increase from 23 per cent in 2001 to 28% in 2025. The most robust growth in natural gas demand is expected to take place in developing nations, where overall demand rises by 3.9 per cent per year between 2001 and 2025. The level of natural gas use in the developing world by 2025 is projected to be two and a half times the 2001 level. Much of the growth in the region is expected to fuel electricity generation, but infrastructure projects are also expected to displace polluting home heating and cooking fuels with natural gas in major urban areas. Several factors contribute to natural gas becoming the preferred fuel of the future. It has the advantage of being a clean and an environment friendly fuel, has better heat efficiencies, is widely distributed geographically, and finally, it is less prone to price fluctuations. As of January 1, 2003, proved world natural gas reserves, as reported by Oil & Gas Journal, were estimated at 5,501 TCF, 50 TCF more than the estimate for 2002. Most (about 71 per cent) of the world’s natural gas reserves are located in the Middle East and the East Europe/ Former Soviet Union, with Russia and Iran together accounting for about 45 per cent of the world’s natural gas reserves. Reserves in the rest of the world are fairly evenly distributed on a regional basis. However, most of the increase is attributed to developing countries, where gas reserves have increased by 37 TCF since last year’s survey. Among the regions of the developing world, Africa and Asia had the largest revisions in proved natural gas reserves between 2002 and 2003. In Africa, the entire increment of 23 TCF in gas reserves is attributable to Egypt, where a marked increase in exploration activity over the past few years has resulted in a substantial increase in gas reserves, including finds in the Western Desert, Gulf of Suez, Mediterranean Sea, and Nile Delta. Developing Asia saw an increase in reserves of 11 TCF over the past year. Among the developing Asian countries, the greatest increases in proven reserves were in China and India, where reserves grew by 5 TCF and 4 TCF, respectively. Modest increases in proved reserves were witnessed in Pakistan, Philippines, and Thailand. According to World Petroleum Assessment 2000, a significant volume of natural gas remains to be discovered. The mean estimate for worldwide-undiscovered gas is 4,839 TCF. A further 3,000 TCF is estimated to be “stranded or remote locations” reserves. The amount of natural gas traded across international borders continues to grow, increasing from barely 19 per cent of the world’s consumption in 1995 to 23 percent in 2001. Pipeline exports grew by 39 per cent and the LNG trade grew by 55 per cent between 1995 and 2001. The fact that many sources of natural gas are far from demand centers, coupled with cost decrease throughout the LNG chain, is making LNG increasingly competitive, contributing to the expectation of strong worldwide growth for LNG. The world’s natural gas trade can be divided into two major trading regions: the Pacific, where LNG is the predominant commodity and the Atlantic where pipeline gas as well as LNG are traded. The future demand for natural gas is expected to come from developing nations, such as, India and China, which currently have very low per capita gas consumption as compared to consumption in USA, the former Soviet Union, etc. But these developing markets are expected to be extremely price sensitive. Traditionally, the conventional, long-term, take or pay (ToP) LNG supply contracts so signed were rigid and offered little flexibility to buyers. These contracts were primarily meant to address sellers’ concerns and to recover the huge capital expenditure incurred in setting up the liquefaction and transportation infrastructure on the LNG projects during the developmental phase. This development phase is now agreed to be over and the market is now reaching a mature stage. The last couple of years saw the onset of a new era in LNG trade wherein the pricing and contract terms are flexible. The LNG buyers who were uncomfortable with conventional contracts because of the growing demand uncertainty and price sensitivity of the end customer started voicing their concerns, and this became evident in most of the deals that took place last year setting the momentum for buyers to have hard negotiations with the sellers. The recent Guangdong project bargain deal has set a precedent for future deals. In August 2002, an Australian LNG consortium (North West Shelf) finally succeeded in getting a supply agreement signed with China for its first LNG receiving terminal situated in Guangdong. The contract term is reported to be 25 years from 2005-2006, and the contract volume 3 MMTPA. According to reports, the deal was struck for under 3 $/MMBtu (for crude oil price of $20/barrel) causing serious unrest amongst the Japanese buyers who were so far paying almost 20 per cent more. Correcting the Guangdong price by distance puts the LNG price in Japan at a little above $3. In comparison, the exship price of LNG imported from NWS to Japan stays within the latter half of the 3 $/MMBtu mark when linked to $20/barrel of crude oil (estimated from customs clearance statistics and others). Hence, if the reported Guangdong price is correct, the resultant differentials

amount to as much as 20 per cent. Also, India’s Petronet project reached an agreement with RasGas of Qatar on the price offered to the Dahej LNG terminal for the supply of 5 MMTPA of LNG. According to unconfirmed media reports appeared in October 2003, the final negotiated price between Petronet LNG and RasGas has pricing designed to limit volatility by fixing the crude price at $20/barrel for the beginning years. The new contract price provides complete insulation from oil price fluctuations. Spot trading of LNG, which is a yardstick of flexibility, is increasing at a rapid rate. Transactions under short-term contracts (less than a year and inclusive of spot trading) in 2001 recorded a tenfold increase over 1992 levels and reached a hefty 8 per cent of total LNG trade (IEA, “Flexibility in Natural Gas Supply and Demand”). The coming years will also see innovative logistic and LNG transportation solutions. The increased short-term trading of LNG and the swapping of cargoes to optimize shipping will be the ways in which suppliers would respond to the market needs. LNG trade shall also become more global in nature with LNG ships trading between the Atlantic Basin and Asia Pacific and Middle East project start to play a swing role between the regions. Decreasing cost of LNG-ship building will mean more options to buyers and sellers. The future will also see new risk distribution models wherein buyers shall undertake the risks and rewards that were so far considered to be under the domain of the sellers only. The changes taking place in the LNG industry provide both challenges and opportunities to the stakeholders to achieve price levels and contract terms that balance the expectations of both buyer sand sellers. If LNG is to successfully compete with existing fuels in the developing countries, innovative pricing structures and contractual terms will have to be developed that take into account the industry’s changing characteristics. With these innovations in place, LNG would establish itself as a viable energy option in developing markets.

Natural Gas
Natural gas is a highly flammable hydrocarbon gas consisting chiefly of methane (CH4). Although methane is always the chief component, it may also include other gases such as oxygen, hydrogen, nitrogen, ethane, ethylene, propane, and even some helium.
The gas is found entrapped in the earth's crust at varying depths beneath impervious strata, such as limestone, and may or may not be in association with oil. If oil is present it is called wet gas, else dry gas.

Natural gas is a colorless, odorless fuel that burns cleaner than many other traditional fossil fuels. Natural gas is used for heating, cooling and production of electricity besides for various other industrial purposes. The principal constituents of natural gas are Methane and Ethane, but most gases contain varying amounts of heavier hydrocarbons that may be removed by processing. In India, the C3 and C4 fractions of natural gas are usually recovered in a Liquefied Petroleum Gas (LPG) fractionator plant for making LPG. Typically, a 1:1 Propane-Butane mix on mass basis is used for making LPG in India. After the recovery of the Propane and Butane fractions from the ‘rich gas’ stream, the stream of gas downstream of LPG recovery Plant (known as lean gas) is returned to the pipeline system. While all fractions of the rich gas can be as such used by fertilizer and power plants as feedstock or fuel respectively, the value added to the C2, C3, C4, C5 and heavier fractions is greater when they are used for the production of LPG or when C2 and C3 is used for the production of petrochemicals. The removal and separation of individual l hydrocarbons by processing is possible because of the differences in their physical properties. As each component has a distinctive weight, boiling point, vapor and physical characteristics, its separation from other components is a relatively simple physical operation. Natural gas may also contain moisture, Hydrogen Sulfide, Carbon Dioxide, Nitrogen, Helium, or other components that may be diluents and/or contaminants. Natural gas is processed to remove unwanted water vapor, solids and/or other contaminants that would interfere with pipeline transportation or marketing of the gas. Liquefied Natural Gas – LNG is nothing but natural gas reduced to a liquid State by cooling it to -161°C. Once liquefied, the natural gas is more compact occupying 1/600th of its gaseous volume. Natural gas is liquefied because in gaseous form it is extremely voluminous and cannot be transported to long distances as gas fields are far-off from the user market. Liquefied

form eliminates the need for more room for gas transportation. LNG is transported in special tankers and brought to the receiving regasification terminal in another location. It is regasified at the terminal itself and transported through a pipeline.
Natural Gas meets many of the requirements for fuel in a modern day industrial society. It is efficient, clean burning fuel, eco friendly and has flexibility of control. The key uses are:
Electricity generation by utilities: Fuel for base load power plants and for use in combined cycle/co-generation power plants.
Public and commercial: LNG is clean fuel for use as is piped Gas in household. Economically cheaper as compared to LPG. In fact most of the Western Countries use piped gas in houses. The household use of piped gas is expected to increase in future.
Industrial: As an under boiler fuel for steam raising and heating applications.
Alternative Motor fuel to diesel: With only one carbon and four hydrogen atoms per molecule, natural gas is the cleanest burning fossil fuel. Moreover, it has 30 to 40 % higher fuel efficiency for running motor vehicles. Due to environmental considerations, the use of natural gas in Automotive Sector is bound to increase considerably on account of higher efficiency and being a cleaner fuel.
Petrochemicals: A variety of chemical products e.g. methanol can be derived from natural gas.

Natural gas units
1 Billion Cubic Metre = 35.3 Billion Cubic Feet Natural gas
= 0.90 Million Tonnes Crude Oil
= 0.73 Million Tonnes LNG
= 36 Trillion British Thermal Units
= 6.29 Million Barrels of Oil Equiv.
1 million british thermal unit = 1 thousand cubic feet (Mcf)
1 MMT LNG = 1.23 MMT oil equivalent
1MMTPA LNG = 3.5 MMSCMD of Natural gas
MMSCMD: Million Standard Cubic Metres Per Day

Benefits of natural gas
The relative merit of natural gas to alternate hydrocarbon fuels is driving the demand for gas. Gas is a clean fuel offering higher thermal efficiencies (in power generation) and higher yields (in the manufacture of fertilizers). Gas turbines have lower capital costs, shorter gestation period and can supply peaking power. Further, it contains no Sulphur making it ideal fuel for transportation purposes. Lower CO2/ CO emission implies environmental friendliness of the fuel. In addition to its environment friendliness, natural gas has other advantages. It is lighter than air and, therefore, safer (in case of any leakage, being lighter than air, it does not tend to accumulate and settle down). It is extremely convenient to use, since customers just have to switch it on like electricity. There is no storage needed at the users’ end which means that they can productively use the space and not worry about running out of stored fuel. Moreover, consumers do not have to take the trouble of handling the fuel as in the case of coal. Then, consumers are billed for the fuel that actually enters their premises, unlike in all other fuels where they are billed for the quantity that has gone out of the supplier premises.

Indigenous resources and availability
Almost 70 per cent 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). Small amounts of reserves have also been found in Rajasthan. Although the state owned enterprises increased the reserve base significantly over the period 1975- 90, the gap between domestic production and demand widened significantly in the 90s. As a result, initiatives were taken to encourage private sector investment in the E&P sector, with exploration acreage offered to private companies under production sharing arrangements with the Indian government. Accordingly, in June 1994 the government awarded the first Joint Venture (JV) fields to be operated by joint ventures of state enterprises with private companies. Until April 1998, E&P activities in the country were steered mainly by the PSUs – ONGC and OIL. However, with less than 25 per cent of the country’s sedimentary areas covered under exploratory surveys, along with the stagnating domestic hydrocarbon production and declining reserve replacement ratios, the Government of India felt the urgency to harness its potentially substantial hydrocarbon reserves. Therefore in 1999, the Government of India introduced the New Exploration Licensing Policy (NELP) to provide attractive incentives and level playing field to new entrants, including foreign companies in the E&P sector. After the opening up of the E&P sector apart from ONGC and OIL, many players including big domestic and international companies entered the arena. Bidding results in all the four rounds of NELP so far show that while ONGC is set to dominate, Reliance is emerging as an important player.

Reserves
The total resource base of oil and gas is the entire volume formed and trapped in-place within the Earth before any production. The largest portion of this base is non-recoverable by current or foreseeable technology. This inability is either because of un favourable economics, or intractable physical forces, or a combination of both. At the next level, the recoverable resources are divided into discovered and undiscovered segments. In India reserves are classified as (a) Prognosticated (which is basically all the resources "expected" to be contained), (b) geological or in-place which is discovered resources but not recoverable and (c) balance recoverable reserves. The total proven reserves on natural gas in India as at the end of FY2002 was about 750 billion cubic metres. The giant gas discovery in the KG baisn resulted in the reserves at the end of FY2003 increase to 920 billion cubic metres (mcm). 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.

Demand (See annexure)
The current production of natural gas in the country is around 86 MMSCMD. After taking into account the internal consumption, flaring, shrinkage on account of extraction of LPG and C 2 and C 3 fractions, etc. the net availability of gas for supply to the consumers is to the extent of around 68 MMSCMD. As against this, the total firm commitments made in terms of gas allocations to various consumers is to the extent of about 120 MMSCMD. This figure indicates the allocation made and does not take into account the large unmet demand of gas. As per the study conducted by an Expert Group constituted by Ministry of Petroleum and Natural Gas a few years earlier, the demand for gas was assessed at 188 MMSCMD in 2004-05 and 283 MMSCMD in 2009-10. The Government under the technical assistance of Asian Development Bank also commissioned a

study. This study conducted by M/s Bechtel Ltd., UK also indicated that the demand could vary between 203 MMSCMD (high case) to 140 MMSCMD (low case) in 2012. In another estimate the same study indicated that the demand supply gap would increase to 226 MMSCMD by 2020. Similarly, the India Hydrocarbon Vision –2025 also estimated the demand at 117 MMSCMD by 2002, which would gradually increase to 322 MMSCMD by 2025 in one scenario and to 391 MMSCMD as per another scenario. Therefore, the demand-supply gap ranges from 47 MMSCMD in 2002 to nearly 355 MMSCMD in 2025. Currently, only 68 MMSCMD of gas is available to the consumers. The gas recently tapped by Reliance in Krishna-Godavari Basin, in Andhra Pradesh, will be available to the consumer in another two to three years. However, even if the entire 40 MMSCMD4 from Reliance’s gas find is added to the current availability of gas, the total GAIL - Infraline Natural Gas in India: A Reference Book Various Gas Demand Estimates for 2006-07 gas that could be supplied to the consumer comes to 108 MMSCMD, leaving still a gap with unmet demand.

Supply
The current scenario is likely to change, as the supply position will improve considerably by 2006-07 as a result of development of new discoveries. There are a number of estimates of demand made at different points of time by different agencies whose objectives were also different. Therefore, there are variations in the results of these studies. While some of the studies have taken price elasticity of demand in consideration but most of them have not. The chapter on Demand-Supply presents five such cases. First case presents the potential gas demand estimates of GLC based on the existing allocations and growing applications for further allocation of more gas. The second case gives the estimates as per the Hydrocarbon Vision 2025 and the third case is the summation of gas master plan developed by Asian Development Bank in 1999. Fourth case highlights the GDP Indexed demand growth as estimated in a study conducted by TERI, which is based on the calculation of imputed value of gas and covers the price sensitivity. Finally, the fifth case throws some light on the region-wise estimates after including the likely supply from recent gas finds, such as, those of Reliance.

Natural gas production
Unlike in the case of crude oil production in India, the production of natural gas is showing an upward trend although at a nominal production growth rate of 3.6% per annum (during FY1998-2002). In fact, natural gas production in India has been increasing continuously. The production of natural gas was about 8 b cm in 1985-86, 26.4 bcm in 1997-98, 27.4 bcm in 1998-99, 28.4 bcm in 1999-00, 29.4 bcm in 2000-01 and 30.4 bcm in 2001-02.
The production of natural gas by private players from the discovered fields has increased over the last five years. This has been on account of additional development in the fields awarded to these players in the initial rounds of development in the early 1990s.
Among the States, Gujarat accounts for the major share of onshore natural gas production (33%) followed by Assam/Nagaland (27%). The following Table presents the State-wise natural gas production figures for the last few years.

India’s natural gas production reached a level of 31.4 BCM in 2002-03, of which, 82.78 per cent was from the National Oil Companies (ONGC and OIL) and the remaining 17.22 per cent from private players, including joint ventures. Today, India accounts for about 0.5 per cent of the world’s total natural gas reserves. The recent discovery of major gas deposit in Krishna-Godavari (KG) by Reliance and further positive indications from other licensees drilling in KG and other basins could change these figures. The discovery stands as the biggest gas find in India in three decades and was among the world’s largest gas discoveries in 2002. This is also the first ever discovery by an Indian private sector company. Reliance hopes to have the field in production by 2006-07, with daily production of up to 40 MMSCMD. Apart from Reliance discovery, there are other gas finds by ONGC, Cairn Energy, Niko Resources, GSPL-GAIL in the recent time. The

new discoveries will definitely ensure more energy security for India, as the country will become self-sufficient in resources. This, in turn, will help the development of other sectors (power, fertilizer, cement, steel, etc.), which are currently deprived of gas use because of non-availability. Apart from the potential in conventional gas reserves, CBM and Gas Hydrates are expected to be an additional source of supply in the long term. CBM blocks nominated by DGH are estimated to contain 18 trillion cubic feet (TCF) of gas in place and are estimated to support a gas production rate of 20-40 MMSCMD. Commercial production in India is expected to commence by 2006-07.

Import Option
The increased energy demand driven by high economic growth has widened the demand-supply gap. The demand for natural gas in particular, has been increasing because of its environment friendly nature, making it a competitive fuel/feedstock in power and fertilizer sectors. The existence of inferior quality coal coupled with high transportation costs and environmental concerns is grossly eroding its usage for meeting energy demands. With the result, natural gas is emerging as a popular fuel. The country has not been able to meet the demand with the available domestic production till recently. The demand is likely to grow, rapidly in the near future. Given that the domestic gas supply is not likely to keep pace with demand, India will have to import gas either via pipeline or as LNG even after the recent gas discoveries. There are significant gas reserves in countries adjacent to India that could be utilized to meet the import requirements indicated by the supply shortfall. These reserves are primarily concentrated in the Middle East (Iran and Qatar), Turkmenistan, South Asia (Indonesia, Malaysia) and Australia. Iran provides both a possible source of gas and the best access to the gas/oil reserves of Central Asia. The gas reserves in the Eastern neighborhood are of strategic importance to India. Myanmar had initial success in the exploration of its offshore reserves. Bangladesh has an active exploration program and a large potential for exploring gas. Indian Government thus, has been actively thinking of a long-term co-operation with these two nations in the field of energy. The Indian Government has put LNG/Gas imports under ‘Open General License’ and companies are free to develop such projects and market gas directly. The Foreign Investment Promotion Board (FIPB) has given approval to several proposals of LNG terminals. To give a thrust and support to the develop- ment of LNG trade in India, Government has also set up a joint Venture Company – Petronet LNG Limited (promoted by ONGC, IOC, BPCL and GAIL), to execute LNG projects at Dahej (Gujarat) and Kochi (Kerala). Also, private players like Shell are also participating actively in setting up LNG terminals.

Gas Transmission and Distribution
In view of the need to create gas sector infrastructure for sustained development of gas markets across the country, Gas Authority of India (GAIL), now known as GAIL (India) Limited, was set up by Government of India on August 16, 1984 with the responsibility to develop pipelines and to process, market and plan the optimum utilization of natural gas, thereby enabling OIL and ONGC to concentrate on the exploration and production of hydrocarbons in India. Prior to the formation of GAIL, approximately 725 km of local regional pipelines were constructed and operated by ONGC, apart from around 320 km of pipeline laid by various customers. In 1986, work began on the Hazira-Bijaipur- Jagdishpur (HBJ) gas transmission line linking the gas sourced from Bassein fields landing at Hazira in Gujarat with fertilizer, power and industrial consumers in Gujarat, Rajasthan, Madhya Pradesh and Uttar Pradesh. In 1987-88, the country’s first crosscountry, 1700 km long, 18.2 MMSCMD capacity HBJ pipeline system was successfully commissioned by GAIL in 22 months,14 months ahead of schedule. Today, GAIL is the national gas company in India with a ready-built infrastructure for transmission and marketing of natural gas over long distances in the country. GAIL owns and operates around 4,500 km of pipeline which currently transports over 22 BCM of natural gas every year. The most prominent pipeline of GAIL is the 2,700 km HBJ pipeline which has a capacity to handle 33.4 MMSCMD of natural gas. The other pipelines of GAIL are the regional ones located in Mumbai, Gujarat, Rajasthan, Andhra Pradesh, Tamil Nadu, Pondicherry, Assam and Tripura. Gujarat State Petroleum Corporation (GSPC), a Gujarat

Government owned company, has also entered the gas transportation business and is setting up an Rs 32 billion, 2,500 km pipeline network for transportation of gas within the state of Gujarat. This two-phase pipeline project is being executed by Gujarat State Petronet Ltd. (GSPL), a special purpose vehicle (SPV) floated by GSPC. Phase 1 involves an investment of Rs 12 billion and covers a distance of 525 km from Vadnagar in the north of Gujarat to Vapi in the south. Phase II involves extending the network to Saurashtra, Surendranagar, Rajkot and Jamnagar. The length of this segment is 500-600 km and the investment involves Rs 20 billion. Among other regional pipelines, Assam Gas Company has a prominent pipeline network in northeast India. In addition to its 250 km pipeline linking Sibsagar with Marsharita in Assam, it has over 350 km of branch pipelines in the region. After the discovery of gas reserves in KG Basin in October 2002, Reliance is also having a re-look on its proposed pipeline network. RIL, which has plans to lay a network of pipelines across the country to transport petro products from its 27 MMT Jamnagar refinery to a large number of cities in the country, now plans to acquire the right of usage to lay two separate gas pipelines for (i) transporting the KG gas to Goa in the country’s western part and (ii) from Jamnagar to Cuttack in the east coast. The smaller pipeline networks of GAIL supply gas to industries from offshore and onshore gas fields in the western, northeastern and southern parts of the country. The regional pipelines are in the states of Mumbai, Gujarat, Rajasthan Andhra Pradesh, Tamil Nadu, Pondicherry, Assam and Tripura. City Gas Distribution Systems In the eighties, GAIL initiated techno-economic feasibility studies for gas distribution in the metro cities of Mumbai and Delhi through Sofragaz and British Gas respectively. Based on the encouraging recommendations of these studies, the Government of India approved gas allocation for Mumbai and Delhi. Mahanagar Gas Limited (MGL), a Joint Venture company of GAIL, British Gas and the Government of Maharashtra was incorporated in May 1995 for supply and distribution of natural gas (NG) to domestic, commercial, small industrial consumers and CNG to vehicular consumers in Mumbai through its integrated gas pipeline network. Similarly Indraprastha Gas Limited (IGL), a JVC of GAIL, BPCL and Government of National Capital Territory (NCT) of Delhi was incorporated in December 1998 for developing a distribution network for the residential, transport and commercial consumers in Delhi. Gujarat Gas Company Limited (GGCL), promoted by British Gas, has developed the gas distribution network in Surat, Bharuch and Ankleshwar of Gujarat. In Baroda (Vadodara), the distribution network has been developed by Municipal Corporation of Vadodara. In Andhra Pradesh, GAIL, HPCL, APIIC and KSPL have jointly promoted Bhagyanagar Gas Limited in August 2003. The objective of Bhagyanagar Gas is to provide city gas distribution (to start with in Vijaywada and Hyderabad-Secundrabad), eco friendly fuels (LPG - to start with in Tirupathi and twin city) to provide natural gas/LPG to small scale industries and commercial centres and related services in the State. As per the direction of the Supreme Court, GAIL is also supplying gas to the polluting industries in Agra and Ferozabad of Uttar Pradesh through distribution system in the area to protect the pristine beauty of Taj Mahal. Recently, in August 2003, Hon’ble Supreme Court has issued a directive to the Union of India and the state governments to draw plans to introduce clean fuels in 11 cities apart from the existing cities of Delhi and Mumbai. These are Kolkatta, Chennai, Bangalore, Hyderabad, Ahmedabad, Surat, Lucknow, Kanpur, Agra, Pune and Sholapur Under its Project Blue Sky, GAIL has already drawn plans to implement city gas projects in the five cities of Kanpur, Lucknow, Agra, Bareilly and Pune in phases at an estimated investment of Rs 5.54 billion (Rs 100 crore = 1 billion). Recently, government of Gujarat has issued No Objection Certificates to various entities to implement city gas projects in various cities including Ahmedabad, Vadodara among other cities in Gujarat. However, it is understood that MoP&NG is drawing up plans to implement city gas distribution projects across the country including the 11 cities as listed out by the Supreme Court through various project/state specific Joint Venture Companies comprising GAIL and Oil Marketing Companies like IOC, BPCL and HPCL; local bodies of the State Governments and other strategic partners. Planned Pipeline Projects Dahej-Vijaipur Pipeline (DVPL) Project The Rs 2,936 crores, 610 kms, DVPL project is being implemented by GAIL on a fast track basis with a squeezed schedule to synchronize with the Dahej LNG terminal’s completion schedule of December, 2003. DVPL pipeline shall cater to the western and northern markets in India along the existing HBJ corridor. Dahej-Uran Pipeline (DUPL) Project GAIL has approved the execution of Dahej-Uran Pipe Line (DUPL). The Rs 1416 crores DUPL project shall provide the vital trunk pipeline link between the key gas markets of Maharashtra and Gujarat. Gujarat Gas Grid Project

The Gas Grid Project promoted by Gujarat State Petronet Ltd. envisages transporting indigenous natural gas from production centers and LNG from terminals to demand centers all over Gujarat through a high pressure Trunk Pipeline. It is a pipeline transmission project to deliver gas to end-users and for local distribution. Pipeline for KG Basin Gas Gas Transportation and Infrastructure Company Limited (GTICL) a company promoted by Reliance Industries Ltd. has proposed to lay a pipeline from Kakinada-Hyderabad-Goa for which the process of acquisition of land under Petroleum and Mineral Pipeline (Acquisition of Right of User in Land) Act, 1962 is underway.

End Use Consumption
Natural gas is used in a variety of applications, such as, power plants, fertilizer plants, industrial units, sponge iron manufacturing, ceramic industries, transportation industry, air conditioning and other industrial applications. In India, the fertilizer and power sectors account for over 74 per cent of the country’s total natural gas consumption. The sale of natural gas to fertilizer industry increased from 20.79 MMSCMD in 1995-96 to 22.10 MMSCMD in 2001-02 and reached 22.49 MMSCMD during April-September 2002. The share of natural gas as feedstock in nitrogenous fertilizer production is 47.2 per cent followed by naphtha, which has 30.8 per cent. Furnace oil and coal have a share of 10.7 per cent and 2.7 per cent respectively. The Department of Fertilizer has indicated that as against the actual supply of 22.10 MMSCMD gas to the fertilizer sector in 2001-02, the total gas requirement in 2006-07 would be 43.6 MMSCMD. The growth in gas demand would mainly come from additional supplies i.e., re-gasified LNG becoming available during the Tenth Five Year Plan Period for existing plants and their expansions. The current average gas supply to the power sector is 35 MMSCMD. The estimated requirement for power sector is expected to grow from the present level of around 35 MMSCMD to 52 MMSCMD of natural gas/LNG by 2006-07. Being a relatively clean fuel with lower/nil emission levels of SOx, NOx and SPM, natural gas in its compressed form is being promoted by the government as a fuel for the transport sector, under the directives of the Supreme Court of India. CNG has already replaced approximately 531 kl (kilo litre) diesel and 315 kl of petrol in Delhi. In Mumbai CNG has replaced 102 kl of diesel and 350 kl of petrol. Going forward, GAIL (India) limited has also announced its “Project Blue Sky” to replicate the success of CNG in Delhi and Mumbai. CNG for the cities of Agra, Pune, Kanpur, Lucknow and Faridabad are planned by GAIL at a cost of Rs 5.54 Pattern of Gas Use in India bilion during phase-I of this “Project Blue Sky”. In association with HPCL, GAIL is also planning to start city gas distribution in Andhra Pradesh through Bhagyanagar Gas Ltd. Gas based petrochemicals production plants rely on domestic production of C2/C3 fractions by processing of gas. Based on the requirements indicated by the Ministry of Chemicals and Fertilizers and Ministry of Power and also considering that the sectoral mix of gas use in 2006-07, would be comparable to the sectoral mix prevailing at the end of 2001-02 (80 per cent gas use by power and fertilizer sectors), the overall gas demand by 2006-07 would reach about 125 MMSCMD. The huge domestic gas find by Reliance in the KG basin is also likely to impact the major consumers of gas i.e., power and fertilizer units. As regards the impact on the power sector, a recent CRIS-INFAC study indicates that 40 MMSCMD gas can support around 10,400 MW of power capacity. As regards the impact on the fertilizer sector, the study states that 40 MMSCMD can support around 29 MMTPA of urea capacity.

National Gas Grid
In the wake of recent world class gas finds in the east coast and the imminent arrival of LNG cargos on the western coast of India, Indian gas sector is moving away from a supply constrained market to a multi-source multi-market entity. In this emerging scenario, the need of the hour is an integrally planned optimum National Gas Grid to serve the entire industry on an “open access” basis. Gas Pricing Till the 1970’s, gas prices were based on the recommendations given by expert committees. In the early 1970’s, ONGC set gas prices on a negotiated basis, resulting in different gas prices for different consumer segments. In mid 70’s, the price of natural gas was determined by the producers themselves, based on the thermal equivalence of substitute fuels and the opportunity cost to the consumer. In 1986, a decision was taken by the Government of

India to fix uniform prices for natural gas on a year to-year basis. This policy was followed till 1991. From January 1, 1992, the prices of natural gas were fixed for a period of four years up to December 31, 1995. This pricing was based on the recommendation of the Kelkar Committee, set up by the Government to examine natural gas prices. Post December 1995, the consumer price for non-North East places was fixed by the Government at 1,850 Rs/tcm (thousand cubic metre) (exclusive of royalty @ 10 per cent and class tax varying from 0 to 19 per cent) for a calorific value of 9,000 kilo calories. The corresponding figure for North East India was 1,000 Rs/tcm with a provision for further discounts. In January 1995, the Government appointed a Committee under the chairmanship of Mr T L Sankar to review the pricing of natural gas. Based on the recommendations of this Committee, Government fixed a price band of 2,150 Rs/tcm as the lower limit and 2,850 Rs/tcm as the ceiling for the consumer price. Producer Price actually payable to producer (ONGC) was pre-determined at an amount lower than the consumer price so that the difference between the Consumer Price and Producer Price was to be credited to a Gas Pool Account. Gas Pool Account was established in order to encourage the development of the gas industry in India by partly compensating exploration and development companies for the low margins received in the development and sale of gas at prices fixed by the government. In addition to the price as fixed above, royalty, taxes, duties and other statutory levies on the production and sale of natural gas is payable by the consumers. The royalty on gas as fixed under the Oilfields Development Act is 10 per cent of the wellhead price. For privately operated fields, the royalty is fixed on the negotiated wellhead prices. There is no cess on natural gas (unlike crude oil) although a cess could be levied under the law. There is no excise duty on nat-tive Summary ural gas or on crude oil, as these are minerals although excise duty is charged on petroleum products. A sales tax is leviable at state rates if the sale is within the state or at the central rate of 4 per cent for inter-state sales. The sales tax rates vary from state to state ranging from zero to 22 per cent. It may be noted that GAIL does not make a margin on merchant sales; it is allowed a return only on its investment in the pipeline. In order to encourage investment in the exploration of oil and gas, Government has allowed the contractors, freedom to market oil and gas produced under NELP. Accordingly, oil and gas produced under NELP blocks are not covered under the Administered Gas Pricing Mechanism and the producers are free to market the gas at the market determined prices. Recently, on July 23, 2003, a Group of Ministers, represented by producer and user Ministries, met and recommended the following: 1. The natural gas prices to be increased on an adhoc basis with immediate effect, as the prices have remained static since October 1999. 2. A Tariff Committee to be appointed to study the cost structure of ONGC and OIL, and suggest a reasonable price, within six months, for the period till complete deregulation of the gas prices is brought about. 3. The price of gas is raised from 2,850 Rs/tcm to Rs 3,200/tcm, a rise of 12.28 per cent. 4. The gas produced by the joint venture of Tapti and Panna-Mukta of about 8 MSCMD to be sold by GAIL/producer at market-determined price. However, 1 MSCMD of gas from Ravva joint venture field in Krishna-Godavari basin to be be taken by GAIL and adjustment for the higher cost made as per the existing arrangement. 5. Gas Pool Account to be limited to Rs 1 billion per annum as per the actual requirement of compensation for concessional gas price in northeast region and other purposes. 6. Gas produced by ONGC and OIL from the new gas fields to be sold at a price determined in terms of NELP contracts. That will provide a level-playing field to these oil sector PSUs with other players. 7. At present, the consumer price for general consumers is 2,850 Rs/tcm whereas for northeastern consumers the corresponding price is 1,700 Rs/tcm which works out to be 60 per cent of the general consumer prices. It is proposed that the price of gas for northeastern region may be pegged at 60 per cent of the revised price for general consumers. The difference between the producer price and the consumer price in the northeastern region may be reimbursed to OIL from the Gas Pool Account as is being done under the existing arrangement. 8. The gas transportation charges along the HBJ pipeline system were fixed at 1,150 Rs/ tcm with effect from October 1, 1997 based on the recommendations of the Sankar Committee. GAIL also uses natural gas internally, as a fuel for operating the compressors required to ensure desired pressure of gas in the HBJ pipeline system. There are a total of six compressors stations along the HBJ system of which two compressors were commissioned after October 1, 1997. Further two compressor stations at Jhabua and Hazira were augmented after October 1, 1997. As a result, the total quantum of natural gas used internally as fuel by GAIL has increased.

Simultaneously, the gas price has also increased from the level considered during HBJ tariff fixation by Sankar Committee. Therefore, the cost of transportation be raised to 1160 Rs/tcm. In the meting of Committee of Secretaries (CoS) in May 2003, ministry of Petroleum and Natural Gas (MoP&NG) had suggested that the gas prices be increased from Rs 2850/tcm to Rs 3850/tcm whereas the Ministry of Power and Department of Fertilisers indicated Rs 3250/tcm as their acceptable price for gas. On July 23, 2003, Group of Minister (GoM), represented by producer and user ministries met and recommended an increase in natural gas prices of Rs 350/tcm. They have also suggested that the Gas Pool Account to be limited to Rs 1 billion per annum as per the actual requirement of compensation for concessional gas price in northeast region and other purposes. However, MoP&NG is yet to take a decision on these recommendations. Regulatory and Policy Initiatives The Indian gas market is presently in a transition from administered control to market driven system. Under new policy framework (NELP, CBM) the companies are free to market gas directly in the domestic market. The LNG and pipeline gas imports are under Open General Licence (OGL) and the domestic gas prices will ultimately move to market based pricing system. It is certain that gas market in India is under restructuring and in near future there would be multiple companies involved in gas marketing related activities. Over medium/long term period, cross country gas pipelines may also be required to meet growing gas demand in existing and new emerging markets in the country. In view of above changes taking place in the Indian gas sector, a proper regulatory mechanism would be needed to ensure a systematic development of the Indian gas market in cost effective and competitive manner. For any emerging gas market, the regulation has to be sensitive to the needs of the pipeline companies by creating a supportive environment to attract investments in developing capital intensive network of pipelines and to spread economic use of gas. The issues like unbundling of marketing and transmission activities and third party access to pipelines would have to take into account the present and historical background under which gas pipelines have been set up and also the fact that there are a large number of processing facilities along such pipeline systems, which may suffer adverse economic consequences by any third party access, if considered. The regulatory framework thus has to be compatible with the existing realities, needs of the domestic market, project developers and sectoral requirements over medium/long term. Government of India, Ministry of Petroleum and Natural Gas has been examining various models for hydrocarbon sector regulation in the country and it is expected that there would be two separate regulatory bodies i.e., one for the upstream sector, mainly focusing on exploration and production of oil and gas and another for the downstream sector with focus on refining and marketing of petroleum products as well as marketing of gas. It is also expected that the regulatory framework would be finalized soon and necessary approvals obtained for the introduction of the same. Regulatory framework for downstream sector has been finalized with the introduction of Petroleum Regulatory Bill, 2002 in Parliament. For the up-stream sector, the framework may be finalized based on initial experience of the downstream so that there are no missing links.

Role of government
The Government has introduced attractive fiscal terms and conditions in the oil and gas exploration policy. This has facilitated the major gas discovery by Reliance, However, apart from the discovery by Reliance, wells have been drilled by other players but without major success. Apart from the gas find by Reliance, the gas reserves being discovered are small in size and require advanced technologies and attractive fiscal terms & conditions to be commercially viable.

The legal framework for the exploration and production of oil and gas is provided mainly by the Oilfields Development and Regulation Act, 1948, and the Petroleum and Natural Gas Rules, 1959. The Act was amended in 1999 to provide for the NELP (New Exploration Licensing Policy). The downstream sector is regulated mainly by the Indian Petroleum Act and a number of orders passed by the government under the Essential Commodities Act.
The DGH (Directorate General of Hydrocarbons) was set up in 1993 under the administrative control of the MoPNG, with the objective of ensuring correct reservoir management practices,

reviewing and monitoring exploratory programmes, development plans for national oil companies and private companies, and monitoring production and optimum utilization of gas fields.

Attractive New Exploration and Licensing Policy (NELP): With the objective of enhancing exploratory activity, the government has come out with NELP with attractive terms. So far, the government has announced four rounds of NELP and awarded 70 blocks. The GoI has approved the award of contracts under NELP-1 in about four-and-a-half months since the bid closure date. The short time-span in granting approval for the award of contracts is a record of sorts. Similarly, in the NELP-II round, the government awarded the blocks within two months from the bid closing date and the contracts were signed one-and-a-half months thereafter. Similarly, in NELP III, the blocks were awarded within three months of the bid closing date. The NELP IV was announced in May 2003 and 24 blocks have been offered for bidding. NELP IV includes ultra deepwater blocks for the first time. The government has signed 50 production-sharing contracts (PSCs) since April 2000. Of these, 47 contracts have been under the new exploration licensing policy (NELP) alone. The number of PSCs thus signed in the past 15 months is more than twice those executed in the previous 10 years. Under NELP-II, the entire process of award, negotiations and approval of the contracts for 23 exploration blocks has been completed in a record time of about three months. Award of contracts under NELP I, II amd III in a short time span and announcement of NELP IV is probably a reflection of the seriousness with which the GoI is considering involving the private sector in oil & gas exploration activities in India.

Industry Structure
Integrated companies with international presence
The private fully integrated international companies (that is, having exploration and production, refining and distribution as well as petrochemical plants) often with oversized downstream activities (compared with their upstream) following the nationalisation of their concessions during the 1970s. The operations of these players are also geographically diversified. These players have the advantages of economies of scale and scope apart from the synergies of following an integrated operation. As a result, these companies are among the most profitable ones in the global oil & gas industry. Further, the profitability of these companies is driven by the upstream operations--the performance of which, in turn, is dictated by the trend in oil prices.

The national oil Companies
The national oil companies of the producing countries, which are focused mainly on exploration and production. However, there are some in this category that are trying to break into refining and distribution and petrochemicals, to achieve a better balance in their business. The national companies of the consumer countries who often are limited to refining, distribution and petrochemical activities and who, in size, are quite modest in comparison with the heavyweights like integrated companies with international presence and national oil companies of the producing region.

The niche players
These are the players, who have evolved due to non-traditional skills such as deal making, financing, trading, and commercial etc. Examples include players like the erstwhile Enron and Tosco. Historically, Enron's capability was limited to conventional pipeline aggregation skills and contract gas supply skills. By employing innovative financial, risk management and trading skills, it emerged as a leading energy player with business worth over $250 mn, before collapsing in 2001 due to certain financial irregularities. Similarly, Tosco's skills in acquiring refineries at cheap valuations and operating them efficiently resulted in the emergence of a profitable niche player in the refinery segment.

In India, Distribution and marketing of gas is done mainly by GAIL. The other players in the natural gas distribution industry are small and regional players, such as Gujarat Gas (with operations in Gujarat), Mahanagar Gas Ltd. (in Mumbai), Indraprastha Gas Ltd. (in Delhi), and the two State Government undertakings in the North-Eastern States (Assam Gas Company Ltd. and Tripura Natural Gas Company Ltd.). OIL also has a marginal share of the natural gas distribution business.

India - major players
The exploration and production of natural gas in the country is primarily undertaken by the ONGC (Oil and Natural Gas Corporation) Ltd and the OIL (Oil India Ltd). The ONGC has also set up a wholly owned subsidiary, ONGC Videsh Ltd, to look after the company’s overseas operations. Relience group is another important player, albeit in the private sector.
GAIL (Gas Authority of India Ltd) is responsible for transportation and marketing of natural gas. Set up in 1984, it now operates 4000 km of pipeline, including the 2702-km-long Hazira–Bijapur–Jagdishpur pipeline extending from the western coast to North India, and over 1300 km of pipeline in different states.

Gas is marketed by smaller regional companies in India—by the Mahanagar Gas Ltd, a joint venture between GAIL and British Gas in Mumbai, Maharashtra; by Gujarat Gas Company in the cities of Surat, Bharuch, and Ankleshwar in Gujarat; by the Baroda Municipal Corporation in the city of Baroda, Gujarat; and by Indraprastha Gas Ltd, a joint venture between GAIL, BPCL, and the Government of the National Capital Territory of Delhi.

Indian pricing policy
The current domestic gas price is fixed according to the Fuel Oil Import parity price (75 per cent parity), between a floor of RS.2150/MCM and a ceiling of Rs.2850/MCM. It is expected that the Government of India is likely to raise the ceiling price to India is likely to raise the ceiling price to Rs.3200/MCM. Progressive deregulation of prices is expected to take place over the next few years as the gas market evolves into a competitive market. [See also National Gas grid section earlier]

Factors influencing natural gas price in India
Power sector, major growth in demand for gas in India will continue to come from the power sector. The share of the power sector in the total gas consumption is expected to grow from the current level of 40 per cent to a level of 45 per cent by 2005-06.
The share of fertiliser sector in gas consumption is expected to go down to a level of 30 per cent by the year by 2005-06 but it will continue to be an important sector of consumption.
The sponge iron sector is really coming in a major way – it is estimated that by 2012 the sector will have a share of 54%, up from about 33% now. The transport sector is another important sector, as use of CNG is expected to grow many folds

The Road Ahead Circa 1974, with the huge oil & gas discovery in Bombay High field in 1974, followed by the giant South Bassein free gas find in 1978, the question then was “How to develop a market for this gas? The answer then was GAIL and the HBJ pipeline. Ten years later, the scenario turned 180 degrees, when the gas demand exceeded the supply and the question changed to “How to find more gas?” The answer then was NELP, CBM and OGL. Now in the year 2003, with huge indigenous gas finds and LNG cargos set to reach the Indian shores, along with the prospects of the growing power, industrial and nascent retail gas segments, Indian gas sector is moving from a supply constrained phase into an era of multi-source multi market entity. The power and fertilizer sectors would definitely influence the pace and growth of gas demand in the country. The power sector troubled over State Electricity Boards’ (SEBs) finances is gradually turning around with the help of Accelerated Power Development and Restructuring Program (APDRP) initiated by the Government. The progress in SEB restructuring, privatization of distribution and especially tariff rationalization will enable the power sector to afford more gas as a cleaner and efficient fuel for power generation. Also, the new Electricity Act, 2003 is expected to have a positive impact on gas demand in the power sector. In Fertilizer Sector, too, policy changes regarding the price rationalization and reduction in subsidies are likely to impact the use of gas as a feedstock against naphtha. The demand would also emanate both from existing users and from newer applications of natural gas. In the supply side, possible gas finds from NELP-I, NELP-II, NELP-III, NELP-IV initiatives are expected 15 to energise the growth of gas sector. Competitive pricing (vis-à-vis alternative fuels) and budgetary and fiscal concessions from the Government of India would be the key factors dictating the successful affordability of LNG in India. Energised by the supply side developments, the market would ask for more and the pipeline gas from Bangladesh, Myanmar and Iran may also fructify in phases. Unconventional sources like CBM, Natural Gas Hydrates, Underground Coal Gasification, etc. would also get tapped on experimental basis and economics permitting would get scaled up on commercial scale. The other factors that will influence the growth of gas markets are Technology and Environment Concerns. Increased monetisation of reserves is expected due to advances in deep drilling, which will be further coupled with enhanced viability to bring gas due to advances in logistics – LNG, deep sea pipelines, CNG by ship, VOTRANS CNG, Coselle, Gas-to-Liquid, etc. One can also expect increase in gas demand due to the technological developments in end user side like Distributed power, direct gas use in home appliances, air conditioning, etc. thus developing of new markets for gas usage. Share of gas is expected to grow in the industries, transport and homes due to sustained thrust from judiciary and policies on its environmental benefits. Emerging carbon trading may also provide additional incentive for increased gas use. In the infrastructure front, two decades after the HBJ in 1984, perhaps the answer this time around is an optimally planned “National Gas Grid” serving multiple (private and state) producers, shippers and customers of gas. Such a market development is expected to be accompanied by regulatory changes to support the new market rules and already, Petroleum Regulatory Bill has been tabled in the Indian Parliament. Setting up of Downstream Petroleum Regulatory Board along with introduction of open access principle and Cost of Services based framework of transportation tariff determination will fuel the growth of emerging natural gas scenario. Further unbundling of transportation and marketing would add fillip to healthy competition. Thus, in the coming years, key factors like Deregulation, Gas Pricing and Tariff, Technology, Globalization and Environmental Concerns would lead to a buoyant growth of gas market in India. The increasing size of the gas markets will continue to be the driving force for organizing more gas supplies and establishing integrated pipeline infrastructure in India. With the emergence of a gassy hydrocarbon province along with her favorable geographic disposition, natural gas is all set to propel India into an era of clean, efficient and internationally competitive industrialization and along with these developments, India is poised to emerge as the potential growth hub for natural gas in the Asian region.
Exchanges dealing in natural gas futures

New York mercantile Exchange

It launched the world’s first natural gas futures contract in April 1990 with Henry Hub as the reference point. Volumes and “open interest” (the number of futures or options natural gas contracts outstanding in the market) have grown rapidly, and the NYMEX gas contract is the fastest growing instrument in the exchange’s history. The estimated trading volume, around 725 Btu (20 bcm) of gas a day, is ten times the amount of gas delivered daily in the United States. In October 1992, NYMEX marked another milestone in the energy markets when it launched “options” on natural-gas futures, giving market participants still another instrument to manage their market risk. The exchange allows hedgers and investors to trade anonymously through futures brokers. NYMEX gas instruments have attracted private and institutional investors who seek to profit by assuming the risks that the industry seeks to avoid in exchange for the possibility of rewards. A wide cross-section of the gas industry is active on the futures market from producers to end-users: producers, processors, local distribution companies and marketers, industrial and commercial gas users. The marketers, predictably, are the largest participants accounting for 69% of the open interest in 2000. Gas suppliers use the NYMEX futures contracts to provide a variety of services to help customers manage their price risks. These include fixing gas costs or expenditures and offering ceiling prices. Marketers often manage the market risk for their customers. As a result, local distribution utilities themselves accounted for only 1.7% of the reportable open interest for 2000 – although a much larger share of transactions was performed on their behalf.

Natural Gas Exchange
In Canada, the NGX, located in Calgary, provides electronic trading and clearing services to natural-gas buyers and sellers in Canadian markets. The NGX started service in February 1994. Over the past eight years, NGX has grown to serve over 150 customers with trading activity averaging 200,000 TJ (5 bcm) per month. NGX is wholly owned by the OM Group, the world”s leading provider of transaction technology. In Canada, the regulation of commodity trading is under provincial jurisdiction. The Alberta Securities Commission is NGX’s lead regulator.

International Petroleum Exchange
In the United Kingdom, the IPE launched gas-futures contracts in 1997. They are based on deliveries of natural gas at the NBP. The IPE gas futures market is a transparent, screen-based system, which provides a mechanism for risk management, hedging and in some cases the physical delivery of gas. The IPE traded a daily average of 60 million therms of natural gas, or approximately 60% of the UK’s daily consumption.

Annexure
Production of Natural Gas
Unit: Million cubic meters, Figures for 2002-03 are for April-November
Source: Ministry of Petroleum & Natural Gas

*included in Assam. Figures for 2002-03 are for April-November
Demand for natural gas as per Hydrocarbon Vision 2025
Unit: mmscmd

Demand / Domestic Prodution of Natural Gas (MMSCMD)
As per Hydrocarbon Vision 2005, demand forecast is
Sector -wise breakup for Natural Gas consumption
As per Hydrocarbon Vision 2005,

Sector	2002	2007	2012
Power	43	39	29
Fertilizer	20	16	11
Sponge Iron	31	38	54
Others	6	7	6

Unit: MMSCMD
Off take (million cubic metres) of natural gas by industry:
995/96 to 2001/02
1

Industry	1995/96a	1996/97a	1997/98a	1998/99a	1999/00	2000/01	2001/02b
Energy purposes
Power generation	6,836	6,935	8,114	8,714	8,829	8,801	9,214
Industrial fuel	2,301	2,631	3,106	3,005	2,329	2,870	2,979
Tea plantation	111	130	117	147	140	151	147
Domestic fuel	178	184	206	193	250	335	485
Captive use/ LPG	589	618	569	911	4,840	5,004	5,339
Total	10,015	10,498	12,112	12,970	16,424	17,199	18,234

Non-energy purposes
Fertilizer industry	7,602	7,625	8,752	8,869	8,592	8,480	7,957
Petrochemicals	474	509	649	650	666	779	909
Others	_	_	_	_	1,203	1,402	937
Total	8,076	8,134	9,401	9,519	10,461	10,661	9,803
Grand total	18,091	18,632	21,513	22,489	26,885	27,860	28,037

^aexcludes some sales by the Oil and Natural Gas Corporation Limited
^bprovisional
Source
[TERI Energy Data Directory & Yearbook 2002/2003]