vietnam with the discovery of two major free gas fields, namely LanTay and LanDo, in partnership
with British Petroleum and Petro-Vietnam. The success carried on thereafter. In 2001, OVL acquired
20% stake in Sakhalin-1 project in the far east of Russia. In January 2009, OVL completed the
acquisition of Imperial Energy Corporation Plc – a UK based Company having its exploration and
production assets in Tomsk region of Western Siberia, Russia with an investment of over USD
2.1billion.

9. The company, adopting a balanced portfolio approach, maintains a combination of producing,
discovered and exploration assets, working as operator in 17 projects and joint operator in 5
projects. OVL produces hydrocarbons from its 9 assets, namely, Russia (Sakhalin-I and Imperial),
Syria (Al-Furat Project), Vietnam (Block 06.1), Colombia (Mansarover Energy Project), Sudan (Greater
Nile Oil Project and Block 5A), Venezuela (San Cristobal Project) and Brazil (BC-10); 6 projects are in
development phase and 23 are in the exploration phase. OVL‟s international oil and gas operations
Page | 8
produced 8.87 MMT of O+OEG in 2009-10 as against 0.252 MMT of O+OEG in 2002-03. OVL‟s
overseas cumulative investment has crossed USD 10 billion.
OVL currently owns assets in CIS & far-east, Middle-East, Africa and Latin America.
Vietnam:
Block 06.1 is an offshore Block located 370 km south–east of Vung Tau on the southern Vietnamese
coast with an area of 955 sq. km. OVL with 45% PI, British Petroleum (Operator) with 35% PI and
PetroVietnam, a Vietnamese Government-owned entity with 20% PI, have developed the Lan Tay
field in the Block. The field started commercial production in January, 2003. During 2009-10, OVL‟s
share of production from the project was 1.967 BCM of gas and 0.042 MMT of condensate as
compared to 1.848 BCM of gas and 0.046 MMT of condensate during 2008-09. OVL’s share of the
development expenditure was approx. USD 230 million till 31st March, 2010.
Block 127 is an offshore deep-water Block, located at water depth of more than 400 meters with
9,246 sq km area in Vietnam. The PSC for the Block was signed on 24th May, 2006. OVL holds 100%
PI in the Block with Operatorship. Exploration was done in July 2009 to a depth of 1265 metres and
no hydrocarbons presence was detected. As there was no hydrocarbon presence, the Company has
decided to relinquish the block to PetroVietnam. The Company has invested approx. USD 68 million
till 31st March, 2010.
Block 128 is an offshore deep-water Block, located at water depth of more than 400 meters with
7,058 sq km area in Vietnam. The PSC for the Block was signed on 24th May, 2006. OVL holds 100%
PI in the Block with Operatorship. A well had been identified and the rig was deployed on the
location in September 2009. The well could not be drilled with the rig as it had difficulty anchoring
on the location. The drilling activity was terminated and it is planned that the location shall be drilled
in 2011. The Company has invested approx. USD 45 million till 31st March, 2010.
Myanmar:
In Myanmar OVL owns 5 blocks. OVL is participating in the complete hydrocarbon exploration,
production and transportation chain comprising combined Upstream Field development of A-1 and
A-3 Blocks, Offshore Pipeline JV Company and Onshore Pipeline Company. OVL also holds a stake in
Shwe Offshore Pipeline Joint Venture Company (PipeCo-1) and PipeCo-2 also. As per current
estimates, OVL’s share of investment jointly for Blocks A-1 and A-3 including Pipeco-1 & 2 projects is
estimated at about USD 1 billion. OVL acquired three offshore deep-water exploration Blocks i.e. AD-
2, AD-3 and AD-9 on 23rd September, 2007 in Myanmar. OVL is the operator with 100% PI in all the
three Blocks. The Company has invested approx. USD 24 million in the Blocks till 31st March, 2010.
Russia:
Sakhalin-1 - a large oil and gas field Far East offshore in Russia. OVL acquired stake in the field in July,
2001. OVL holds 20% PI in the field.The maximum net cash sink for investment in this project was
approved at USD 1,556 million.
OVL acquired Imperial Energy Corporation Plc., an independent upstream oil Exploration and
Production Company having its main activities in the Tomsk region of Western Siberia, Russia on
13th January, 2009 at a total cost of USD 2.1 billion. Imperial’s interests comprise of seven blocks in

10. the Tomsk region. As on 1st April 2010, OVL’s share of 2P reserves in the project was 112.871 MMT
(O+OEG). The Company has invested approx USD 2,335 million till 31st March 2010 in the project.
Iran:
Farsi Offshore Exploration Block: Farsi is an offshore exploration Block spread over 3,500 sq km in
Persian Gulf Iran. The contract for the Block was signed on 25th December, 2002. OVL holds 40% PI.
Page | 9
OVL’s share of investment was approx USD 36 million till 31st March, 2010.
Iraq:
OVL is the sole licensee of Block-8, a large inland exploration Block in Western Desert, Iraq spread
over 10,500 sq. km. The Exploration & Development Contract (EDC) for the Block was signed on 28th
November, 2000. The Company has invested approx USD 2 million till 31st March, 2010 in the
project.
Syria:
ONGC Nile Ganga BV (ONGBV) and Fulin Investments Sarl, a subsidiary of China National Petroleum
Company International (CNPCI), hold 33.33% to 37.5% PI in four Production Sharing Contracts (PSCs)
comprising 36 producing fields in Syria. The acquisition was completed on 31st January, 2006. OVL
had advanced approx USD 223 million towards cost of acquisition. OVL’s share in the oil production
was 0.718 MMT during 2009-10 as compared 0.812 MMT during 2008-09.
Block-XXIV, measuring about 3,853 sq km is an on-land Block located in the central eastern part of
Syria. The contract for the Block was signed on 15th January, 2004. OVL holds 60% PI in the Block
with IPR Mediterranean Exploration Ltd. OVL incurred a capital expenditure of approx USD 29 million
till 31st March, 2010.
Africa & Latin America
In the African continent, OVL has acquired assets in Egypt, Libya, Sudan and Nigeria. In Latin
America, OVL owns assets in Venezuela, Cuba, Brazil and Colombia.
Source: OVL
BHARAT PETROLEUM CORPORATION LIMITED
BPCL entered the upstream sector in 2003 with the aspirations of reasonable supply security of
crude, hedging of price risks, to become a vertically integrated oil company and to add to BPCLs
bottom-line.
Creation of BPRL:
Considering the need for a focused approach for E&P activities and implementation of the
investment plans of BPCL at a quicker pace, a wholly owned subsidiary company of BPCL, by the
name Bharat PetroResources Limited (BPRL) with an authorized share capital of ` 1000 Crores was
incorporated in October 2006, with the objective of carrying out Exploration and Production
activities.
The first overseas onshore block was awarded to the BPCL consortium in Oman in June 2006.
Subsequently, 1 offshore block in Australia and 1 offshore block in the Joint Petroleum Development
Area (JPDA) between Australia and East Timor were also awarded to the BPCL consortium. Also, 2
blocks have been acquired through the Farm-in process (1 offshore block in Australia in 2006 and 1
shallow water block in the North Sea in early 2007). Further, BPRL has bid successfully for an
offshore acreage in the North Sea (UK) in 2008. BPRL and M/s Videocon Industries Limited (VIL)

11. jointly bid successfully for the acquisition of 10 deep water exploration blocks (across 4 concessions)
in offshore Brazil. These blocks were held by M/s EnCana Corporation, Canada, through their affiliate
M/s EnCana Brazil PetroleoLimitada (EnCana). In December 2008, BPRL farmed into an offshore
block in Mozambique with 10% PI, and in January 2010, farmed into an offshore block in Indonesia.
All the above blocks are in various stages of Exploration. BPRL consortium has drilled 6 wells in 2009,
Page | 10
and is planning to drill 12 wells in 2010. A discovery has been announced in the Campos basin in
Brazil and also in offshore Mozambique. BPRL has partnerships with some world renowned
Operators including Petrobras and Anadarko.
INDIAN OIL CORPORATION LIMITED
IndianOil is the highest ranked Indian company in the latest Fortune Global 500listings, ranked at the
125th position. IndianOil's vision is driven by a group of dynamic leaders who have made it a name
to reckon with. Its business strategy focuses primarily on expansion across the hydrocarbon value
chain, both within and outside the country. To enhance upstream integration, IndianOil has been
pursuing exploration & production activities both within and outside the country in collaboration
with consortium partners.
The overseas portfolio includes eleven blocks spanning Libya, Iran, Gabon, Nigeria, Timor-Leste,
Yemen and Venezuela. IndianOil is associated with two successful discoveries in oil exploration
blocks, one each in India and Iran. IndianOil also farmed into an exploration block in Gabon along
with Oil India Ltd. (OIL) as the operator. In addition, the IndianOil-OIL combine has acquired
participating interest in a block in Nigeria. The Corporation, in consortium with OIL, Kuwait Energy
and Medco Energy of Indonesia has acquired a participating interest in two exploration blocks in
Yemen. As part of consortium, IndianOil has been awarded Project -1 in the Carabobo heavy oil
region of Venezuela. To boost E&P activities, IndianOil has incorporated Ind-OIL Overseas Ltd. – a
special purpose vehicle for acquisition of overseas E&P assets – in consortium with Oil India Ltd.
RELIANCE INDUSTRIES LIMITED
In April 2010, RIL entered into a joint venture with the USA based Atlas Energy, Inc. (Atlas) under
which RIL acquired 40% interest in Atlas‟ core Marcellus Shale acreage position. RIL has become a
partner in approximately 300,000 net acres of undeveloped leasehold in the core area of the
Marcellus Shale region in south-western Pennsylvania for an acquisition cost of $ 339 million and an
13 additional $ 1.36 billion capital costs This joint venture will materially increase RIL‟s resource
base and provide an entirely new platform from which to grow its exploration and production
business while simultaneously enhancing its ability to operate unconventional projects in the future.
Additionally, RIL has farmed out 20% PI in the blocks Borojo North and Borojo South in Colombia
30% PI in block 18 and 25% PI in block 41 in Oman. RIL now has 13 blocks in its international E&P
portfolio including 2 in Peru, 3 in Yemen (1 producing and 2 exploratory), 2 each in Oman, Kurdistan
and Colombia, 1 each in East Timor and Australia; amounting to a total acreage of over 93,500 sq.
kms.
OIL INDIA LIMITED
Keeping in perspective the Indian Government’s liberalisation policy and the dismantling of the
Administered Pricing Mechanism, OIL expanded its business activities both within and outside the
country, adding hydrocarbon related ventures like gas based power generation to its portfolio.

12. OIL is actively pursuing opportunities to acquire producing E&P assets, exploration acreages, etc. in
Africa, Middle East, South East Asia, South America, CIS countries and Russia, and is willing to
associate with reputed companies to jointly fulfil this objective.
PRODUCTION
Page | 11
Proven and indicated reserves of natural gas in India were 1 074 bcm as of 1 April 2009,slightly up
from 1 050 bcm as of April 2008. The vast majority (787 bcm) represents offshore gas(287 bcm is
onshore) according to the Ministry of Petroleum and Natural Gas.Exploration anddevelopment
drilling in India is significant as domestic production has grown from 12 bcm in theearly 1990s to
levels around 30 bcm since 2000, before increasing dramatically during 2009. Thefiscal year
2008/097 saw the drilling of 122 exploratory wells and 250 development wellsworking with total
metreage of 888 000 m, the highest levels in last five years.
Domestic net gas production by region:
Production has been almost flat at 30-32 bcm since 2002, but jumped to 46 bcm in 2009/10.Around
three quarters of the gas production came from the Western offshore area. The shareof offshore
production increased to 80% in 2009/10. Fields located in Gujarat, Assam andAndhra Pradesh are
the major sources of onshore gas. Smaller quantities of gas are alsoproduced in Tamil Nadu, Tripura
and Rajasthan as can be seen in Figure 1, but this changed dueto the start of the offshore eastern
coast Krishna Godavari (KG) field in April 2009.Despite a relatively long E&P history, one major issue
concerns the fact that no full geologicalsurvey of the sedimentary basins has been completed . This
issue, which isrecognised by the government, is nevertheless critical to attract investors.

13. Page | 12
As already mentioned, ONGC and OIL are the two dominant players with private companiesplaying
an increasing role. All natural gas produced from existing fields in nominated blocks ofONGC and OIL
is treated as Administered Pricing Mechanism (APM) gas. However, both ONGC andOIL will now be
allowed to sell any production from new fields in their blocks at market prices thatare set and
approved by the government to encourage the two companies to invest in upstreamdevelopment
(see previous section on pricing). Meanwhile JV gas from allocated fields beforeNELP is sold at
“market prices”, set and approved by the government. Gas production by JVs andprivate companies
has been increasing, a trend likely to continue over the upcoming years.The recent major
development is the Krishna Godavari KG-D6 (block DWN-98/3) field operatedby Reliance Industries
Ltd. (RIL). The field is located in the Bay of Bengal off the eastern coast ofIndia and produced 14 bcm
in FY 2009/10. As of early 2010, it has reached a production level of60 Mcm/d (22 bcm/y) and is
expected to reach an annual plateau production of 30 bcm by2012, similar to India’s domestic
production level over the past decade.
THE KRISHNA GODAVARI KG-D6 FIELD
The major upstream development over the past few years is the start of the deep-waterKrishna
Godavari KG-D6 (block DWN-98/3) field operated by RIL. It was discovered in 2002,began producing
in April 2009, and its potential is estimated at 337 bcm (11.9 tcf) (DGH). RILowns 90% and Canadian
Niko Resources the remaining 10%. Initially, production was expectedto increase by an additional 10
Mcm/d each month up to 40 Mcm/d by July 2009 and to reach aplateau production of 80 Mcm/d
only by 2011-12 – the equivalent of 29 bcm of annualproduction, which would double India’s current
production. It was then expected to plateauand dwindle from 2017 to 2020. However, potential
production of 60 Mcm/d was reached inJuly 2009, although the field did not produce this amount of
gas until early 2010 due to the lackof offtakers. Discussions on gas allocation are anticipating a
production up to 90 Mcm/d(33 bcm/y), but recent trends seem to indicate that production would
remain flat for anotheryear and that the plateau level of 80 Mcm/d (29 bcm/y) would be reached
only in 2012.

14. There are nevertheless two issues affecting KG-D6 field production: one relates to
governmentdecisions on the allocation and price of the gas, and the other to the legal dispute
between theAmbani brothers, MukeshAmbani who owns Reliance Industry (RIL) and Anil Ambani
who ownsReliance Natural Resources (RNRL). It ended in May 2010 with the ruling of the Supreme
Court.
Page | 13
The Allocation Of KG-D6 Gas
Gas is to be sold according to the Indian gas policy reflecting recent decisions on volumes andend-
consumers. The gas produced during Phase I (40 Mcm/d) would therefore be allocatedwith the
following priority and volumes.
• Fertiliser companies: 15 Mcm/d
• Existing gas-fired power plants and plants to be commissioned before April 2010: 18 Mcm/d
• LPG and Petrochemical plants: 3 Mcm/d
• City gas distribution: 5 Mcm/d.
Allocation of KG-D6 Gas
For the first 40 Mcm/d, Reliance had initially contracts to sell gas to 15 fertiliser manufacturers,19
power plants and 3 steel companies. It had also signed a sale and purchase agreement withGAIL for
its LPG plant and with Indraprastha Gas for city gas for 0.3 Mcm/d to be increased to0.5 Mcm/d by
March 2010 and 2.1 Mcm/d within five years. During the first months ofproduction in 2009, RIL had
been forced to cap output, as close to one-fourth of the initialallocations were not taken. Customers,
such as state power utility National Thermal PowerCorporation (NTPC), Gail, Essar Power, and
Ratnagiri Gas and Power, were not taking theirallocated quantities or are taking very irregular
quantities which could threaten the field’soperations. Ratnagiri was not taking the 2.7 Mcm/d for
which it signed up because it hadcontracted to buy regasified LNG from Petronet LNG through
September 2009.
The decision on further allocations has been made by the EGoM in November 2009; RIL willincrease
output to 60 Mcm/d and sell another 30 Mcm/d on an interruptible basis. The finalallocation of RIL’s
gas is given in Table 5. The dramatic increase of gas use in the powergeneration sector is a clear
result of this (see section on demand). Fertilisers have been alsoswitching from expensive oil
products to gas. A slower than expected ramp-up ofKG-D6 production would have an impact on
customers allocated interruptible supplies.

15. CONSUMPTION
Current Energy Production 16,385.61 MW
INDIA’S GAS USE
Page | 14
GAS DEMAND PROJECTION
Problems with Natural Gas -
Not a renewable source of energy.
India has only limited reserves of natural gas, though further discoveries are being made
from recent explorations
Owing to the high percentage of methane in natural gas, it is highly combustible
The process of extraction of natural gas involves making large cavities in the ground. Natural
gas requires highly complex treatment plants and pipelines for its delivery.
Natural gas occupies four times the space of gasoline-equivalent energy.

16. MAJOR GAS BASED PROJECTS
Project State Commissioned Capacity (MW)
RGPPL, Anjanvel, Maharashtra 1480
Dadri, Uttar Pradesh 817
Paguthan, Gujarat 654.73 Page | 15
Auraiya, Uttar Pradesh 652
Jhanor-Gandha,r Gujarat 648
Kawas, Gujarat 645
Faridabad, Haryana 430
Anta, Rajasthan 413
Vemagiri Power Generation Ltd., Andhra Pradesh 388.5
Rajiv Gandhi CCPP, Kayamkulam, Kerala 350

17. Page | 16
LNG – LIQUIFIED NATURAL GAS
LNG is a clear, colorless, non-toxic liquid that can be transported and stored more easily than natural
gas because it occupies up to 600 times less space.When LNG reaches its destination, it is returned
to a gas at regasification facilities. It is then piped to homes, businesses and industries.
LNG Terminal Capacity (MMTPA)
Dahej 5
DahejExp 5
Kochi 2.5
Shell Hazira 2.5
Dabhol 2.5
Mangalore 5
Kakinada 2.5
Total 25
LNG IMPORTS

18. CNG – COMPRESSED NATURAL GAS
Compressed Natural Gas, or CNG, is quite simply gas that has been compressed such that it can be
transported in pressure vessels rather than by pipeline as is the traditional method. CNG is generally
used to fuel transit and fleet vehicles in large cities, as well as in a limited number of personal
Natural Gas Vehicles (NGVs).
Page | 17
Scenario
In India CNG is primarily used as an alternative fuel for transportation.The Table Summarizes the
LNG activities in India in terms of stations, growth in vehicles etc.
LPG - LIQUEFIED PETROLEUM GAS
Liquefied petroleum gas is one of the most common and an alternative fuels used in the world
today. Liquefied petroleum gas is also called as LPG, LP Gas, or Auto gas. The gas is a mixture of
hydrocarbon gases used as a fuel for various purposes. This is mainly used in heating appliances and
vehicles and is replacing chlorofluorocarbons as an aerosol propellant. It is also used as a refrigerant
mainly to reduce damage to the ozone layer.

19. When gas is drawn from the earth, it is a mixture of several gases and liquids. Commercial natural
gas is mainly composed of methane. However, it also contains ethane, propane and butane in
accordance with the specifications for natural gas in each country in which it is distributed.
Therefore, before natural gas is marketed, some NGLs, including LP Gases (propane and butane) are
separated out, depending on the ‘wetness’ of the gas produced: NGLs represent 1 to 10% of the
Page | 18 unprocessed gas stream. Some NGLs are also trapped in crude oil. In order to stabilize the crude oil
for pipeline or tanker distribution, these “associated” or ”natural gases” are further processed into
LP Gas. Worldwide, gas processing is the source of approximately 60% of LP Gas produced.
Demand and Supply of LPG in India
Consumption Pattern:

20. Page | 19
REFINING
The refining is very similar to that of gasoline is refined from crude oil. LPG is basically a hydrocarbon
with propane and butane as main constituent. LPG is a by-product of natural gas processing. It is the
product that comes from crude oil refining when carried with the smaller amounts of propylene and
butylenes. LPG is largely propane and thus the characteristics of propane are sometimes taken as a
close approximation to those of LPG. When the natural gas is produced, it constitutes of methane
and some other light hydrocarbons which are easily separated in a gas processing plant. There are
many natural gas liquid components that are recovered during processing.
These components mainly include ethane, propane and butane and few other heavier hydrocarbons.
The other gases that are being produced as refining by product are propane and butane along with

21. other gases that rearrange or break down the molecular structure and obtain more desirable
petroleum compounds.
In an oil refinery, LP Gases are produced at various stages: atmospheric distillation, reforming,
cracking and others. The LP Gas produced will be between 1 and 4% of crude oil processed. This
Page | 20 yield will depend on the type of crude oil, the degree of sophistication of the oil refinery and the
market values of propane and butane compared to other oils products. Worldwide, refining is the
source of approximately 40% of LP Gas produced.
Like all other hydrocarbons obtained from oil and gas, LP Gas has its own distinct marketing
advantages and can perform nearly every fuel function as the primary fuels from which it is derived.
Furthermore, LP Gas supply is growing faster than any other oil products. As a result, demand for LP
Gas is steadily growing throughout the world and forecasts show this trend will continue.
APPLICATIONS
POWER GENERATION
Gas demand in the power generation sector requires looking at the whole power sector in India.
Future gas use in this sector will depend on three factors: electricity demand, gas availability and
competitiveness of gas-fired plants versus coal-fired plants.
Analysing the challenges of India’s power sector is not the aim of this Working Paper, but the main
issues concern lack of access to electricity for many people, electricity shortages both on an annual
and a peak basis, and the need to attract investments in generation, transmission and distribution in
order to sustain economic growth. India’s impressive economic growth over thepast decade has
resulted in booming demand for electricity, but energy poverty represents atremendous challenge.
In 2001, 44% of households did not have access to electricity.

22. In order to provide electricity to more people, major investments will be required.
Electricityshortages have been typically around 7% during the 1996-2006 period and the peak
electricityshortage up to 14%. The current capacity as of July 2010 amounts to 163.7 GW, according
to theCentral Electricity Authority (CEA), with gas representing 11% versus 52% for coal and 24% for
hydro. There are now 17.4 GW of gas-fired plants, two thirds of which have beeninstalled since
1995. The IEA estimates that India’s generation capacity will increase almostfourfold between 2009
Page | 21
and 2030 to reach 571 GW with gas-fired capacity increasing from17 GW to 65 GW. Electricity
generated by gas-fired plants is expected to increase to 299 TWh by2030 (IEA, 2009). The Ministry of
Power and the CEA estimated that 78.7 GW would be neededbetween 2007 and 2012 in order to
fully meet electricity and peak demand by 2012. This willalso require significant investments in both
the transmission and the distribution segments.
Gas has benefited from the shortages of electricity and domestic coal which resulted in
higherelectricity prices, helping gas to be used base load even with non-APM gas. Gas availability
hasbeen a constant problem over the 2000-09 period, but the situation has only started to
improvesince mid-2009. Previously, gas-fired plants were utilised at around 50% of their capacity.
Infact, many gas-fired plants had been running on naphtha or remained idle when naphtha wastoo
expensive due to the limited availability of gas. The CEA estimated that the shortfall of gasto the
power generation sector over the period 2000-08 was between 18 and 28 Mcm/d (6.6and 10.2
bcm). In 2008, the 220 MW Jegurupadu CCGT was unable to generate due to shortagesof gas while
909 MW were pending commissioning for the same reason. The year 2009 has seena considerable
improvement with KG-D6 coming on line. Since then, total thermal generation has been close to
targets. The gas-fired plant load factor (PLF) has increased from 57% in January 2009 to 66% in April
2009 to 77% in April 2010. PLF in 2009/10 was around 10% higher than the same period one year
earlier. Meanwhile, the PLF of lignite and coal plants declined due to shortages of domestic coal and
failure to secure imports.
We can expect gas supply constraints to be less of an issue in the power generation sector over the
coming years; the main issue will be the competitiveness of gas-fired plants.
The third issue is the competitiveness of gas versus coal as natural gas competes with coal for base-
load generation. This will determine whether gas is used for base load or to meet peak demand
requirements. Future demand from gas-fired plants depends strongly on the evolution of gas prices
and the path of the reforms in the coal sector. The government plans to liberalise the domestic coal
sector in order to improve the efficiency and attract new investments. In most cases, it will be
difficult for gas to compete against domestic coal, especially if coal-fired plants are located near
mines. However, it has to be observed that most coal reserves are located in the eastern states,
where generation already exceeds consumption by far. More coal-fired generation would require
coal to be transported over long distances or imported, or electricity transmission lines to be built
between regions: these options have a cost. Imported coal could be attractive, especially at the large
power plants proposed at coastal locations. Furthermore, the policy aimed at reducing air pollution
from coal use (including sulphur dioxide) could give an advantage to gas. Finally, the expected
rationalisation of the Indian electricity grid could provide an opportunity for natural gas to play a
larger role to meet peak demand.
We have compared gas-fired plants to coal-fired plants in India, taking two approaches. The first
approach is to look at short-run marginal costs (SRMC) for existing plants:
There are five different cases; the only variable for the gas-fired plants is the price. The analysis is
based on 250 MW gas-fired plants, with 46% efficiency. This is a relatively high efficiency, reflecting
plants installed over the past decade. Older plants would be less efficient. As we have mentioned

23. before, many gas-fired plants used to have access to APM gas at USD 1.8/MBtu, but APM prices have
been recently increased to the level of KG-D6 gas price. Depending on the plant location, a transport
cost through the EWPL and GAIL’s network needs to be added. The five cases are: APM gas (before
May 2010 to highlight the difference with the new price) transported through the HVJ line, KG-D6
gas consumed in the eastern region, KG-D6 gas consumed in the north-western region, LNG imports
from Qatar and spot LNG imports both consumed in the north-western region (see section on
Page | 22
prices). For spot LNG, a price of USD 8/MBtu delivered has been assumed, which may look expensive
for the SRMC taking into account the current market conditions (Henry Hub prices are around USD
5/MBtu as of July 2010), but would reflect higher prices for the generating costs with markets
tightening around the middle of the decade.
Gas-fired plants have been compared to four coal-fired plants, three using domestic coal and one
using imported coal. Plants using domestic coal have a 32% efficiency versus 37% for imported coal.
Domestic coal is based on Grade E coal prices as published by Coal India, and is burned either at the
mine mouth, or transported 700 km or 1 500 km;21 700 km is close to the average historical
transport distance for coal, while 1 500 km reflects longer distance between the eastern region and
consumption centres. Data on transport costs is derived from Indian Railways. Imported coal
assumes a price of USD 90/t (plus a 5% import duty) and that the coal is consumed near the
unloading port.
As expected, the cheapest option is the coal-fired plant using domestic coal on-site, despite its low
efficiency. A CCGT using the former APM gas (at USD 1.8/MBtu) would nevertheless have come
second, but as mentioned earlier, these cheap supplies are no longer available. Coal-fired plant with
domestic coal currently remains competitive against imported LNG (Qatar) up to a transport
distance of 1 300 km. But gas-fired plants using KG-D6 gas, APM gas or more expensive supply
sources would remain more expensive than any coal-fired plants.
To conclude, coal-fired power has currently a competitive advantage using domestic coal in India,
but in some cases depending on the location of the plant, future gas-fired plants could be more
competitive. New gas-fired plants using APM or KG-D6 gas could compete against coal plants using
imported coal for base-load generation. The role of gas depends on where future coal-fired plants
would be located, the evolution of local and imported coal prices, and whether the shortages of coal

24. will continue. If reforms in the coal sector are successful, the role of gas in base load will be more
limited. But if insufficient coal supplies are available, gas could be used more widely, even more if
gas has become more expensive, while the cost would be passed to end users.
Page | 23
FERTILISERS
The fertiliser industry uses natural gas as a primary feedstock instead of the more expensive naphtha
or fuel oil. In 2008/09, gas demand in this sector represented 9 bcm, one fifth of total demand, but
demand has been very variable over the past five years, mainly constrained by the lack of availability
of gas. The sector is key to maintain food self-sufficiency; it has therefore always been heavily
subsidised, with subsidies increasing from INR 15 879 crore in 2004/05 to INR 75 849 crore (USD 16.6
billion) in 2008/09. This policy is therefore very expensive, especially as gas from KG-D6 was more
expensive than APM-gas while urea prices to farmers are capped by the government. Over the past
year, several fertiliser units have been switching to gas as new supplies from KG-D6 have become
available. It can be expected that most fertiliser plants will switch from naphtha and fuel oil to gas in
the coming years, as this has been encouraged by the government. It is also more cost effective to
use gas instead of expensive naphtha: the Fertilizer Industry Coordination Committee (FICC)
reported an 18% drop in the average cost for urea production in 2009 after KG-D6 gas replaced
costlier alternative fuels like naphtha.
The main unknowns for future gas demand in this sector are the future subsidy policy for the farm
gate price of urea and the government’s policy on self-sufficiency. Discussions to phase out subsidies
for urea production by 2012 are ongoing; the issue will become even more challenging with the
recent increase in APM prices. The government’s decision to allow more urea to be imported will
also be key. There are already JVs in the Middle East, for example in Oman, which produce fertiliser
at a much lower price as gas is available at much lower prices (around USD 1/MBtu). But such a
decision could face opposition from agricultural lobbies. A future shift to a greater role for imports

25. would dramatically reduce domestic gas consumption and lessen the subsidy burden on the central
government.
INDUSTRIAL GAS USE
Page | 24 In 2008/09, industrial gas demand (excluding fertilisers) amounted to 14.5 bcm – around one third of
total demand. Petrochemicals and LPG represent half of this demand, while “industrial use”
represent only one third. The petrochemical industry faces similar challenges as the fertiliser
industry in terms of access to cheap raw material. The growth of this industrial use during 2008/09
has been a remarkable 80% to 5.9 bcm (see Table 9). Due to the Gas Policy, many industrial
customers (apart from LPG and petrochemicals) have no access to cheap gas and have to buy market
priced gas from private companies. They need to accept the international prices or use another fuel
(like naphtha). As can be seen in Table 10, the industrial sector has the potential to grow by 10% per
year driven by India’s strong economic growth. But industrial gas demand is still only a fraction of
the potential market, as poor economics due to pricing issues, substitution difficulties for technical
reasons, and non-availability caused by the lack of infrastructure together make industrial demand
difficult to meet. The major opportunity for growth is in displacing naphtha use where prices exceed
USD 10/MBtu.
RETAIL
City gas
The residential sector still uses predominantly biomass, which represents around 80% of its energy
demand. This share is expected to progressively drop due to urbanisation and higher incomes, but
biomass will remain the main fuel in rural areas. In the cities, LPG, then electricity and gas are
increasingly used for heating and cooking. It is estimated that 286 million people live in cities
representing 28% of the population but this number is expected to increase to 575 million by 2030
(41% of population) (MoHUPA, 2009). But urban poverty remains high with an estimated 80 million
people living in cities and towns having low or no access to more efficient sources of energy. So far,
gas has played a limited role in the residential sector and is limited to major cities; this sector
therefore represents a small share of total gas demand. Gas use is expected to grow significantly in
major cities where expansion of networks in underway or planned, but it will not expand to rural
areas. The aim is to have gas distribution in place in all cities with more than 2.5 million inhabitants
and then to have cities with a population between 1 and 2.5 million covered by phases. The growth
will require enhanced infrastructure development, and a clear regulatory framework to enhance the
development of gas distribution in cities. Out of all KG-D6 gas, only 5 Mcm/d have been allocated to
CGD (plus 2 Mcm/d on an interruptible basis), but not all can be effectively absorbed by the existing
infrastructure.
CNG
There are an estimated 700 000 natural gas vehicles (NGV) in India making India the fifth country
after Pakistan, Argentina, Brazil and Iran in terms of NGVs. Although the growth in the number of
cars has been impressive over the past decade (there were only 10 000 in 2000), NGVs only
represent a small share of total vehicles. There have been two main drivers for NGV programmes in
India: improving local air quality and reducing the costs due to oil product prices’ subsidies. Air
pollution has been a rising concern for GoI; in 2003, MoPNG released its Auto Fuel Policy to address
these issues. Although it was recognised that liquid fuels would remain the backbone in the
transport sector (with an upgrade of the specifications), the use of NGV and LPG would be
encouraged. Over the past decade, CNG programmes were introduced in nearly 30 cities, leading to
a steady growth in the number of NGVs (buses, three-wheelers, taxis and small commercial

26. vehicles). The 30 cities are mostly located in Maharashtra and Gujarat, in the North-West of the
country. Some individual state governments have taken actions such as tax exemptions, lower
interest on loans to support the development of NGVs. As in the residential sector, the growth of gas
use in the transport sector faces three major obstacles: expansion of the gas transport network to
the cities; construction of the necessary infrastructure within the city, including refilling stations; and
the availability of gas for CNG.
Page | 25
CURRENT INDUSTRY DEVELOPMENTS
NATURAL GAS VEHICLES
A natural gas vehicle or NGV is an alternative fuel vehicle that uses compressed natural gas (CNG) or
liquefied natural gas (LNG) as a clean alternative to other fossil fuels. Natural gas (NG) as a vehicle
fuel continues to grow in popularity with homeowners. With escalating fuel prices, natural gas offers
many benefits: reduced costs, enhanced safety, single occupancy in High Occupancy Vehicle (HOV)
and carpool lanes with no bridge tolls and of course, cleaner emissions. Because it is a domestic
resource, it promotes energy security for our country. These reasons make natural gas the
alternative fuel of choice for our country.
ENVIRONMENTAL BENEFITS
Natural gas is one of the cleanest burning alternative transportation fuels available today and has
been recognized as an excellent fuel when used to generate electricity, heat homes, and fuel
industrial facilities. It is emerging as a leader in the alternative fuels marketplace.
In addition, natural gas does not contaminate lakes, rivers, or groundwater as petroleum fuels do
because it quickly dissipates into the atmosphere if a leak or spill occurs.
Commercially available medium and heavy-duty natural gas engines have demonstrated over 90%
reduction in particulate matter and more than 50 percent reduction in nitrogen oxides (NOx) relative
to commercial diesel engines. Natural gas engines also produce less greenhouse gases (CO2) that
contribute to global warming.
ECONOMIC BENEFITS
Lower fuel costs: Natural gas is typically 1/3 to the cost of gasoline per gallon equivalent.
Reduced maintenance intervals: Natural gas doesn’t contaminate the engine oil like
traditional fuels - hence less frequent oil changes.
Access to HOV Lanes: California is one state where NGVs are permitted to travel in the HOV
(High Occupancy Vehicle) lanes with only a single person in the vehicle and no bridge tolls
during commute hours.
Reduce dependence on foreign oil: Natural gas is a U.S. fuel and reduces our dependence on
foreign energy supplies.
CNG is consistently cheaper than gasoline or diesel.
Light-duty natural gas vehicles tend to cost $4,000 to $8,000+ more than a gasoline-powered
vehicle. The cost of medium and heavy-duty vehicles is largely dependent on the type of vehicle and
the number of fuel storage cylinders. Frequently, financial incentives and tax credits are available
from local, state and federal agencies to help offset the initial higher premium.

27. UNDERGROUND COAL GASIFICATION (UCG)
Energy demand of India is continuously increasing. Coal is the major fossil fuel in India and continues
to play a pivotal role in the energy sector. India has relatively large reserves of coal (253 billion
tonnes) compared to crude oil (728 million tonnes) and natural gas (686 billion cubic meters). Coal
Page | 26 meets about 60% of the commercial energy needs and about 70% of the electricity produced in India
comes from coal, and therefore there is a need for technologies for utilization of coals efficiently and
cleanly. UCG offers many advantages over the conventional mining and gasification process. UCG is a
well proven technology. Due to the site-specific nature of the process, possibility of land subsidence
and surrounding aquifer water contamination, this technology is still in a developing stage in India.
Potential for UCG in India is studied by comparing the properties of Indian coals with the properties
of coal that are utilized by various UCG trials Underground coal gasification (UCG) is an industrial
process, which converts coal into product gas. UCG is an in-situ gasification process carried out in
non-mined coal seams using injection of oxidants, and bringing the product gas to surface through
production wells drilled from the surface.
Gasification process
The product gas obtained in the UCG process depends on the temperature, pressure and gasifying
agent used. For a low heating value product gas air–steam may be used, whereas for medium to
high heating value gas oxygen– steam is used. Chinchilla (Australia) and Chinese trials used air to
produce a dry gas of calorific value 3–5MJ=m3, whereas pure oxygen at high pressure in the Spanish
trials yielded 13MJ=m3 of dry gas after gas clean up. Oxygen production has a high energy demand
but the benefits are improved gasification stability, better cavity growth and 80% reduction in the
volume of the injection gases that need to be compressed. Oxygen is required for any high pressure
UCG operation for the reason of the cavity growth and pre-combustion CO2 capture. The cavity
made using any drilling technique serves as a reactor. The major reactions taking place in the reactor
are pyrolysis, combustion, gasification, gas phase oxidation and water gas shift reaction.
CITY GAS DISTRIBUTION
City gas distribution (CGD) is among the fastest growing segments in the gas sector with all major
players recording rapid growth in the past couple of years. The segment would continue to grow in
the coming years as well with 20 per cent growth in demand in metropolitan cities and 15 per cent in
other areas. Among the customers, demand growth from the industrial segment is expected to be
the fastest followed by the transportation segment.
The CGD segment has grown on the back of a competitive regulatory environment provided by the
Petroleum and Natural Gas Regulatory Board (PNGRB), which plans to roll out CGD networks in over
200 new cities by 2015. The new regulatory framework has facilitated the entry of several new
players in the segment including some of the existing energy and infrastructure players, and an
international major, which is exploring a joint venture with an Indian firm for gas sourcing and
distribution.
Though the long-term prospects are bright, the CGD segment has been stagnating since early-2011.
While the Supreme Court had reiterated the PNGRB’s authority in awarding licenses for the second
and subsequent rounds of bidding, the board has been unable to function due to lack of quorum.
There was a change in guard at the PNGRB in October 2011 and the new chairman is expected to
take up the award of licenses for the second and third rounds on a priority and restart the stalled
bidding process for the remaining geographical areas (GAs).

28. Page | 27
Country wide CGD projects
In addition to the regulatory challenges, the segment has been facing transmission and supply
constraints. Currently, the approximately 13,000 km of cross-country pipeline network does not
cover a large part of the country, especially the southern and eastern regions. Expeditious

29. completion of pipelines that have been approved by the government and award of new licenses for
pipelines are crucial for the development of the CGD segment.
The CGD industry also faces challenges in sourcing gas for networks, particularly because the
government has curtailed supply to non-core sectors including CGD due to a fall in production from
the Krishna-Godavari basin. However, given the economic and environmental advantages of CGD,
Page | 28
especially with the increasing price of competitive fuels, several operators are sourcing liquefied
natural gas (LNG) for their networks.
COAL BED METHANE (CBM)
Methane was once regarded by miners as a hazard rather than a resource and many miners died in
methane explosions before the introduction of high-capacity ventilation to dilute gasses. However, if
methane is not recaptured it is not only lost as a resource but contributes to global warming. Even
though the volume of methane contributing to greenhouse gasses is three times smaller than carbon
dioxide, its greenhouse potential is 21 times higher. Coal mining is estimated to cause about 9 per
cent of global methane emissions. Methane captured during coal mining could be significant,
ecologically friendly source of energy, producing no particulates and only about half the CO2
associated with coal combustion. Depending on quality methane from mines could be sold to gas
companies, used to generate electricity, used to run vehicles, used as feedstock for fertilizer or
methanol production, used in blast furnace operators at steelworks; sold to other industrial,
domestic or commercial enterprises; or used on-site to dry coal.
CBM Exploration in India
Coalbed Methane (CBM), an unconventional source of natural gas is now considered as an
alternative source for augmenting the country’s energy resources. The environmental, technical and
economic advantage of CBM has made it a global fuel of choice. Having the 4th largest proven coal
reserves and being the third largest coal producer in the world, India holds significant prospects for
commercial recovery of CBM. Prior to 1997, due to absence of proper administrative, fiscal and legal
regime, CBM E&P activities were limited to R&D only. It was only after the formulation of the policy
for exploration and production of CBM by the Government in July 1997, CBM exploration activity
commenced in the country. Ministry of Petroleum & Natural Gas (MOP&NG) became the
administrative Ministry and Directorate General of Hydrocarbons (DGH) became the implementing
agency for CBM policy. DGH functioning under the aegis of MOP&NG plays a pivotal role in
development of CBM resources in India.
Contractual & Fiscal Terms
Below are some of the attractive terms offered by the Government are:
• No participating interest of the Government.
• No upfront payment.
• No signature bonus.
• Exemption from payment of customs duty on imports required for CBM operation.
• Freedom to sell gas in the domestic market.
• Provision of fiscal stability.
• Seven years tax holiday.
CBM Development
India's natural gas production is expected to double from the current 95 million cubic meters a day
(MCMD) to over 190 MCMD by March 2009, Oil Minister MurliDeora told to the Parliamentary
Consultative Committee. Coal Bed Methane (CBM) production in the country is expected to begin in
2007-08 and production is envisaged at 3.78 billion cubic meters, or about 10 MCMD, making India

30. one of the few countries commercially producing CBM. India has so far awarded 26 CBM blocks
covering an area of 13,600 square kilometers. The total investment committed in these blocks is
around Rs6.75 billion and as of April 1, 2006 the companies operating the CBM blocks had invested
Rs1.7 billion.
GAS HYDRATES Page | 29
Projected World Energy Supply
Gas hydrates are crystalline solids that consist of gas molecules, usually methane, surrounded by
water molecules. The gas molecules are densely packed in a crystalline structure so that hydrate
deposits can store vast quantities of methane. Estimates of the amount of carbon bound in gas
hydrates are almost twice the amount of carbon found in all known fossil fuels on Earth; hence,
hydrates represent a dominant unconventional energy resource. Though these hydrates are
abundant worldwide, particularly in Arctic regions and in marine sediments, there is much to learn
about how they form, evolve, interact with surrounding sediments, and affect environmental
conditions when extracted.
Naturally occurring gas hydrates are a form of water ice which contains a large amount of methane
within its crystal structure. They are restricted to the shallow lithosphere (2000-4000 m depth). With
pressurization, they remain stable at temperatures up to 18°C. The average hydrate composition is 1
mole of methane for every 5.75 moles of water. The observed density is around 0.9 g/cm3. One liter
of methane clathrate solid would contain 168 liters of methane gas (at STP).
Environmental and Geo hazard Issues:
Potential hazards associated with production of natural gas from hydrate include ground subsidence,
methane release, slope instability, and water and sand production. Initial studies have indicated that

31. these issues can be mitigated; however, modeling and field validation of mitigation strategies are
needed.
An additional area of interest is the opportunity for sequestering carbon dioxide as a subsurface
hydrate. ConocoPhillips is investigating the possibility of using the chemical exchange of carbon
dioxide for methane in hydrate-bearing reservoirs. In addition to producing natural gas without
dissociating the hydrate, this technology would result in stable, long-term sequestration of carbon
Page | 30
dioxide.
SHALE GAS
Shale gas refers to natural gas that is trapped within shale formations. Shales are fine-grained
sedimentary rocks that can be rich sources of petroleum and natural gas.
Horizontal Drilling and Hydraulic Fracturing
Over the past decade, the combination of horizontal drilling and hydraulic fracturing has allowed
access to large volumes of shale gas that were previously uneconomical to produce. The production
of natural gas from shale formations has rejuvenated the natural gas industry in the United States.
Horizontal Drilling
Two major drilling techniques are used to produce shale gas. Horizontal drilling is used to provide
greater access to the gas trapped deep in the producing formation. First, a vertical well is drilled to
the targeted rock formation. At the desired depth, the drill bit is turned to bore a well that stretches
through the reservoir horizontally, exposing the well to more of the producing shale.
Hydraulic Fracturing
Hydraulic fracturing (commonly called "fracking" or "hydrofracking") is a technique in which water,
chemicals, and sand are pumped into the well to unlock the hydrocarbons trapped in shale
formations by opening cracks (fractures) in the rock and allowing natural gas to flow from the shale
into the well. When used in conjunction with horizontal drilling, hydraulic fracturing enables gas
producers to extract shale gas at reasonable cost. Without these techniques, natural gas does not
flow to the well rapidly, and commercial quantities cannot be produced from shale.
Shale Gas vs. Conventional Gas
Conventional gas reservoirs are created when natural gas migrates toward the Earth's surface from
an organic-rich source formation into highly permeable reservoir rock, where it is trapped by an
overlying layer of impermeable rock. In contrast, shale gas resources form within the organic-rich
shale source rock. The low permeability of the shale greatly inhibits the gas from migrating to more
permeable reservoir rocks. Without horizontal drilling and hydraulic fracturing, shale gas production
would not be economically feasible because the natural gas would not flow from the formation at
high enough rates to justify the cost of drilling.
Environmental Concerns
There are some potential environmental issues that are also associated with the production of shale
gas. Shale gas drilling has significant water supply issues. The drilling and fracturing of wells requires
large amounts of water. In some areas of the country, significant use of water for shale gas
production may affect the availability of water for other uses, and can affect aquatic habitats.
Drilling and fracturing also produce large amounts of wastewater, which may contain dissolved
chemicals and other contaminants that require treatment before disposal or reuse. Because of the
quantities of water used, and the complexities inherent in treating some of the chemicals used,
wastewater treatment and disposal is an important and challenging issue.

32. If mismanaged, the hydraulic fracturing fluid can be released by spills, leaks, or various other
exposure pathways. The use of potentially hazardous chemicals in the fracturing fluid means that
any release of this fluid can result in the contamination of surrounding areas, including sources of
drinking water, and can negatively impact natural habitats.
Page | 31
RENEWABLE ENERGY
Renewable energy is that form of energy which comes from natural resources. These natural
resources include sunlight, wind, rain, tides, and geothermal heat, which are renewable (naturally
replenished). About 16% of global final energy consumption comes from renewables, with 10%
coming from traditional biomass, which is mainly used for heating, and 3.4% from hydroelectricity.
New renewables (small hydro, modern biomass, wind, solar, geothermal, and biofuels) accounted
for another 3% and are growing very rapidly. The share of renewables in electricity generation is
around 19%, with 16% of global electricity coming from hydroelectricity and 3% from new
renewable.
While many renewable energy projects are large-scale, renewable technologies are also suited to
rural and remote areas, where energy is often crucial in human development. As of 2011, small solar
PV systems provide electricity to a few million households, and micro-hydro configured into mini-
grids serves many more. Over 44 million households use biogas made in household-scale digesters
for lighting and/or cooking and more than 166 million households rely on a new generation of more-
efficient biomass cook stoves. United Nations' Secretary-General Ban Ki-moon has said that
renewable energy has the ability to lift the poorest nations to new levels of prosperity. Carbon
neutral and negative fuels can store and transport renewable energy through existing natural gas
pipelines and be used with existing transportation infrastructure, displacing fossil fuels, and reducing
greenhouse gases.
Climate change concerns, coupled with high oil prices, peak oil, and increasing government support,
are driving increasing renewable energy legislation, incentives and commercialization. New
government spending, regulation and policies helped the industry weather the global financial crisis
better than many other sectors. According to a 2011 projection by the International Energy Agency,

33. solar power generators may produce most of the world’s electricity within 50 years, dramatically
reducing the emissions of greenhouse gases that harm the environment.
Solar Energy
Solar energy is the most readily available source of energy. It does not belong to anybody and is,
therefore, free. It is also the most important of the non-conventional sources of energy because it is
Page | 32
non-polluting and, therefore, helps in lessening the greenhouse effect.
The form of energy here is Thermal energy. This energy is used for: Cooking/Heating, Drying/Timber
seasoning, Distillation, Electricity/Power generation, Cooling, Refrigeration, Cold storage. Some of
the gadgets and other devices which use solar energy are - Solar cooker, Flat plate solar cookers,
Concentrating collectors, Solar hot water systems (Domestic and Industrial), Solar pond, Solar hot air
systems, Solar Dryers, Solar timber kilns, solar stills, Solar photovoltaic systems, Solar pond,
Concentrating collectors, Power Tower, Air conditioning, Solar collectors, coupled to absorption,
Refrigeration systems.
Biomass
Biomass is a renewable energy resource derived from the carbonaceous waste of various human and
natural activities. It is derived from numerous sources, including the by-products from the timber
industry, agricultural crops, raw material from the forest, major parts of household waste and wood.
The form of Energy is Chemical energy. This energy is being used for: Cooking, Mechanical,
Applications/Pumping, Power generation, Transportation. Some of the gadgets and other devices
include: Biogas plant/Gasifier/Burner, Gasifier engine pump sets, Stirling engine pump sets, Producer
gas/ Biogas based engine generator sets, Ethanol/Methanol.
Hydel Energy
The energy in the flowing water can be used to produce electricity. Waves result from the
interaction of the wind with the surface of the sea and represent a transfer of energy from the wind
to the sea. Energy can be extracted from tides by creating a reservoir or basin behind a barrage and
then passing tidal waters through turbines in the barrage to generate electricity.
The form of Energy is Potential/Kinetic energy. This energy is being used for: Power generation.
Some of the gadgets and other devices: Turbine generators
Geothermal Energy
The core of the earth is very hot and it is possible to make use of this geothermal energy (in Greek it
means heat from the earth). These are areas where there are volcanoes, hot springs, and geysers,
and methane under the water in the oceans and seas. In some countries, such as in the USA water is
pumped from underground hot water deposits and used to heat people’s houses.
The form of Energy is Thermal energy. This energy is being used for: Heating/Power Generation.
Some of the gadgets and other devices: Heat exchanger, Steam turbines.
Wind Energy
Wind energy is the kinetic energy associated with the movement of atmospheric air. It has been
used for hundreds of years for sailing, grinding grain, and for irrigation. Wind energy systems convert
this kinetic energy to more useful forms of power. Wind energy systems for irrigation and milling
have been in use since ancient times and since the beginning of the 20th century it is being used to
generate electric power. Windmills for water pumping have been installed in many countries
particularly in the rural areas.
The form of Energy is Kinetic energy. This energy is used for: Sailing ships, Pumping water/Irrigation,
Grinding Grains, Power generation. Some of the gadgets and other devices: Sails, Windmills, Wind
turbines.

34. FDI IN PETROLEUM AND NATURAL GAS SECTOR
Since a long time 100% FDI under automatic route has been permissible for all activities in the
petroleum and natural gas sector, other than the refining activity (for which a separate FDI policy
was prescribed). However, for actual trading and marketing of petroleum products, although FDI up
to 100% was allowed through the automatic route, such an approval was subject to the condition of Page | 33
divestment of 26% equity in favor of the Indian partner/public within 5 years. The Government has
now approved deletion of the conditionality of compulsory divestment of 26% equity within 5 years
for actual trading and marketing of petroleum products.
FDI up to 100% is allowed through the automatic route for refining activity in the private sector, but
for refining activity in the public sector, infusion of FDI has been permitted only up to 26%, and with
the prior approval of Foreign Investment Promotion Board (FIPB). The Government has now
approved that infusion of FDI for refining activity in the public sector will henceforth be permitted up
to 49%, and with the prior approval of the FIPB. However, the decision does not envisage or
contemplate disinvestment or dilution in the existing public sector undertakings.
Cumulative FDI inflows during January 2000-2009 (up to December 2009) are Rs. 472,231.23 crores
(US$ 105.99 billion). Out of this, the amount of FDI inflows in the Petroleum & natural gas during
January 2000 to December 2009 is Rs. 11,265.78 crores (US$ 2.61 billion) which 2.47% of the total
FDI inflows.
FUTURE PROSPECTS
While a considerable area is available in the country for carrying out exploration activities for
hydrocarbons, so far as the demand versus domestic availability of crude oil is concerned, India’s
position of 63 per cent self-reliance in 1989-90 became 31 per cent in 2000-01. One of the main
reasons for a comparatively lower growth in the country’s oil production is the absence of major
discoveries of hydrocarbon resources in recent years. Thus, there is an urgent need to increase the
availability of indigenous crude oil through increased exploration in the country. Over the last 15
years, the demand for petroleum products has risen at an annual compound rate of about 6 per
cent. During the last few years, the crude oil production in the country has been at a rate of around
32 million tonnes per annum while the current requirement is of the order of 122 million tonnes.
Similarly, the country’s natural gas production last year was about 81 million standard cubic meters
per day (MMSCMD) as against the projected demand of around 151 MMSCMD in 2001-02. The
demand for petroleum products in the country during the current year is about 138 MMT and is
expected to be about 179 MMT by the year 2006-07.
Considering the availability of vast unexplored or poorly-explored area with substantial yet-to-be-
established hydrocarbon resource base and widening gap of demand and supply, the Government of
India has felt the need to accelerate the pace of exploration for hydrocarbons in the country. To this
effect, the Government has recently come up with ‘India Hydrocarbon Vision – 2025’ wherein the
strategic directions were provided towards exploration of the Indian sedimentary basins in a phased
manner in keeping with technological advancement and environmental concerns. To achieve the set
objectives, the implementation schedule envisages continuance of exploration in producing basins,
pursuit of extensive exploration in non-producing and frontier basins, a programme for appraisal of
the Indian sedimentary basins to the extent of 25 per cent by 2005, 50 per cent by 2010, 75 per cent
by 2015 and 100 per cent by 2025.

35. NEW EXPLORATION LICENSING POLICY
NELP was conceptualised by the Government of India, during 1997-98 to provide an equal platform
to both Public and Private sector companies in exploration and production of hydrocarbons with
Directorate General of Hydrocarbons (DGH) as a nodal agency for its implementation. India has an
Page | 34 estimated sedimentary area of 3.14 million km2 consisting of 26 sedimentary basins, of which, 57 %
(1.35 million km2) area is in deep-water and remaining 43 % (1.79 million km2) area is in on land and
shallow offshore. At present 1.06 million km2 area is held under Petroleum Exploration Licenses in
18 basins by national oil companies viz. Oil and Natural Gas Corporation Limited (ONGC), OIL India
Limited (OIL) and Private/Joint Venture companies. Before implementation of the New Exploration
Licensing Policy (NELP) in 1999, a mere 11% of Indian sedimentary basins was under exploration,
which has now increased extensively over the years.
Recently, bidding process was completed in NELP-IX. Till 2010, 8 rounds of NELP have been
completed. 400 PSC’s have been signed, out of which 168 are in operation.*2+ The private / JV
companies contribute about 46 % of gas and 16% oil to the national Oil & Gas production. The
Mangala fields in Rajasthan and Krishna-Godavari Basins have been the major source for oil and gas
fields.
In view of the inherent risk of hydrocarbon exploration and the huge financial investment associated
with such risky exploration ventures, it has been felt that the efforts of the two upstream NOCs may
not be adequate to achieve the set mandate. Hence opening up of the acreages for active
exploration by private or joint venture companies, in addition to the efforts of the NOCs, was
considered necessary. The acreages offered by the Government under various exploration rounds
earlier met with only partial success. The main thrust for acceleration of exploration activities has,
however, begun with the introduction of New Exploration Licensing Policy (NELP) by the
Government in 1997.
NELP has introduced a level playing field for public as well as private sector players. NOCs are also
required to compete with the private and joint venture companies in acquiring exploration acreages
in Indian sedimentary basins. Under this policy, all companies would be required to bid for a
committed work programme to profit petroleum share expected by the contractor at various levels
of pre-tax multiple of investments and percentage of annual production sought to be allocated
towards cost recovery. The other main features of the terms offered by the Government inter alia
include - no signature, discovery or production bonus by the bidder; income tax holiday for seven
years from the start of commercial production, no customs duty on imports required to be payable
for petroleum operations, biddable cost recovery limit up to 100 per cent, royalty to be payable by
the contractor on ad vole ram basis, freedom to the contractor for marketing of oil and gas in the
domestic market, fiscal stability provision in the contract and incentive for deep-water exploration
with only half of the royalty payable in the initial seven years from the beginning of commercial
production. There are certain differences between the earlier rounds of bidding for exploration
blocks and NELP. While NOCs were to bear royalty, cess and PEL fees on behalf of private companies
in the earlier rounds, companies are now required to bear royalty. Cess and fees have now been
exempted under NELP. Under the policy, NOCs are no longer needed to participate as Government
nominees. The policy exempts them from payment of customs duty and cess for the blocks offered.
The New Exploration Licensing Policy, a vehicle designed by the Government of India, has so far
been successful in accelerating the pace of hydrocarbon exploration in the country.
The hydrocarbon sector in India is one of the most crucial industries for determining energy security
as nearly 45 per cent of the country’s total energy needs are met by the oil and gas sector.
Production of indigenous oil and gas is therefore a major plank of oil security for the nation. Through

36. the New Exploration Licensing Policy, the Government of India is making a concerted effort to
expeditiously explore the inadequately explored and unexplored areas of the country’s sedimentary
basins.
Need for NELP
Page | 35
India is the fifth largest consumer of primary energy and the third largest consumer of oil in the
Asia–Pacific region after China and Japan. Due to high economic growth, there is a huge need for
enhancing supply of energy resources. Also, dependence on imported petroleum continues to grow
and is ultimately impacting the country’s long term growth. Of the 26 sedimentary basins identified
in India, so far, only 20% of the total area has been well explored. The remaining areas need to be
extensively explored with the best of technologies, with special emphasis on the frontier basins.
With the introduction of the New Exploration Licensing Policy (NELP), the introduction of much-
needed capital and state-of-the-art technology to explore the sector could be made possible. With
the policies and regulations being some of the most transparent in the world, the NELP has revived a
healthy spirit of competition between National Oil Companies and private and multinational
companies. The development of the exploration sector has been significantly boosted through this
policy, which brought major liberalization in the sector and created pathways for private and foreign
investment, where 100% Foreign Direct Investment (FDI) is allowed. Under NELP, which became
effective in February 1999, the process of competitive bidding is followed wherein acreages are
offered to the participating companies. By mid-2012, the ninth round of bidding has been concluded
along with fourth round for Coal Bed Methane (CBM) blocks. The Government of India offered the
highest ever number of 70 oil & gas exploration blocks covering an area of about 1,63,535 km² and
also making a parallel offer of 10 blocks under the fourth round of Coal Bed Methane Policy (CBM-
IV) for exploration and production of Coal Bed Methane. The Government of India launched the
Ninth round of offers for exploration acreages, NELP IX on 15 October 2010.
NELP-I
Under the First round of New Exploration Licensing Policy, bids were invited by the Government of
India on 8 January 1999 for 48 blocks for exploration of oil and natural gas. Of these, 12 blocks were
deep-water (beyond 400m isobaths), 26 shallow offshore and 10 were onshore blocks. The PSC’s
were signed for 24 exploration blocks comprising 7 deep-water, 16 shallow offshore and 1 onshore.
At present, 11 exploration blocks are under operation and 13 blocks have been relinquished.
NELP-II
Under the second round of New Exploration Licensing Policy, bids were invited by the Government
of India 15 December 2000 for 25 blocks for exploration of oil and natural gas. Of these, 8 blocks
were deep-water (beyond 400m isobaths), 8 shallow offshore and 9 were inland blocks. The PSC’s
were signed for 23 exploration blocks comprising 8 deep-water, 8 shallow offshore and 7 inland. At
present, 4 exploration blocks are under operation and 19 blocks have been relinquished.
NELP-III
Under the third round of New Exploration Licensing Policy, bids were invited by the Government of
India on 27 March 2002 for 27 blocks for exploration of oil and natural gas. Of these, 9 blocks were
deep-water (beyond 400m isobaths), 7 shallow offshore and 11 were inland blocks The PSC’s were
signed for 23 exploration blocks comprising 9 deep-water, 6 shallow offshore and 8 inland. The
exploration activities are going on in 19 awarded blocks and 4 blocks had been relinquished.
NELP-IV

37. Under the Fourth round of New Exploration Licensing Policy, bids were invited by the Government of
India on 8 May 2003 for 24 blocks for exploration of oil and natural gas. Of these, 12 blocks were
deep-water (beyond 400m isobaths), 1 shallow offshore and 11 were inland blocks. The PSC’s were
signed for 20 exploration blocks. At present 19 exploration blocks are operating, comprising 9 deep-
water and 10 inland. The exploration activities are going on in all the 19 awarded blocks.
Page | 36
NELP-V
Under the Fifth round of New Exploration Licensing Policy, bids were invited by the Government of
India for 20 blocks for exploration of oil and natural gas. The Government received 69 bids from 48
global and domestic majors, including BP (formerly British Petroleum) and Reliance Industries, to
participate in the oil exploration activity under the fifth round for 20 oil exploration blocks. Of these,
6 blocks were deep-water (beyond 400m isobaths), 2 shallow offshore and 12 were inland blocks.
The largest numbers of bids received were from Reliance which had bid for 12 of the 20 blocks,
followed by ONGC which had bid for 10 and Oil India Ltd which put in a bid for six blocks.
The PSC’s were signed for all 20 exploration blocks. The exploration activity is going on in all the 20
awarded blocks.[7] As of 2012, ENI is still awaiting Drilling permission from the department of space
due to the block’s proximity to a rocket launch zone (in Andaman and Nicobar Islands) of ISRO.
NELP-VI
A total of fifty five blocks (55) were offered during the NELP VI round for exploration of oil and
natural gas in 16 prospective sedimentary basins consists of 25 Inland, 6 Shallow Water and 24
Deep-water blocks. 165 bids from 68 E&P companies (36 foreign and 32 Indian) had participated in
the bidding process as consortium/ individually.*8+ The PSC’s were signed for 52 exploration blocks
comprising 21 deep-water, 6 shallow water and 25 inland. The exploration activities are going on in
all the 52 awarded blocks.
NELP-VII
A total of fifty Seven blocks (57) were offered during the NELP VII round for exploration of oil and
natural gas in 18 prospective sedimentary basins consists of 29 Inland, 9 Shallow Water and 19
Deep-water blocks. On 22 December 2008 Contracts were signed for 41 blocks out of which 11
blocks in Deep-water, 7 blocks in Shallow Water and 23 Inland blocks.
NELP-VIII
Under the eighth round of New Exploration Licensing Policy (NELP-VIII), Government has offered 31
production sharing contracts on 30 June 2010. There are 8 deep-water blocks, 11 shallow water
blocks and 12 inland blocks which are in the states of Assam (2), Gujarat (8), Madhya Pradesh (1) and
Manipur (1).
NELP-IX
A total of 33 exploration blocks were offered during the bidding process. State-owned Oil and
Natural Gas Corp (ONGC) bagged 10 of the 33 oil and gas exploration blocks, Oil India Ltd (OIL) bid
for as many as 29 blocks and managed to get 10. Reliance Industries bid for two deep-sea blocks in
the Andaman Basin in the Bay of Bengal and four onshore blocks in Rajasthan and Gujarat.

38. Chronology Of Exploration and Production Activities in India
India began its journey into Oil Exploration and Production just seven years after the famous ‘Drake
Well’, which heralded the beginning of the Petroleum era, which was drilled in Titus Ville,
Pennsylvania, USA (1859). The oil reserves were located in the dense jungles, swamps, damp and
undulated terrain of Brahmaputra Valley, Assam in the mid-19th century. The first well was drilled
by Mr.Goodenough of Mckillop, Stewart and Co.; in Upper Assam in 1866 following a hint of oil show
Page | 37
detected by the fleet of elephants carrying logs.
Year Activity
1983-84 Gas struck at Razole, Andhra Pradesh and Gotaru, Rajasthan.
1984 First Early Production system (EPS) commences in Gujarat.
1984 Gas struck at Gotaru in Rajasthan by ONGC.
1988-89 Commercial gas finds in Rajasthan by OIL, Nada field in Gujarat discovered.
1989-90 South Heera field discovered in Mumbai offshore.
New Exploration Licensing Policy (NELP) launched and 48 Exploration blocks offered
1998
under round-I.
Second round of New Exploration Licensing Policy launched and 25 Exploration blocks
2000
offered.
Third round of New Exploration Licensing Policy launched and 27 Exploration blocks
2002
offered.
Fourth round of New Exploration Licensing Policy launched and 24 Exploration blocks
2003
offered.
Fifth round of New Exploration Licensing Policy launched and 20 Exploration blocks
2005
offered.
Sixth round of New Exploration Licensing Policy launched and 55 Exploration blocks
2006
offered.
Seventh round of New Exploration Licensing Policy launched and 57 Exploration blocks
2007
offered
2010 Eight round of New Exploration Licensing Policy offered and 31 blocks offered.
IMPORT
As India does not have any pipeline connection, all the gas currently imported is LNG.Current
operational LNG import capacity is 13.5 mtpa (18 bcm). India joined the global LNGmarket in March
2004 when the Dahej LNG terminal went into operation. Petronet LNGLimited (PLL), a joint venture
promoted by GAIL, IOCL, Bahrat Petroleum (BPCL), GDF Suez, theAsian Development Bank (ADB) and
ONGC was formed to import LNG in order to meet thegrowing gas demand. PLL expanded this
terminal from 5 to 10 mtpa (6.8 to 13.6 bcm) in early2009. The second LNG terminal is the Shell and
Total 3.5 mtpa (4.8 bcm) terminal located inHazira, which was commissioned in April 2005.12 Both
are located on the western coast andcould be further expanded to 15 and 10 mtpa respectively. The
third terminal, the Dabhol-Ratnagiri LNG terminal, is expected to become operational in 2010, after
many delays. It has atotal capacity of 5.5 mtpa (7.5 bcm), with about 2.9 mtpa (3.9 bcm) available for
merchant sales.The commissioning date was delayed from mid-April 2009 to an unspecified date in
2010because of the monsoon season, breakwater facilities and construction costs, and no new

39. commissioning date has been given since. It would first only operate at a capacity of 1 mtpa(1.4
bcm) and ramp up to planned capacity gradually.
LNG import capacity could be extended to over 80 bcm (63 mtpa), if all planned terminals cometo
fruition (see Table 8 below). However, those investments are likely to face some difficultiesand
delays related to lack of capital and difficulties to secure new supplies: only seven LNGliquefaction
Page | 38
plants have taken a Final Investment Decision (FID) since mid-2005. The GorgonLNG facility in
Australia, which took the FID in 2009, will sell 1.5 mtpa to the Indian gas market.However, the Indian
gas market might be less ready to accept LNG prices at the same level asJapan, Korea or even China
whose regasification capacity is increasing rapidly.In 2009/10, India imported 12.3 bcm of LNG from
Qatar (under a long-term contract), Australia,Trinidad and Tobago, and Russia as well as from a few
other countries. LNG was imported at thetwo operational terminals. LNG imports have been growing
as can be seen in Table 7. This trendhas continued in 2009/10 with LNG imports rising from 11.6 bcm
in 2008/09. The surplus ofLNG, driven by lower demand in the traditional LNG importers such as
Japan and Korea and thecollapse of spot prices,13 has enabled India to import LNG at prices around
USD 4-5/MBtu. Forexample, Petronet bought spot cargoes from North West Shelf (Australia) in
2009. Other factorsalso came into play:
• The increase of naphtha prices
• falling production of the mature fields such as Bombay High
• problems with securing the domestic supplies from KG-D6 field.
Until 2009, India had only one long-term LNG contract signed to supply the Dahej terminal for 5
mtpa (6.7 bcm), as the second operational terminal in Hazira operates on the merchant model. The
long-term contract from 2004 with Qatar’s RasGas stated that Dahej’s operator, Petronet LNG, was
based on a fixed price of USD 2.53/MBtu f.o.b. for 5 mtpa for the first five years. Since January 2009,
this price increased to USD 3.12/MBtu. Volumes under this contract have risen to 7.5 mtpa (10 bcm)
in Q4 2009, due to the extension of the terminal’s capacity.
Petronet tried to acquire additional LNG for Dabhol from Qatar and there have been intense
discussions on further volumes in 2006-07 due to a price disagreement: Qatar offered USD 10/MBtu
while Petronet did not want more than USD 5.5/MBtu. They agreed on a shortterm contract of 1.2
mtpa from March 2007 to June 2009. In 2010, Qatar announced that these supplies will be boosted
to 11.5 mtpa by 2014. This could start as soon as 2011 with an additional 1 mtpa, increasing to 2.5
mtpa by 2012 and 4 mtpa by 2014. On 8 May 2009, Petronet LNG finalised talks concerning the
purchase of 1.5 mtpa (2 bcm) of LNG for 20 years from ExxonMobil’s planned output from the
Gorgon LNG plant in Australia, expected to start operating in 2014. This puts total contracted LNG
supplies to 18 bcm as of 2014, two thirds of the LNG capacity which will be online at that time. The
Australian supplies would primarily be sent to the Kochi terminal, which is scheduled to become
operational by 2012. Gorgon’s sponsors took the FID in September 2009. Petronet has taken a lower
share in Gorgon than that mentioned in early 2008 – 3.75 mtpa. It seems that Petronet has acquired
more confidence with the start of the KG field and the fact that ample LNG supplies are available.
With the current gas surplus, the market has currently turned into a buyers’ market, and Petronet is
currently looking at potential cheaper LNG alternatives priced at a spot price level which is currently
half that of oil-linked price. This strategy is fine as long as there is no tightening of the supply and
demand balance on global gas markets or even in the Pacific Basin, which is expected to tighten
more quickly than Atlantic markets. It will certainly be more difficult to attract cheap spot LNG once
markets tighten. Indian companies are therefore looking for additional long-term LNG supplies.
Some Indian customers have recently shown interest in medium- to long-term contracts at Hazira,
probably as the result of difficulties securing domestic gas supplies and the drop of international
spot prices. Petronet is in discussion with several companies to increase future imports of LNG under
long-term contracts. It has been in discussion with Algeria (Sonatrach) since 2007 over a 1.25

40. mtpa25-year contract. Petronet is interested in another project in Australia – the Kimberley hub for
the Browse Basin development. It also wants to acquire a stake in the Niugini project (Papua New
Guinea) from Canada’s Inter Oil, which seeks to sell a 20% of this project.
Page | 39
Since 2006, India has been importing many spot cargoes, not only to Hazira, but also to Dahej.
In2009, India has become a destination of choice for many Pacific and Middle East exporters dueto
increasing demand, proximity and netbacks relatively comparable, if not better, to the UnitedStates
or the United Kingdom. Since the start-up of Sakhalin, Hazira and Dahej have receivedseveral
Russian cargoes as Russia tries to keep exports East of Suez. Petronet and GSPC boughtfive and one
spot cargoes respectively from NWS in Australia; cargoes from Indonesian Tangguhplant have also
been diverted to India. Due to proximity, some Yemeni cargoes may go to Indiainstead of the United
States if Henry Hub prices stay around USD 5/MBtu.Nevertheless, since KG-D6 reached an output of
60 Mcm/d in November 2009, only one spotcargo per month has been arriving to India. Increased
domestic production has moderated theappetite for spot LNG and we are seeing a “wait-and-see”
approach during 2010: market playerswait to see how much appetite there is still for gas once KG-D6
produces at its maximum level.This also depends on the price of spot cargoes. Petronet has stopped
importing spot cargoessince December 2009, but has been starting to import in August 2010.
INFRASTRUCTURE - PIPELINES
IEA’s forecasts on demand and domestic production imply a supply gap of 18 bcm by 2015,
increasing to 28 bcm by 2020 and 52 bcm by 2030. In any case, LNG seems set to remain the first
source of imports for India for at least the five years to come. So far, India does not import by
pipeline. While several projects are under consideration, they are still far from even taking Final
Investment Decision.

41. LNG TERMINALS
Page | 40
India’s import capacity consists of LNG regasification terminals with a current capacity of 13.5 mtpa
(18 bcm). This capacity is expected to increase based on projects currently under construction and in
planning. Only the 5.5 mtpaDabhol and 2.5 mtpa Kochi are under construction with a start in 2010
and 2012 respectively. Meanwhile, up to 40 mtpa (54 bcm) of capacity is planned (see Table 8). Both
existing LNG terminals are planned for expansion. It is unlikely that all these LNG terminals will come
online; so far only the Dabhol and Kochi can realistically come online before 2015 as the market
faces an increase of domestic production and uncertainties on global prices. It is likely that many
users will try to secure cheaper domestic gas before potentially looking at LNG. But some are likely
to be built due to India’s growing appetite for gas.
The latest developments seem to confirm the Indian LNG potential’s expansion course. In particular,
securing LNG for Kochi from Gorgon is a decisive step to advance the project. Corporation of Chinese
Taipei was awarded the onshore engineering, procurement and construction (EPC) job for the
terminal. Construction is said to take 22 months, and Kochi is now scheduled to start operations in
2012.
As mentioned earlier, constraints in domestic pipeline infrastructure are important for future LNG
regasification terminals. For example, gas from the Dahej terminal flows through Gail’s HVJ pipeline
as does production from the Gujarat coast. As a result, little spare capacity is available in this

42. pipeline. This problem was particularly acute during summer of 2009, when demand from the power
generation sector in the region of New Delhi was exceptionally high due to the late arrival of the
monsoon rains.
Page | 41
The IPI Pipeline Project

43. The Iran-Pakistan-India pipeline project was launched in the 1990s. After long years of negotiations
between the neighbouring countries concerning pricing and delivery terms, from which India has
virtually withdrawn since the terror attacks in Mumbai in November 2008, Iran and Pakistan finally
agreed on 5 June 2009 to develop an Iran-Pakistan (IP) pipeline, moving ahead with the first part of
what is still intended to be a trilateral project, the so-called “Peace Pipeline”. One week before the
first round of the Iranian presidential elections in 2009, Iran and Pakistan signed an agreement for
Page | 42
Iran to supply Pakistan with 7.5 bcm/y for 25 years, with an extension of an additional five years in
case of mutual agreement. Both countries expressed their interest in a future Indian participation. In
March 2010, Pakistan and Iran signed a Head of Agreement to build a 7.5 bcm pipeline by 2015.
There are nevertheless several issues that complicate the completion of the pipeline and India’s
participation, notably the development of Iran’s resources, as well as pricing and geopolitical issues.
Firstly, despite Iran’s huge gas resources estimated at 29 tcm (as of end 2009), the country is a net
gas importer as demand is increasing more rapidly than production. Demand has increased from 96
bcm in 2005 to 140 bcm in 2009 according to IEA’s estimates, making it the second non-OECD
market behind Russia and before China. The huge and increasing requirements for reinjection, in
addition to a booming domestic market, require substantial investments in exploration and
production, but Iran is suffering from a poor investment climate due to international political
tensions and the most recent developments make this unlikely to change in the short term. Besides
its huge domestic requirements, Iran is engaged in several export projects ranging from LNG to
pipeline to the East (Pakistan and India) and the West (Turkey and Europe). Iran linked the price of
gas in the pipeline to a gas price formula similar to that for Japanese LNG based on Japanese Crude
Cocktail (JCC) price. However, the USD 0.49/MBtu fee demanded by Pakistan combined with the
transportation tariff of USD 1.57/MBtu would mean that the cost of gas at the Indian border would
be close to USD 7/MBtu, almost USD 2.50/MBtu more than India was willing to spend and more than
recent spot prices. Negotiations have continued over transit fees for two years without success.
Geopolitical issues hampering the pipeline extension to India are diverse: they range from concerns
about a safe transit through Baluchistan to the tense international relations. One important issue for
India is represented by the history of mistrust and recent conflicts with Pakistan, in particular
stability and security concerns regarding the Baluchistan province in Pakistan, through which a
portion of the pipeline is planned. India would need strong domestic support to be dependent on
Pakistan by accepting it as a transit route for part of its energy imports.
Pakistan has also offered India the alternative option to buy gas at the Pakistan-India border from Pakistan and
let Pakistan and Iran deal with the pipeline. However, Indian sources pointed out that this could put India in a
critical situation for its nuclear relations with the United States.
Turkmenistan-Afghanistan-Pakistan-India pipeline (TAPI)
This proposed pipeline along a 1680 km route aims to deliver 30 bcm/y of gas to consumers in
Afghanistan, Pakistan and India. Capital cost is estimated at USD 8 billion. In April 2009, the
governments of the four countries signed a framework agreement to construct TAPI. However, the
project has been pending for more than 10 years. It is backed by the United States, but from the
Indian perspective, the security situation in Afghanistan makes it a more distant prospect than the
IPI pipeline. Security of the TAPI route through Afghanistan is an impediment, although, in 2008, the
Afghan government made several pledges to address these concerns. The framework agreement
states that the TAPI pipeline would be built by a consortium of national oil companies from the four
nations. The draft Gas Pipeline Framework Agreement provides for payment of transit fees to
Afghanistan and Pakistan for allowing usage of their territories for passage of the pipeline, on
internationally accepted cost-of-service based tariff methodology. The two nations would be entitled
to a transit fee based on gas exiting their territories and not for the natural gas consumed, lost or
disposed of within their territories. The IP pipeline would undermine the participation of Pakistan to

44. the TAPI pipeline. Furthermore, Pakistan expressed its interest to source Turkmen gas via Iran
through the IP pipeline. This would require a new pipeline to be built to connect Turkmenistan to
Pakistan but also to agree on pricing issues.
ADB has conducted feasibility studies and provided technical assistance for the project in the past.
Any progress in the pipeline would likely involve ADB assistance as well; however ADB did not
Page | 43
confirm its intention to fund 25% of the 1 680 km TAPI pipeline project that has been considered by
Pakistan. Another question concerns resources. Although reserves have been re-evaluated upwards
in 2008 due to the South Yolatan field, Turkmenistan has committed significant volumes to Russia, as
well as to China under long-term contracts, which exceed by far its current production. Furthermore,
Turkmen gas production has often missed the official optimistic targets. Turkmenistan is also
planning to increase exports to Iran by expanding the existing pipeline and building another one.
Europe is also looking at Turkmen gas although the issue is held back by the lack of a Trans-Caspian
pipeline.
The Myanmar-India pipeline
A 1 575 km long pipeline connecting the Shwe field to the A-1 block in Myanmar, in which both
ONGC Videsh and GAIL own a stake (20% and 10% respectively), was considered to bring gas to
India, passing through Bangladesh. The consortium of blocks A1 and A3 had recently declared a total
discovery of GIIP of 5.35 tcf of gas. However, not much progress has happened on this front recently
while an export pipeline to China has started construction in mid-2010.
REGULATIONS
ACTS / LAWS
The Oilfields (Regulation and Development) Act, 1948
The Act was introduced on 8th September, 1948 and deals with regulation of oilfields and
development of mineral oil resources. Among other things, it regulates the drilling, redrilling,
deepening, shutting down, plugging and abandoning of oil-wells in an oilfield.
Petroleum and Natural Gas Rules, 1959 (As amended from time to time)
Introduced in exercise of powers conferred by sections 5 and 6 of the Oilfields (Regulation and
Development) Act, 1948 (53 of 1948) and in super-session of the Petroleum Concession Rules, 1949.
It regulates the grant of exploration licenses and mining leases in respect of petroleum and natural
gas, which belongs to Government, and for conservation and development thereof.
The rule regulates the exploration and mining of petroleum and natural gas.
Petroleum & Natural Gas Regulatory Board Act, 2006
This Act provided for the establishment of Petroleum and Natural Gas Regulatory Board to regulate
the refining, processing, storage and transportation, distribution, marketing and sale of petroleum,
petroleum products and natural gas excluding production of crude oil and natural gas so as to
protect the interests of consumers and entities engaged in specified activities relating to petroleum,
petroleum products and natural gas in all parts of the country and to promote competitive markets
and for matters connected therewith.
The act regulates the refining, processing, storage and transportation and distribution of petroleum,
petroleum products and natural gas.

45. POLICIES
Natural Gas Pipeline Policy, 2006
The Government of India notified the policy for development of natural gas pipelines and city or
local natural gas distribution networks in India. The policy would promote investment from the
Page | 44 public and private sectors in natural gas transmission. The pipeline policy provides for the regulator
to set a ceiling rate for transportation charges. Companies will be free to offer rates at different
levels as long as it is under the ceiling. The policy will cover cross-country pipeline operators and city
gas distribution companies. The policy is being brought in as several investors have been awaiting a
clear policy guideline in this regard. It would provide proper linkage between gas sources and market
centres, along with inter-connectivity for regions, consumers and producers.
TAX REGIMES
The tax revenue is the most important source of public revenue. A tax is a compulsory payment
levied by the government on individuals or companies to meet the expenditure which is required for
public welfare. India also provides a customized tax regime for the upstream sector and non-resident
service providers in relation to Exploration & Production operations.The Oil and Gas sector is a vast
sector. There are three major components:
Upstream
The upstream oil sector or exploration and production (E&P) sector commonly used to refer to the
searching for and the recovery and production of crude oil and natural gas.
Midstream
The midstream industry processes, stores, markets and transports commodities such as crude oil,
natural gas, natural gas liquids.
Downstream
The downstream sector includes oil refineries, petrochemical plants, petroleum product distribution,
retail outlets and natural gas distribution companies. The downstream industry touches every
province and territory-wherever consumers are located-and provides consumers with thousands of
products.
TAXFRAMEWORK
NELP framework seeks to provide a level playing field to the domestic public sector companies,
private companies, and foreign companies, by offering similar regulatory and contractual terms for
exploration and production of oil and gas. Also included is a seven year tax holiday from the date of
commencement of commercial production.
As per the amendment in the Budget of 2008, the tax holiday would not be available for an
undertaking which begins the refining of mineral oil at any time on or after April 1, 2009. In the
finalized law, the tax holiday was extended till March 31, 2012, for notified public sector refineries;
however, the maximum collateral damages that emerged affected upstream oil and gas producers.
The Government has provided certain tax incentives in the Production Sharing Contract and has
gradually revised the rates on royalty and various taxes and duties.
India has a hybrid system of Production Sharing Contracts’ (PSC) containing elements of royalty, as
well as sharing of production with the Government. Companies enter into a PSC with the
Government of India to undertake exploration and production (E&P) activities.

46. Taxation of the E&P sector was traditionally driven with the objective of attracting investments and
expertise to secure India’s energy resources. An attempt has been made to keep this objective in
mind in the new legislation, i.e. the Direct Taxes Code (DTC), proposed to be enacted from 1 April
2012 but again been deferred in Budget 2012 , as well. Taxation of such companies is not only
governed by the Income Tax law but also by the Production Sharing Contract (PSC) entered into
between the Government and E&P players. In light of a judicial ruling by the Supreme Court of India,
Page | 45
in the event of a conflict between the provisions of the law and the PSC, the provisions of PSC is to
be applied.
ROYALTY REGIME
Central Government is entitled to get Royalty on Oil and Gas produced from the offshore fields
whereas in case of onshore fields it is payable to concerned State Government. The power of
regulation and responsibility for the development of oil fields are exclusively within the domain of
the Central Government. Oil Fields (Regulation and Development) Act, 1948 and the Petroleum and
Natural Gas Rules, 1959 deal with it.
The PSC provides protection in case changes in Indian law result in a material change to the
economic benefits accruing to the parties after the date of execution of the contract.
Land areas — payable at the rate of 12.5% for crude oil and 10% for natural gas
Shallow water offshore areas — payable at the rate of 10% for crude oil and natural gas.
Deep-water offshore areas (beyond 400m isobaths) — payable at the rate of 5% for the first
seven years of commercial production and thereafter at a rate of 10% for crude oil and natural
gas.
INCOME TAX REGIME
The Indian Income Tax Act (‘Act’) provides special provision for taxability of upstream companies.
Section 42 of the Act lists downs the allow ability of certain categories of expenditure as are
specified in the PSC:
Expenditure by way of infructuous or abortive exploration
Expenditure incurred for exploration or drilling activities or services or assets used for these
activities
Depletion of mineral oil in the mining area post commercial production
It further provides that such allowances shall be computed and made in the manner as specified in
the PSC, and the other provisions of the Act being deemed for this purpose to have been modified to
the extent necessary to give effect to the terms of the PSC.
Accordingly, for such kind of expenditure, one has to examine the relevant provisions of the PSC.
Article 17 of the Model PSC5 provides for the following specific allowances in computing the taxable
income of the E&P companies:
Exploration and drilling expenditure, both capital and revenue in nature, is 100% tax
deductible.
Expenditure incurred on development and production activities (other than drilling
expenditure) is allowed as per the provisions of the Income tax Act (“the Act”)
All exploration and drilling expenditure is allowed to be aggregated till year of
commencement of commercial production. Alternately such expenditure may be amortized
equally over a 10-year period from start of commercial production.
DOMESTIC TAX LAWS

47. The contractor under NELP is required to pay taxed under Indian Income tax Act, 1961. The broad
provisions under domestic tax laws are highlighted as below:
Ring-Fencing
No ring-fencing applies from a tax perspective; therefore, it is possible to offset the exploration costs
Page | 46
of one block against the income arising from another block.
Treatment of Exploration and Development Costs
All exploration and drilling costs are 100% tax deductible. Such costs are aggregated till the year of
commencement of commercial production. They can be either fully claimed in the year of
commercial production or they can be amortized equality over a period of 10 years from the date of
first commercial production. Development costs (other than drilling expenditure) are allowable
under the normal provisions under the domestic tax law.
PRODUCTION SHARING CONTRACT REGIME
India has a hybrid system of PSCs containing elements of royalty as well as sharing of production
with the Government. E&P companies (contractors) that are awarded the exploration blocks enter
into a PSC with the Government for undertaking the E&P of mineral oil. The PSC sets forth the rights
and duties of the contractor. The PSC regime is based on production value.
Cost Petroleum or Cost Oil
Cost petroleum is the portion of the total value of crude oil and natural gas produced (and saved)
that is allocated toward recovery of costs. The costs that are eligible for cost recovery are:
Exploration costs incurred before and after the commencement of commercial production
Development costs incurred before and after the commencement of commercial production.
Production costs
Royalties
The unrecovered portion of the costs can be carried forward to subsequent years until full cost
recovery is achieved.
Profit Petroleum or Profit Oil
Profit petroleum means the total value of crude oil and natural gas produced and saved, as reduced
by cost petroleum. The profit petroleum share of the Government is biddable by the contractor. The
blocks are auctioned by the Government. The bids from companies are evaluated based on various
parameters including the share of profit percentage offered by the companies.
INCENTIVES & CAPITAL ALLOWANCES
Accelerated depreciation:
Depreciation is calculated using the declining-balance method and is allowed on a class of assets.
Ranges from 15-60%
Tax holiday
A seven-year tax holiday equal to 100% of taxable profits is available for an undertaking engaged in
the business of commercial production of mineral oil or natural gas or refining of mineral oil.
Research &Development
Expenditures on scientific research incurred for the purposes of the business are tax deductible.
Other

48. There is a special tax regime for foreign companies that are engaged in the business of providing
services or facilities or supplying plant or machinery or hire used in connection with prospecting,
extraction or production of mineral oils.
Notable Issues for the Oil and Gas Sector
Several concessions or exemptions have been provided for import of goods for specified contracts
Page | 47
for exploration, development and production of petroleum goods. Further, concessions or
exemptions have been provided for the import of crude and other petroleum products. Further,
import of certain petroleum products also attracts other customs duties, in addition to the duties
discussed above, such as additional duty on import of motor spirit and high-speed diesel, and
national calamity contingent duty on import of crude oil.
Service tax is levied on services provided in relation to the mining of minerals, oil and gas and also on
the survey and exploration of minerals, oil and gas. Previously, the application of service tax
extended to the Indian landmass, territorial waters (up to 12 nautical miles) and designated
coordinates in the Continental Shelf (CS) and Exclusive Economic Zone (EEZ). Further, there was an
amendment in the law (with effect from 7 July 2009) whereby the application of service tax was
extended to installations, structures and vessels in the CS and EEZ of India.
No excise duty is levied on domestic production of crude oil but the same attracts national calamity
contingent duty as well as oil cess. On certain petroleum products, excise duty is levied both on the
basis of value and quantity. Certain petroleum products also attract other excise duties such as
additional duty (on motor spirit and high-speed diesel), special additional excise duty (on motor
spirit).
CENVAT credit is not available in respect of excise duty paid on motor spirit, light diesel oil and high-
speed diesel oil used in the manufacture of goods.
Petroleum products — petrol, diesel, naphtha, aviation turbine fuel, natural gas etc., — are subject
to VAT at higher rates, which range from 4% to 33%, depending on the nature of product and the
state where they are sold. VAT credit on petroleum products is generally not allowed as a credit
against output VAT or CST liability, except in the case of the resale of such products. Since crude oil
has been declared under the CST Act as being goods of “special importance” in the inter-state trade
or commerce, it cannot be sold at a VAT/ CST rate higher than 4%.
THE BHOPAL DISASTER
The Bhopal gas tragedy a gas leak incident is considered one of the world's worst industrial disasters.
It occurred on the night of 2–3 December 1984 at the Union Carbide India Limited (UCIL) pesticide
plant in Bhopal, Madhya Pradesh. A leak of methyl isocyanate gas and other chemicals from the
plant resulted in the exposure of hundreds of thousands of people. The toxic substance made its way
in and around the shantytowns located near the plant. Estimates vary on the death toll. The official
immediate death toll was 2,259 and the government of Madhya Pradesh has confirmed a total of
3,787 deaths related to the gas release. Others estimate 8,000 died within two weeks and another
8,000 or more have since died from gas-related diseases. A government affidavit in 2006 stated the
leak caused 558,125 injuries including 38,478 temporary partial and approximately 3,900 severely
and permanently disabling injuries.

49. CONCLUSION
In global oil industry, fiscal terms accepted by a country reflect its negotiating strength and
experience of the country, geological prospects, and the track record of previous projects. These
factors directly influence the size of the government’s revenue take.
Page | 48
With broad range of fiscal instruments available in the sector we can say that Indian policymakers
have designed a fiscal regime for oil sector that attracts investments as well as secure reasonable
revenue for the government. Despite these qualifications, there is dire need to outline some
desirable features to target in the fiscal regime for the Indian petroleum sector from the perspective
of the multinational oil companies.
One of the factors that had promoted investments in this sector was a 7 year tax holiday, which
currently had a sunset clause of 31 March 2012. The industry was hoping that the tax holiday
provisions will be extended to help realize the dream of making ‘India as a refinery hub’, but no such
extension has been done.
During the past 30 years, numerous prospective reserves for oil and natural gas have been
discovered in India. A growing economy with its inherent increase in energy demand is likely to
welcome huge investment opportunities in the oil and gas industry. It is expected that India’s energy
sector will provide investment avenues worth US$ 110 billion-US$ 160 billion over the next few
years. With large areas of India’s sedimentary basins remaining unexplored, the Indian oil scenario is
believed to comfortably cross expectations. It is high time since heed be paid towards solving various
issues faced by the industry and also substantially simplify tax laws in this regard.

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Page | 49
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