Natural Gas in India

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History, Current Scenario and Future Prospects.

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Natural Gas in India

  1. 1. The Gas History, Current Scenario & Future Prospects.Sector2012E03 Appra Zaifrani MBA, Batch of 2012-2014.2012E11 Karthik Madhavan Symbiosis Centre for Management and Human Resource Development.
  2. 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. 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 pricePage | 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, Indias 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. 4. Subsequently, more discoveries were made in the Krishna-Godavari, Cauvery and Rajasthansedimentary basins. While the responsibility of carrying out exploration and production activities inthe 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, theCentre’s liberalised economic measures opened up a few acreages to private and joint venturecompanies through various exploration bidding rounds for development of discovered fields. Page | 3RESOURCE BASEIndia has 26 sedimentary basins with an area of 3.14 million sq. km. Considering the entire 3.14million sq km of sedimentary area, inland as also shallow and deep offshore in the country, theresource 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 establishedthrough 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 commerciallyproduced, 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 othersedimentary basins that constitute about 83 per cent of the total sedimentary area. Based on theirhydrocarbon potential, these basins are classified as category-II (i.e. basins having hydrocarbonindications without any commercial production), category-III (i.e. basins, which on geologicalconsiderations are assumed to be prospective) and category-IV (basins, which on analogy withsimilar producing basins in the world are deemed to be prospective) basins. Owing to its risk-rewardperspectives, different basins or parts of the same basin, are in different stages of exploration. Theareas that were to be brought under active exploration, inter alia, include logistically difficult andgeologically complex regions. The perceived geological risk involved in carrying out the explorationfor hydrocarbons in these areas is rather high. Thus, in order to expose these areas to activeexploration requires huge financial investment and induction of high technologies. The order ofinvestment required in the upstream sector in the next 15 years is estimated to be about US$ 60billion.The Indian gas market is expected to be one of the fastest growing in the world over the next twodecades: 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 inIndia really started to grow in the late 1970s after the first major gas finds in the western offshoreand 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 asconsumption had been constrained by the lack of supply for over a decade (MoPNG, 2000). Toaddress the supply shortfall, the Indian government passed some reforms at the end of the 1990s toencourage domestic production and the construction of liquefied natural gas (LNG) terminals. Inparticular, the New Exploration Licensing Policy (NELP) opened Exploration & Production to privateand 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 KrishnaGodavari KG-D6 field in April 2009. The year 2009 therefore marks a turning point for the Indian gasmarket: 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. Butchallenges remain, illustrated by NELP’s failure to attract the major international oil companies and
  5. 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 thePage | 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. 6. compete with coal-fired plants while fertiliser producers depend on international urea price andgovernment subsidies. A market approach based on comparison with alternative fuels should betaken.Insufficient supplies: The bulk of India’s supplies is produced domestically but demand for gas isincreasing while production from the old fields has been dwindling. While most gas production used Page | 5to be produced by state-owned companies, this is changing rapidly: JVs and private companiesrepresent an increasing share of domestic production. Although domestic production will doublebetween 2008 and 2012, developing domestic gas resources is critical to increase supplies to theIndian market. Even if NELP has resulted in a certain number of discoveries, including the majorKrishna Godavari KG-D6 field, it also has some shortcomings. India is also likely to see importsincreasing over the next two decades. Although India is also located near significant resources of gasin Turkmenistan and Iran, pipeline interconnections remain a distant prospect. India has beenturning 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 inparticular are tremendous. Insufficient supplies remain a policy issue despite a relativeimprovement. Meanwhile, the downstream gas market is quite underdeveloped so that significantinvestments will be needed in order to give access to gas to more consumers. This implies attractinginvestments from both public and private companies; private companies will require a stable andtransparent 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 directionbut needs to be further enhanced.The recent decision of the Delhi High Court, in early 2010, putsPNGRB’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 developedmostly in the northwest region. In 2008, a pipeline was built to link a new production region in theEast to the existing network. In order to further develop the use of gas, it is critical to extend thetransmission 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 newinfrastructure to be built.This IEA Working Paper aims to provide a detailed yet non-exhaustive overview of the Indian gasmarket, highlighting the current challenges. It first looks at the industry structure, presents the mainplayers 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 thisreason, this Working Paper analyses both supply – domestic production and LNG imports – anddemand.X 1990 2000 2008 2009Share in TPES (%) 3 5 6 NaDomestic production (bcm) 12 28 32 46LNG imports (bcm) 0 0 11 12Pipeline imports (bcm) 0 0 0 0Consumption (bcm) 12 28 42 59% of power generation 37 44 40 Na% of industry 59 44 47 Na
  7. 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 planPage | 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 Indias 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 ($20,892 Million). The Corporation operates 2 major refineries producing a wide variety of petroleum fuels & specialties, one in Mumbai5.5 MMTPA capacity and the other in Vishakapatnam, (East Coast) with a capacity of 7.5 MMTPA. (West Coast) of Engineers India Limited was established in 1965 to provide engineering and related technical services for petroleum refineries and other industrial projects. In addition to petroleum refineries, with which EIL started initially, it has diversified into and excelled in other fields such as pipelines, petrochemicals, oil and gas processing, offshore structures and platforms, fertilizers, metallurgy and power. EIL now provides a range of project services in these fields and has emerged as Asias leading design and engineering Company. BPCL Bharat Petroleum Corporation Limited engages in refining, storing, marketing, and distributing petroleum products in India. It also involves in the exploration and production of hydrocarbons. The company offers various products, including liquefied petroleum gas (LPG), naphtha, motor spirit, special boiling point spirit/hexane, benzene, toluene, polypropylene feedstock and more. GAIL (India) Limited GAIL (India) Limited operates as a natural gas company in India and internationally. The company involves in the exploration, production, processing, transmission, distribution, and marketing of natural gas. It also offers LPG and other liquid hydrocarbons, and petrochemicals. The company owns approximately 5,800 kilometers of natural gas high pressure trunk pipeline. Reliance The Reliance Group was founded by Dhirubhai H. Ambani (1932-2002). The groups annual revenues are in excess of US$ 34 billion. The flagship company, Reliance Industries Limited, is a Fortune Global 500 company and is the largest private sector company in India.
  8. 8. The Companys operations can be classified into four segments namely: Petroleum Refining and Marketing business Petrochemicals business Oil and Gas Exploration & Production business Others Page | 7Adani Group has forayed into the Oil & Gas sector and has been awarded two oil & gas blocks inGujarat and AssamGujarat and another block with an area of 95 sq. kms. is situated in Assam. underthe recently concluded NELP VI and also plans to participate in the upcoming NELP VII bids and isactively looking at oil and gas blocks overseas. One Block with an area of 75 sq. kms is situated inCambay,Simon Carves as a part of its offshore development, projects have been carried out in India andIndonesia in providing oil and natural gas development facilities. In gas processing they have carriedout projects in Singapore, Indonesia and India in providing natural gas processing facilities and gasfield developments. A key part of many of these projects is the provision of pipeline and tanks wherein conjunction with Punj Lloyd they have considerable expertise in the design and construction ofthese facilities in often very difficult environments.Petronet LNG Limited, one of the fast growing companies in the Indian energy sector, has set up thecountrys s first LNG receiving and regasification terminal at Dahej, Gujarat, and is in the process ofbuilding another terminal at Kochi, Kerala. The Dahej terminal has a nominal capacity of 5 millionmetric 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 10MMSCMD of natural gas)ACQUISITION OF OIL & GAS ASSETS ABROADONGC VIDESH LIMITEDONGC Videsh Limited (OVL) was rechristened on 15th June 1989 from the erstwhile HydrocarbonsIndia Private Limited, which was incorporated on 5th March, 1965. Over a period of time, OVL hasgrown to become the second-largest E&P Company in India both in terms of oil production and oiland gas reserve holdings. The primary business of OVL is to prospect for oil and gas acreages abroadincluding acquisition of oil and gas fields, exploration, development, production, transportation andexport 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 andundertaking a service contract in Iraq, a major breakthrough was achieved by OVL in 1992 inVietnam with the discovery of two major free gas fields, namely LanTay and LanDo, in partnershipwith British Petroleum and Petro-Vietnam. The success carried on thereafter. In 2001, OVL acquired20% stake in Sakhalin-1 project in the far east of Russia. In January 2009, OVL completed theacquisition of Imperial Energy Corporation Plc – a UK based Company having its exploration andproduction assets in Tomsk region of Western Siberia, Russia with an investment of over USD2.1billion.
  9. 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 operationsPage | 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. 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 inPersian Gulf Iran. The contract for the Block was signed on 25th December, 2002. OVL holds 40% PI. Page | 9OVL’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 spreadover 10,500 sq. km. The Exploration & Development Contract (EDC) for the Block was signed on 28thNovember, 2000. The Company has invested approx USD 2 million till 31st March, 2010 in theproject.Syria:ONGC Nile Ganga BV (ONGBV) and Fulin Investments Sarl, a subsidiary of China National PetroleumCompany 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. OVLhad advanced approx USD 223 million towards cost of acquisition. OVL’s share in the oil productionwas 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 ofSyria. The contract for the Block was signed on 15th January, 2004. OVL holds 60% PI in the Blockwith IPR Mediterranean Exploration Ltd. OVL incurred a capital expenditure of approx USD 29 milliontill 31st March, 2010.Africa & Latin AmericaIn the African continent, OVL has acquired assets in Egypt, Libya, Sudan and Nigeria. In LatinAmerica, OVL owns assets in Venezuela, Cuba, Brazil and Colombia.Source: OVLBHARAT PETROLEUM CORPORATION LIMITEDBPCL entered the upstream sector in 2003 with the aspirations of reasonable supply security ofcrude, hedging of price risks, to become a vertically integrated oil company and to add to BPCLsbottom-line.Creation of BPRL:Considering the need for a focused approach for E&P activities and implementation of theinvestment plans of BPCL at a quicker pace, a wholly owned subsidiary company of BPCL, by thename Bharat PetroResources Limited (BPRL) with an authorized share capital of ` 1000 Crores wasincorporated in October 2006, with the objective of carrying out Exploration and Productionactivities.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 DevelopmentArea (JPDA) between Australia and East Timor were also awarded to the BPCL consortium. Also, 2blocks have been acquired through the Farm-in process (1 offshore block in Australia in 2006 and 1shallow water block in the North Sea in early 2007). Further, BPRL has bid successfully for anoffshore acreage in the North Sea (UK) in 2008. BPRL and M/s Videocon Industries Limited (VIL)
  11. 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. IndianOils 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. 12. OIL is actively pursuing opportunities to acquire producing E&P assets, exploration acreages, etc. inAfrica, Middle East, South East Asia, South America, CIS countries and Russia, and is willing toassociate with reputed companies to jointly fulfil this objective.PRODUCTION Page | 11Proven and indicated reserves of natural gas in India were 1 074 bcm as of 1 April 2009,slightly upfrom 1 050 bcm as of April 2008. The vast majority (787 bcm) represents offshore gas(287 bcm isonshore) according to the Ministry of Petroleum and Natural Gas.Exploration anddevelopmentdrilling in India is significant as domestic production has grown from 12 bcm in theearly 1990s tolevels around 30 bcm since 2000, before increasing dramatically during 2009. Thefiscal year2008/097 saw the drilling of 122 exploratory wells and 250 development wellsworking with totalmetreage 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.Aroundthree quarters of the gas production came from the Western offshore area. The shareof offshoreproduction increased to 80% in 2009/10. Fields located in Gujarat, Assam andAndhra Pradesh arethe major sources of onshore gas. Smaller quantities of gas are alsoproduced in Tamil Nadu, Tripuraand Rajasthan as can be seen in Figure 1, but this changed dueto the start of the offshore easterncoast Krishna Godavari (KG) field in April 2009.Despite a relatively long E&P history, one major issueconcerns the fact that no full geologicalsurvey of the sedimentary basins has been completed . Thisissue, which isrecognised by the government, is nevertheless critical to attract investors.
  13. 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. 14. There are nevertheless two issues affecting KG-D6 field production: one relates togovernmentdecisions on the allocation and price of the gas, and the other to the legal disputebetween theAmbani brothers, MukeshAmbani who owns Reliance Industry (RIL) and Anil Ambaniwho ownsReliance Natural Resources (RNRL). It ended in May 2010 with the ruling of the SupremeCourt. Page | 13The Allocation Of KG-D6 GasGas 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 thefollowing 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 GasFor the first 40 Mcm/d, Reliance had initially contracts to sell gas to 15 fertiliser manufacturers,19power plants and 3 steel companies. It had also signed a sale and purchase agreement withGAIL forits LPG plant and with Indraprastha Gas for city gas for 0.3 Mcm/d to be increased to0.5 Mcm/d byMarch 2010 and 2.1 Mcm/d within five years. During the first months ofproduction in 2009, RIL hadbeen 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, andRatnagiri Gas and Power, were not taking theirallocated quantities or are taking very irregularquantities which could threaten the field’soperations. Ratnagiri was not taking the 2.7 Mcm/d forwhich it signed up because it hadcontracted to buy regasified LNG from Petronet LNG throughSeptember 2009.The decision on further allocations has been made by the EGoM in November 2009; RIL willincreaseoutput to 60 Mcm/d and sell another 30 Mcm/d on an interruptible basis. The finalallocation of RIL’sgas is given in Table 5. The dramatic increase of gas use in the powergeneration sector is a clearresult of this (see section on demand). Fertilisers have been alsoswitching from expensive oilproducts to gas. A slower than expected ramp-up ofKG-D6 production would have an impact oncustomers allocated interruptible supplies.
  15. 15. CONSUMPTION Current Energy Production 16,385.61 MW INDIA’S GAS USEPage | 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. 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. 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. 18. CNG – COMPRESSED NATURAL GASCompressed Natural Gas, or CNG, is quite simply gas that has been compressed such that it can betransported in pressure vessels rather than by pipeline as is the traditional method. CNG is generallyused to fuel transit and fleet vehicles in large cities, as well as in a limited number of personalNatural Gas Vehicles (NGVs). Page | 17ScenarioIn India CNG is primarily used as an alternative fuel for transportation.The Table Summarizes theLNG activities in India in terms of stations, growth in vehicles etc.LPG - LIQUEFIED PETROLEUM GASLiquefied petroleum gas is one of the most common and an alternative fuels used in the worldtoday. Liquefied petroleum gas is also called as LPG, LP Gas, or Auto gas. The gas is a mixture ofhydrocarbon gases used as a fuel for various purposes. This is mainly used in heating appliances andvehicles and is replacing chlorofluorocarbons as an aerosol propellant. It is also used as a refrigerantmainly to reduce damage to the ozone layer.
  19. 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 thePage | 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. 20. Page | 19REFININGThe refining is very similar to that of gasoline is refined from crude oil. LPG is basically a hydrocarbonwith propane and butane as main constituent. LPG is a by-product of natural gas processing. It is theproduct that comes from crude oil refining when carried with the smaller amounts of propylene andbutylenes. LPG is largely propane and thus the characteristics of propane are sometimes taken as aclose approximation to those of LPG. When the natural gas is produced, it constitutes of methaneand some other light hydrocarbons which are easily separated in a gas processing plant. There aremany 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. 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. ThisPage | 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. 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 peakelectricityshortage up to 14%. The current capacity as of July 2010 amounts to 163.7 GW, accordingto theCentral Electricity Authority (CEA), with gas representing 11% versus 52% for coal and 24% forhydro. There are now 17.4 GW of gas-fired plants, two thirds of which have beeninstalled since1995. The IEA estimates that India’s generation capacity will increase almostfourfold between 2009 Page | 21and 2030 to reach 571 GW with gas-fired capacity increasing from17 GW to 65 GW. Electricitygenerated by gas-fired plants is expected to increase to 299 TWh by2030 (IEA, 2009). The Ministry ofPower and the CEA estimated that 78.7 GW would be neededbetween 2007 and 2012 in order tofully meet electricity and peak demand by 2012. This willalso require significant investments in boththe transmission and the distribution segments.Gas has benefited from the shortages of electricity and domestic coal which resulted inhigherelectricity prices, helping gas to be used base load even with non-APM gas. Gas availabilityhasbeen a constant problem over the 2000-09 period, but the situation has only started toimprovesince 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 wastooexpensive due to the limited availability of gas. The CEA estimated that the shortfall of gasto thepower generation sector over the period 2000-08 was between 18 and 28 Mcm/d (6.6and 10.2bcm). In 2008, the 220 MW Jegurupadu CCGT was unable to generate due to shortagesof gas while909 MW were pending commissioning for the same reason. The year 2009 has seena considerableimprovement with KG-D6 coming on line. Since then, total thermal generation has been close totargets. The gas-fired plant load factor (PLF) has increased from 57% in January 2009 to 66% in April2009 to 77% in April 2010. PLF in 2009/10 was around 10% higher than the same period one yearearlier. Meanwhile, the PLF of lignite and coal plants declined due to shortages of domestic coal andfailure to secure imports.We can expect gas supply constraints to be less of an issue in the power generation sector over thecoming 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 demandrequirements. Future demand from gas-fired plants depends strongly on the evolution of gas pricesand the path of the reforms in the coal sector. The government plans to liberalise the domestic coalsector in order to improve the efficiency and attract new investments. In most cases, it will bedifficult for gas to compete against domestic coal, especially if coal-fired plants are located nearmines. 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 requirecoal to be transported over long distances or imported, or electricity transmission lines to be builtbetween regions: these options have a cost. Imported coal could be attractive, especially at the largepower plants proposed at coastal locations. Furthermore, the policy aimed at reducing air pollutionfrom coal use (including sulphur dioxide) could give an advantage to gas. Finally, the expectedrationalisation of the Indian electricity grid could provide an opportunity for natural gas to play alarger role to meet peak demand.We have compared gas-fired plants to coal-fired plants in India, taking two approaches. The firstapproach 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 isbased on 250 MW gas-fired plants, with 46% efficiency. This is a relatively high efficiency, reflectingplants installed over the past decade. Older plants would be less efficient. As we have mentioned
  23. 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 onPage | 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. 24. will continue. If reforms in the coal sector are successful, the role of gas in base load will be morelimited. But if insufficient coal supplies are available, gas could be used more widely, even more ifgas has become more expensive, while the cost would be passed to end users. Page | 23FERTILISERSThe fertiliser industry uses natural gas as a primary feedstock instead of the more expensive naphthaor fuel oil. In 2008/09, gas demand in this sector represented 9 bcm, one fifth of total demand, butdemand has been very variable over the past five years, mainly constrained by the lack of availabilityof gas. The sector is key to maintain food self-sufficiency; it has therefore always been heavilysubsidised, with subsidies increasing from INR 15 879 crore in 2004/05 to INR 75 849 crore (USD 16.6billion) in 2008/09. This policy is therefore very expensive, especially as gas from KG-D6 was moreexpensive than APM-gas while urea prices to farmers are capped by the government. Over the pastyear, several fertiliser units have been switching to gas as new supplies from KG-D6 have becomeavailable. It can be expected that most fertiliser plants will switch from naphtha and fuel oil to gas inthe coming years, as this has been encouraged by the government. It is also more cost effective touse 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 replacedcostlier alternative fuels like naphtha.The main unknowns for future gas demand in this sector are the future subsidy policy for the farmgate price of urea and the government’s policy on self-sufficiency. Discussions to phase out subsidiesfor urea production by 2012 are ongoing; the issue will become even more challenging with therecent increase in APM prices. The government’s decision to allow more urea to be imported willalso be key. There are already JVs in the Middle East, for example in Oman, which produce fertiliserat a much lower price as gas is available at much lower prices (around USD 1/MBtu). But such adecision could face opposition from agricultural lobbies. A future shift to a greater role for imports
  25. 25. would dramatically reduce domestic gas consumption and lessen the subsidy burden on the central government. INDUSTRIAL GAS USEPage | 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. 26. vehicles). The 30 cities are mostly located in Maharashtra and Gujarat, in the North-West of thecountry. Some individual state governments have taken actions such as tax exemptions, lowerinterest on loans to support the development of NGVs. As in the residential sector, the growth of gasuse in the transport sector faces three major obstacles: expansion of the gas transport network tothe cities; construction of the necessary infrastructure within the city, including refilling stations; andthe availability of gas for CNG. Page | 25CURRENT INDUSTRY DEVELOPMENTSNATURAL GAS VEHICLESA natural gas vehicle or NGV is an alternative fuel vehicle that uses compressed natural gas (CNG) orliquefied natural gas (LNG) as a clean alternative to other fossil fuels. Natural gas (NG) as a vehiclefuel continues to grow in popularity with homeowners. With escalating fuel prices, natural gas offersmany 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 domesticresource, it promotes energy security for our country. These reasons make natural gas thealternative fuel of choice for our country.ENVIRONMENTAL BENEFITSNatural gas is one of the cleanest burning alternative transportation fuels available today and hasbeen recognized as an excellent fuel when used to generate electricity, heat homes, and fuelindustrial 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 dobecause 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) relativeto commercial diesel engines. Natural gas engines also produce less greenhouse gases (CO2) thatcontribute 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-poweredvehicle. The cost of medium and heavy-duty vehicles is largely dependent on the type of vehicle andthe number of fuel storage cylinders. Frequently, financial incentives and tax credits are availablefrom local, state and federal agencies to help offset the initial higher premium.
  27. 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). CoalPage | 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. 28. Page | 27Country wide CGD projectsIn addition to the regulatory challenges, the segment has been facing transmission and supplyconstraints. Currently, the approximately 13,000 km of cross-country pipeline network does notcover a large part of the country, especially the southern and eastern regions. Expeditious
  29. 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 Indias 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. 30. one of the few countries commercially producing CBM. India has so far awarded 26 CBM blockscovering an area of 13,600 square kilometers. The total investment committed in these blocks isaround Rs6.75 billion and as of April 1, 2006 the companies operating the CBM blocks had investedRs1.7 billion.GAS HYDRATES Page | 29Projected World Energy SupplyGas hydrates are crystalline solids that consist of gas molecules, usually methane, surrounded bywater molecules. The gas molecules are densely packed in a crystalline structure so that hydratedeposits can store vast quantities of methane. Estimates of the amount of carbon bound in gashydrates 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 areabundant worldwide, particularly in Arctic regions and in marine sediments, there is much to learnabout how they form, evolve, interact with surrounding sediments, and affect environmentalconditions when extracted.Naturally occurring gas hydrates are a form of water ice which contains a large amount of methanewithin its crystal structure. They are restricted to the shallow lithosphere (2000-4000 m depth). Withpressurization, they remain stable at temperatures up to 18°C. The average hydrate composition is 1mole of methane for every 5.75 moles of water. The observed density is around 0.9 g/cm3. One literof 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. 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 carbonPage | 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 Earths 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. 32. If mismanaged, the hydraulic fracturing fluid can be released by spills, leaks, or various otherexposure pathways. The use of potentially hazardous chemicals in the fracturing fluid means thatany release of this fluid can result in the contamination of surrounding areas, including sources ofdrinking water, and can negatively impact natural habitats. Page | 31RENEWABLE ENERGYRenewable energy is that form of energy which comes from natural resources. These naturalresources include sunlight, wind, rain, tides, and geothermal heat, which are renewable (naturallyreplenished). 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) accountedfor another 3% and are growing very rapidly. The share of renewables in electricity generation isaround 19%, with 16% of global electricity coming from hydroelectricity and 3% from newrenewable.While many renewable energy projects are large-scale, renewable technologies are also suited torural and remote areas, where energy is often crucial in human development. As of 2011, small solarPV 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 digestersfor 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 thatrenewable energy has the ability to lift the poorest nations to new levels of prosperity. Carbonneutral and negative fuels can store and transport renewable energy through existing natural gaspipelines and be used with existing transportation infrastructure, displacing fossil fuels, and reducinggreenhouse gases.Climate change concerns, coupled with high oil prices, peak oil, and increasing government support,are driving increasing renewable energy legislation, incentives and commercialization. Newgovernment spending, regulation and policies helped the industry weather the global financial crisisbetter than many other sectors. According to a 2011 projection by the International Energy Agency,
  33. 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 isPage | 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. 34. FDI IN PETROLEUM AND NATURAL GAS SECTORSince a long time 100% FDI under automatic route has been permissible for all activities in thepetroleum and natural gas sector, other than the refining activity (for which a separate FDI policywas prescribed). However, for actual trading and marketing of petroleum products, although FDI upto 100% was allowed through the automatic route, such an approval was subject to the condition of Page | 33divestment of 26% equity in favor of the Indian partner/public within 5 years. The Government hasnow approved deletion of the conditionality of compulsory divestment of 26% equity within 5 yearsfor actual trading and marketing of petroleum products.FDI up to 100% is allowed through the automatic route for refining activity in the private sector, butfor refining activity in the public sector, infusion of FDI has been permitted only up to 26%, and withthe prior approval of Foreign Investment Promotion Board (FIPB). The Government has nowapproved that infusion of FDI for refining activity in the public sector will henceforth be permitted upto 49%, and with the prior approval of the FIPB. However, the decision does not envisage orcontemplate 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 duringJanuary 2000 to December 2009 is Rs. 11,265.78 crores (US$ 2.61 billion) which 2.47% of the totalFDI inflows.FUTURE PROSPECTSWhile a considerable area is available in the country for carrying out exploration activities forhydrocarbons, so far as the demand versus domestic availability of crude oil is concerned, India’sposition of 63 per cent self-reliance in 1989-90 became 31 per cent in 2000-01. One of the mainreasons for a comparatively lower growth in the country’s oil production is the absence of majordiscoveries of hydrocarbon resources in recent years. Thus, there is an urgent need to increase theavailability of indigenous crude oil through increased exploration in the country. Over the last 15years, the demand for petroleum products has risen at an annual compound rate of about 6 percent. During the last few years, the crude oil production in the country has been at a rate of around32 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 metersper day (MMSCMD) as against the projected demand of around 151 MMSCMD in 2001-02. Thedemand for petroleum products in the country during the current year is about 138 MMT and isexpected 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 ofIndia has felt the need to accelerate the pace of exploration for hydrocarbons in the country. To thiseffect, the Government has recently come up with ‘India Hydrocarbon Vision – 2025’ wherein thestrategic directions were provided towards exploration of the Indian sedimentary basins in a phasedmanner in keeping with technological advancement and environmental concerns. To achieve the setobjectives, the implementation schedule envisages continuance of exploration in producing basins,pursuit of extensive exploration in non-producing and frontier basins, a programme for appraisal ofthe Indian sedimentary basins to the extent of 25 per cent by 2005, 50 per cent by 2010, 75 per centby 2015 and 100 per cent by 2025.
  35. 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 anPage | 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

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