Document of F The World Bank FOR OFFICIAL USE ONLY Report No. 4097-INa STAFF APPRAISAL REPORT INDIA SOUTH BASSEIN OFFSHORE GAS DEVELOPMENT PROJECT January 26, 1983 Energy Department Petroleum Projects, Division I This document has a restricted distribution and may be used by recipients only in the performance of their official duties. Its contents may not otherwise be disclosed without World Bank authorization. CURRENCY EQUIVALENTS Currency Unit = Rupee (Rs) Rs 1 = Paise 100 US$ 1 = Rs 9.0 Rs 1 = US$ 0.11111 Rs 1 million = US$ 111,111 MEASURES AND EQUIVALENTS 1 Metric Ton (mt) = 1,000 Kilograms (kg) 1 Metric Ton (mt) = 2,204 Pounds (lb) 1 Meter = 3.28 Feet 1 Kilometer (km) = 0.62 Miles 1 Cubic Meter (CM) = 35.3 Cubic Feet (cft) 1 Barrel (Bbl) = 0.159 Cubic Meter 1 Metric Ton of Oil (39O API) = 7.60 Barrels 1 Normal Cubic Meter (Nm3) of Natural Gas = 37.32 Standard Cubic Feet (SCF) 1 Kilocalorie (kcal) = 3.97 British Thermal Units (Btu) MW = 1,000 kilowatts kWh = kilowatt-hour GWh = 1 Million kWh Bbl/d = Barrels per day MMCMD = Million Cubic Meters per Day TCE = Metric Ton of Coal Equivalent TCF = Trillion Cubic Feet toe = Ton of Oil Equivalent tpd = Ton per day tpy = Ton per year PRINCIPAL ABBREVIATIONS AND ACRONYMS USED BOP - Bombay Offshore Project CFP - Compagnie Francaise des Petroles DCF - Discounted Cashflow GOI - Government of India LPG - Liquefied Petroleum Gas LSHS - Low Sulfur Heavy Stock MSEB - Maharashtra State Electricity Board NGL - Natural Gas Liquids OIDB - Oil Industry Development Board OIL - Oil India Limited ONGC - Oil and Natural Gas Commission RCF - Rashtriya Chemicals and Fertilizers Ltd. TEC - Tata Electric Companies WGEP - Working Group on Energy Policy FISCAL YEAR April 1 - March 31 FOR OFFICIAL USE ONLY INDIA SOUTH BASSEIN OFFSHORE GAS DEVELOPMENT PROJECT STAFF APPRAISAL REPORT Table Of Contents Page No. I. THE ENERGY SECTOR .......................................... 1 Background ............................................ 1 Energy Supply and Consumption ......................... 2 Energy Resources ...................................... 5 Energy Prospects ...................................... 7 II. THE PETROLEUM SUBSECTOR .................................... 8 Introduction .......................................... 8 Petroleum Consumption, Production and Prices . . 8 a. Consumption and Production Trends .............. 8 b. Pricing Policies ............................... 10 Petroleum Resources, Past and Future Development ...... 11 a. Petroleum Resources ............................ 11 b. The Role of the Private and Public Sectors in the Development of India's Petroleum Potential ............... 12 c. Development Prospects and Investment Strategy.. 14 The Bank's Role and Lending Strategy in the Petroleum Subsector .. 15 III. THE PROJECT .............................................. 18 Objective ............................................. 18 Main Characteristics of the South Bassein Field ....... 18 Project Design and Optimization ....................... 19 The Project ........................................... 20 Engineering and Construction .......................... 22 Execution ............................................. 23 Implementation Schedule ........................ .. 23 Estimated Cost ........................................ 24 ONGC's Financing Plan ................................. 25 Project Financing Plan ................................ 26 Items Proposed for Bank Financing ..................... 27 Procurement and Disbursement .......................... 28 Ecology and Safety .............................. 28 This report is based on the findings of a mission that visited India in November 1981 and was prepared by Messrs. H. Schober, D. Carpio, G. Yuksel and Ms. S. Lazar of the Energy Department, N.C. Krishnamurthy of the Industrial Projects Department, and M. Heitner (Consultant). This document has a restrictqd distribution and may he used by recipients only in the performance of their official duties. Its contents may not otherwise be disclosed without World Bank authorization. - ii - Table of Contents (Cont.) Page No. IV. THE GAS MARKET AND TUSTIFICATION .......................... 29 Introduction .......................................... 29 Current Patterns of Gas Production/Utilization ........ 30 Current Policy for Gas Utilization .................... 32 The Market for South Bassein Gas ...................... 34 Economic Rate of Return ............................... 37 Project Risks ......................................... 39 V. THE OIL AND NATURAL GAS COMMISSION ......................... 40 General ..... . 40 Organization and Management ..................... .... 40 Staffing and Training ................................. 41 Management Information Systems ........................ 41 Accounts and Audit................................. 41 Insurance ............................................. 42 ONGC's Investment Program (1982/83 - 1987/88) ......... 42 VI. FINANCIAL ASPECTS ......................................... 44 Introduction ................................. 44 Past Performance ...................................... 44 Financial Analysis of the Project and the South Bassein Development Program .................. 46 Financial Prospects of ONGC ........................... 47 VII. AGREEMENTS TO BE REACHED AND RECOMMENDATION .............. 49 ANNEXES 1.1 Production, Trade and Consumption of Primary Energy 1.2 Sectoral Distribution of Energy Consumption 2.1 Crude Oil Supply 2.2 Production and Consumption of Oil Products 3.1 Reserve Estimates and Production Projections 3.2 Detailed Project Description 3.3 Implementation Schedule 3.4 Project Cost Estimate 3.5 Phasing of Expenditures 3.6 Disbursement Schedule 4.1 Forecast of Demand for Lean Gas (Western Region) 4.2 Forecast of Offshore Gas Production 4.3 Assumptions for Economic Rate of Return 4.4 Fertilizer Feedstock Netback Value Calculation 4.5 Economic Rate of Return - The Project 4.6 Economic Rate of Return - the Full Development Program 4.7 Sensitivity Analyses - Economic Rate of Return 5.1 Organization Chart - ONGC 5.2 Organization Chart - Bombay Offshore Project 5.3 ONGC's Investment Program - ±iii Table of Contents (Contd.) ANNEXES 6.1 Historical and Projected Financial Statements 6.2 Assumptions Underlying Financial Statements 6.3 Financial Rate of Return - The Project 6.4 Financial Rate of Return - The Full Development Program 6.5 Sensitivity Analyses - Financial Rate of Return 7.1 Documents Available in Project File MAPS IBRD 16183 and 16184 I I. THE ENERGY SECTOR Background 1.01 Commercial primary energy (coal, oil, gas, hydro and nuclear power) accounts for about 46% of total primary energy supplyl/ in India, with 1'e balance (54%) coming from noncommercial energy (mainly firewood, agricultural and animal wastes). Coal, hydro and nuclear power have important roles in meeting commercial primary energy requirements and in 1981/82 accounted for approximately 67% of total supply; the share of petroleum is relativel'y moderate in comparison with other developing countries and accounts for about 33% of total commercial primary energy supply. The supply of commercial energy has been growing faster (about 5.3% per year), than that of noncommercial energy (between 1.7% and 2.5% per year), thus resulting in a steady decline in the share of noncommercial energy in total energy supply. 1.02 India has consistently followed energy policies that limit the use of petroleum to sectors where economic substitution by other energy resources, particularly coal, is not possible. Despite the recent development of offshore petroleum resources, the country remains dependent on imported oil to meet a significant part of its primary energy requirements, particularly the growing demand in transport, fertilizers and petrochemicals, as well as in the modern agriculture sector where substitution by electricity continues to be limited by insufficient power generation and distribution. The impact of the increase in world oil prices after 1973 on India's balance of payments is evident from the following: while the volume of petroleum imports grew by 30%, from 16 to 21 million tons of oil equivalent (toe) between 1972/73 and 1981/82, the cost of imports over the same period grew about 23 times from $269 million to US$6 billion, equivalent to about 70% of India's estimated merchandise export earnings. Well identified domestic energy resources such as coal and hydroelectricity are large enough to supply most of India's future commercial energy requirements for industry and power generation. However, proven oil and gas reserves are not sufficient to meet the demand for oil in sectors where further substitution by other fuels is limited. 1.03 In 1981/82, out of a total oil supply of 36.8 million toe, 16.2 million (or 44%) came from local production while the remainder (20.6 million toe) had to be imported. Current projections based on production from known petroleum reservoirs indicate a potential petroleum deficit of up to 34 million toe by the end of the 1980s. The high cost of petroleum imports will remain a serious constraint to economic development unless new reserves are discovered in the near future to compensate for the depletion of existing reserves as well as to meet anticipated growth in demand. India's potential oil and gas resources are significant, but many of the prospective areas are largely unexplored. Therefore, the exploration for new and the development of existing petroleum reserves are among India's most pressing priorities. 1/ Supply is defined as production plus imports less exports. When changes in stock levels are not taken into account, then supply equals apparent consumption. -2- 1.04 It is against this background that India is making a concerted effort to accelerate hydrocarbon exploration and development by the national oil companies (i.e. ONGC and OIL) and also by foreign oil companies which were invited in late 1980 and again in August 1982 to submit bids for exploration and production sharing on many blocks offshore and onshore. The success of these efforts, together with an active public sector program in developing natural gas resources, currently untapped, over the next three to four years, will be a key factor in determining whether indigenous hydrocarbon supplies can be 'ncreased sufficiently above current forecasts to meet a major portion of the anticipated growth in demand during the present decade. Energy Supply and Consumption 1.05 In 1975/76 (the last year for which overall figures are available), primary energy supply in India was 182 million tons of oil equivalent. The breakdown by primary energy source is shown in Annex 1.1 and is summarized as follows: Primary Energy Supply in India (million tons of oil equivalent)±/ Average Annual Growth Rate (%) Actual Estimate 1960/61- 1970/71- Fiscal Year 1960/61 1970/71 1975/76 1980/81 1981/82 1970/71 1980/81 Commercial Primary Energy Coal & lignite b/ 27.8 37.1 50.6 58.2 63.7 2.9 4.7 Petroleum c/ 7.9 19.0 24.1 34.7 38.4 9.2 6.2 Hydro & Nuclear Power d/ 1.9 6.6 8.6 11.9 13.7 1.30 7.2 Subtotal 37.6 62.7 83.3 104.8 115.8 5.2 5.3 Noncommercial Primary Energy f/ Firewood 48.8 57.8 65.2 N.A. N.A. 1.7 2.5 e/ Agricultural waste 13.2 15.6 17.6 N.A N.A. 1.7 2.5 e/ Animal dung 12.0 14.2 16.1 N.A. N.A. 1.7 2.5 e Subtotal 87.6 N.A. N.A. 1.7 2.5 e/ Total 111.6 150.3 1=2T N.A. N.A. 3.0 3.9 e/ -a/ Based on the following conversion factors: one ton of oil equivalent (toe) Is equal to 2 tons of domestic coal; 5.88 tons of lignite; 0.94 tons of refined petroleum products; 1,235 cubic meters of natural gas; 4,166 kWh of hydro and nuclear power; 2.04 tons of firewood; 2.33 tons of agricultural waste; and 4.54 tons of animal dung. b/ 98.5% coal and 1.5% lignite In terms of toe In 1980/81. x-I Natural gas excludes quantities flared and used In field operations. Petroleum supply Includes those for fuel as well as for petrochemical feedstocks. g/ About 94% hydro power and 6% nuclear power in 1980/81. The figures are gross power generation. a/ Growth rate from 1970/71 to 1975/76 only. The same rate assumed for the 10-year period (1970/71-1980/81). A/ Non-commercial energy figures are for consumption which are taken as equal to supply. -3- 1.06 Trends in commercial energy consumption by various economic sectors during the period 1960/61-1980/81 are shown in Annex 1.2 and summarized as follows: Sectoral Breakdown and Growth of Commercial Energy Consumption a/ (Percent) Average Annual Growth Rate (%) 1960/61- 1970/71- 1960/61 1970/71 1980/81 b/ 1970/71 1980/81 Households 14.9 13.7 11.2 4.6 4.8 Agriculture 1.9 3.4 6.3 11.8 11.2 Industry 43.4 48.9 55.5 6.7 5.8 Transportation 36.9 29.8 23.4 3.2 2.0 Other 2.9 4.2 3.6 9.3 2.8 Total % 100.0 100.0 100.0 5.4 4.5 Total (In million toe) 30.9 52.4 81.6 a/ Coal, lignite and oil used for power generation are excluded from these consumption trends; however, all electricity (i.e. primary and conventional thermal) consumption is included but on a delivered basis to consumers (i.e. gross generation less internal power plant uses, as well as transmission and distribution losses). Furthermore, oil consumption excludes non-fuel uses (i.e. petrochemical feedstocks). b/ Provisional. Source: Working Group on Energy Policy (see para. 1.16); Ministry of Petroleum; and Department of Coal. The household sector accounts for a relatively small share of commercial energy consumption (7% of coal, 19% of petroleum and 10% of electricity). However, consumption of noncommercial energy in this sector is high, particularly in the rural areas where electricity and kerosene are mostly used for lighting. Although the substitution of commercial energy for non- commercial energy will continue, noncommercial energy will remain a significant source of supply for rural households. Measures are however needed to maintain and even increase production from noncommercial sources (particularly firewood) as well as improve the efficiency of cooking stoves in order to conserve commercial energy for applications where non-commercial energy is not possible or practicable. 1.07 Energy needs in agriculture are mainly for land preparation, water lifting, threshing and transportation. They are met mostly by animal power or by the use of liquid fuels (mainly diesel oil) and electricity. Commercial -4- energy consumption in agriculture accounts for only about 6.3% of commercial energy use but has been growing rapidly between 1960/61 and 1980/81 (about 7.8% p.a. for oil products and 16.2% p.a. for electricity), reflecting the efforts made to modernize the sector. This trend towards increased use of commercial energy in agriculture will continue with the efforts to further modernize the sector and increase the standard of living of the rural population. 1.08 The industrial sector is by far the largest user of coal and electricity. In 1980/81, it accounted for 75% of coal consumption (excluding power generation), about 63% of electricity consumption and 19% of oil consumption. In contrast to other developing countries the share of industry in total oil consumption is still relatively modest but has gradually increased (it was only 11% in 1970/71). Over the past twenty years the energy intensity of the industrial sector has increased from 0.12 to 0.17 tons of oil equivalent per thousand rupees of gross domestic product originating from industry (at factor costs in 1980/81 rupees) due primarily to the increased use of electricity. In the future, the growth in the energy intensity of industry is expected to slow down as a result of better capacity utilization and use of appropriate technologies. The future industrial demand for energy is difficult to predict since the sector has been affected by recurrent shortages of power and raw materials as well as transport bottlenecks, so that recent trends may not be representative. In addition, part of the industrial capacity was built when energy was relatively cheap, and less attention was paid to energy efficiency. It is believed that there is considerable potential for energy savings in the industrial sector by improving the efficiency of existing plant and equipment, improving the design of future plants, and introducing energy efficiency standards, but this will require a large investment effort. 1.09 The transport sector 1/ is the largest user of petroleum products and the second largest user of coal. Over the past twenty years the structure of demand has changed considerably as a result of the rapid growth of road transport and the substitution of diesel-electric for steam locomotives. In 1980/81 oil products accounted for 66% of the commercial energy consumed in the sector compared to 47% in 1970/71 while the share of electricity remained small at about 3% in 1980/81. Current projections in the transport sector indicate continuing decline in coal consumption as road transport increases in importance and as railways continue to shift to more efficent diesel electric locomotives, thereby contributing to a growing demand for petroleum products. The transport sector is an area where significant energy savings, especially in petroleum products, could be achieved over time if measures were taken to increase the capacity of the railways and to electrify main lines, improve their operating efficiency, encourage the use of railways for long- distance freight and passenger hauls, improve the efficiency of road vehicles (mainly trucks), and optimize the location of industrial plants. The performance of the railways improved substantially during 1981/82 as a result of several innovations introduced in 1980/81. The Sixth Plan provides for many investments for the railways that are expected to ease some of the 1/ The railways, power and coal subsectors are the critical infrastructure bottlenecks in India and are reviewed in Economic Situation and Prospects in India, April 1982 (Report No. 3872-IN). equipment problems in the medium term although the Plan allocation for this sector appears to be inadequate to make up for the under-investment during the two previous plan periods. 1.10 In 1980/81 the power sector used about 38 million tons of coal (about 33% of coal production). Of the power generated (including self-generation b,v industry), about 42% came from hydroelectric and nuclear plants, 46% from coal and 12% from oil. Over the past ten years the share of coal in conventional thermal generation by utilities has fluctuated between 85% and 90% and this is expected to continue in the future. The share of hydro and nuclear energy has varied between 40% and 50% of total power generation. It is expected that by 1987/88 the consumption of oil in the power utilities will be limited to what is required to ensure the efficient operation of coal-fired plants. Total electricity consumption has been growing at an average of 6.5% p.a. between 1970/71 and 1980/81, a rate significantly lower than previously. However, as the power shortages which developed during the 1970s demonstrated, the growth of demand for electricity has been and will continue to be supply-constrained. Energy Resources 1.11 Coal 1/ is the main domestic source of commercial primary energy in India with reserves (in seams greater than 1.2 meters thick and at depths less than 600 meters) estimated at about 85 billion tons, of which about 25 billion tons are proven reserves. Most of the coal is of low to medium quality (3,500 to 5,500 kcal/kg). The 1981/82 coal production is estimated at 124.7 million tons, making India the sixth largest coal producer in the world. Between 1975/76 and 1979/80, coal production stagnated at about 100 million tons per year because of extensive flooding in 1978, serious power shortages, delays in commissioning new mines, lack of explosives, labor unrest, and transportation bottlenecks. During both 1980/81 and 1981/82, coal production increased by 10 million tons per year, a remarkable achievement, although, at present, coal production is still about 10 million tons per year less than demand. Most of the production and transport problems are being addressed. For example, the Sixth Plan embodies further measures to overcome the infrastructure-related constraints, and labor relations have improved in the past year. The Plan also includes significant investments to bring new mines into operation. In order to increase productivity, a high proportion of these new investments will be in open-pit mining. Since in the past most of the delays in bringing new mines into operation were experienced in underground projects, the shift to open-pit mining is expected to help in reducing delays in project execution and commissioning. About two-thirds of the planned increase in production (40 to 45 million tpy) between 1980/81 and 1984/85 is to come from open pit mines. However, about 47% of this increase is to come from projects still to be approved. Various demand projections for coal by 1984/85 range between 165 to 185 million tons while production is expected to range between 155 and 165 million tons. Of the expected 1984/85 coal demand, power generation would account for about 42%, steel would utilize about 23%, the railways 6% and cement about 4% of the total. In order to achieve the production targets, the coal industry has to overcome the problems referred to above, and will need to 1/ A detailed review of the coal sector is contained in the Bank report India Coal Sector Report, September 14, 1982 (Report No. 3601-IN). -6- avoid delays in project preparation and implementation. Improvements in the ability of local equipment manufacturers to provide new equipment and spare parts in a timely manner will also be needed. 1.12 India's hydroelectric potential is estimated at about 400,000 GWh of annual energy generation which might sustain an installed hydro power capacity of 100,000 MW at a 45% load factor. But almost 70% of this potential is in remote areas in the north and northeast and difficult to access. About 12,600 MW (13% of potential) is already developed and represents 36% of the total installed generating capacity of approximately 35,000 MW (including 2,736 MW of non-utility capacity). An additional 4,700 MW of hydro power capacity is scheduled for commissioning by 1984/85, and a further 23,000 MW is under study for development. India also has sufficient reserves of uranium (34,000 tons equivalent of U308, of which 15,000 tons is considered economically exploitable at current international prices) and thorium to meet the foreseeable requirements of its nuclear power program. The existing nuclear power plants have a capacity of 860 MW. In addition, four units with a combined capacity of 940 MW are under construction. 1.13 Demand for power has consistently exceeded supply in the last decade. The gap has widened in recent years and the shortage in 1980/81 is estimated to have reached about 13%. The reasons for the gap between demand and supply are the strong growth in demand, delays in completing planned thermal generation capacity and low capacity utilization. Capacity utilization of thermal power plants declined from about 55% in 1976/77 to 45% in 1980/81 but increased to 47% in 1981/82. The low capacity utilization is partly due to difficulties in plant commissioning, delayed maintenance of boilers and turbogenerators, lack of spare parts, shortages of appropriately trained manpower, problems related to design and fabrication of domestically produced equipment and continuing difficulties in the supply and quality of coal. A high-level commission has recently carried out a comprehensive analysis of the situation and has submitted its findings to the Government. Several measures are being introduced to improve the efficiency of thermal plants, including: (a) improved preventive and planned maintenance; (b) better availability of spare parts; (c) improved training; (d) adequate coal supplies of acceptable quality; and (e) more effective management. The results of these measures are already having an impact in the sector. In 1980/81 and 1981/82, power generation increased by 9% and 10% respectively. With the implementation of the above measures more progress is projected for the medium term. Power generation capacity is planned to reach 50,900 MW by 1984/85, (including about 2,750 MW of non-utility capacity). The increase will come from thermal power plants (70%), hydroelectric units (25%) and nuclear plants (5%). The country's overall average electrical energy requirements are expected to be met by 1988/89 onwards, although a peak capacity deficit would most likely continue until the mid-1990s and regional capacity differences will continue to impose shortages in some areas. 1.14 India's remaining proven and probable recoverable reserves of petroleum are currently estimated at 800 million tons of oil equivalent, of which 470 million tons is oil and the remainder natural gas. Domestic oil production has increased from 0.5 million tons in 1961 to 16.2 million tons in 1981/82 and currently meets about 44% of India's domestic oil requirements. Gas production is currently estimated at about 3.1 million tons of oil equivalent, of which about 60% is used as fuel or feedstock, and the balance is flared (mostly in Assam), mainly because there is no market within - 7 - reasonable distance. The petroleum sub-sector is discussed in more detail in Chapter II. 1.15 Renewable energy represented 59% of total primary energy supply in 1975/76 but its share has been declining. Wood, charcoal, dung and vegetable wastes made up an estimated 92% of the total with the remainder provided by hydroelectric power. Renewable energy (especially traditional fuels) will continue to play an important though decreasing role in rural energy supplies as the agriculture sector is further modernized and the living standards of the rural population improve with a corresponding increase in the use of commercial energy. Energy Prospects 1.16 Several studies of India's future energy demand and supply alternatives have been carried out. The most comprehensive is the Report of the Working Group on Energy Policy (WGEP), published in 1979, which assesses: (i) whether the availability of energy may become a serious constraint to India's economic development; and (ii) what would be the likely impact of an active energy conservation program on India's future energy balances. Although WGEP recognizes the limitations of such an exercise, given that historical data may not be indicative of future developments, it concludes that: (i) commercial energy availability may become a serious constraint to economic development, either because domestic resources would be insufficient to meet the anticipated demand or because the effort required to develop domestic resources would imply human and financial inputs which are not likely to be available; (ii) a coordinated and all-encompassing energy conservation/demand management program would have a significant impact beyond the late 1980s and could possibly reduce commercial energy demand by as much as 20% (the main reduction being in the demand for power and in the demand for petroleum and petroleum products across the entire economy, but especially in the transport sector); and (iii) the most critical aspect of India's future energy policy will be to contain (within economic limits) the demand for oil at as low a level as possible. 1.17 The policy measures it recommends are: (i) improvement in the efficiency of energy utilization; (ii) introduction of fuel-efficient technologies; (iii) reduction of transportation demand through improved planning of production and consumption locations; (iv) reduction of the energy intensity of industries; and (v) inter-fuel substitution from commercial energy to noncommercial and renewable energy. The Working Group considers that such measures, supplemented by appropriate pricing policies, would permit India to reduce commercial energy consumption without affecting economic growth. It is hoped that the ratio of energy use to GDP would decline by 50% between the late 1970s and the early 1990s. The energy saving measures outlined above supported by detailed implementation plans and an appropriate pricing policy, could substantially reduce waste and improve energy availability in the future. -8- II. THE PETROLEUM SUBSECTOR Introduction 2.01 Despite rapid development of its largest oil field (Bombay High), India currently imports about 56% of its petroleum requirements. By 1984/85, the year of expected peak production from Bombay High, imports will still account for about 33% of domestic supply as production reaches 30 million tons compared with anticipated consumption of 45 million tons. 2.02 India's gas resources are currently underutilized, particularly offshore. With a rapidly increasing production of associated gas in the Bombay High field, and the discoveries of large free gas reserves offshore, gas could become an important source of energy as it can replace oil products advantageously, and be used as a fertilizer and petrochemical feedstock; however a necessary prerequisite is the conversion of existing industries from fuel oil to natural gas and the establishment of new gas-based industries to take advantage of this resource, necessarily a long process because of the large investments tl'at have to be mobilized, and the time required to convert and construct such plaits. The Government recognizes the potential of gas to the economy, and has embarked on a large-scale program to foster the utilization of offshore gas on a sound economic basis. Petroleum Consumption, Production and Prices a. Consumption and Production Trends 2.03 Crude oil consumption grew steadily from about 8.0 million tons in 1960/61, to 22.4 million tons in 1972/73. Following the first oil crisis in 1973, oil consumption was held between 23 and 24 million tons per year from 1973/74 through 1975/76. Consumption again started to gradually increase in 1976/77 reaching an estimated 32.3 million tons by 1981/82. While domestic production accounted for only 6% of consumption in 1960/61, this proportion had reached 36% in 1970/71 before falling to between 30% to 33% through 1974/75. As production from Bombay High started in 1976/77 and continued to increase, domestic crude oil accounted for 36% to 41% of consumption during 1977/78 through 1979/80 and 44% in 1981/82. 2.04 The accelerated development (para 2.19) of the presently known petroleum reservoirs is expected to increase domestic crude oil production substantially, from about 16.2 million tons in 1981/82 to a projected 30 million tons in 1984/85. Thus, domestic oil can be expected to provide at least 60% of total oil consumption by the mid-1980s (Annex 2.1) but less than 50% by the end of the decade. In addition, the development of the offshore South Bassein gas field will provide the equivalent of about 1.8 million toe of gas by 1985/86, rising to 5.1 million toe by 1989/90, making gas a significant energy resource in the late 1980s. This is summarized below: Petroleum Production and Consumption Trends Actual Est. Forecast/a Crude Oil (million tons) 1960/61 1970/71 1979/80 1980/81 b/ T981/82 1984/85 1989/90 Domestic Production 0.45 6.82 11.77 10.51 16.19 30.20 30.00 Net Crude Oil Imports 5.71 11.68 16.12 16.25 15.36 11.69 23.70 Net Product Imports c/ 1.80 0.40 3.90 6.90 5.23 4.05 10.00 Supply 7.96 18.90 31.79 33.66 36.78 45.94 63.70 % Self-Sufficiency 6 36 37 31 44 66 47 Natural Gas (million toe) Field Production N.A. 1.17 2.24 1.92 3.11 4.67 7.82 Less: Field Uses N.A. 0.16 0.26 0.21 0.29 0.46 0.71 Flared Gas N.A. 0.60 0.76 0.63 1.23 0.61. 0.85 Consumption N.A. 0.41 1.22 1.08 1.59 3.60 6.26 Total Petroleum Consumption (million toe) N.A. 19.31 33.01 34.74 38.37 49.54 69.96 a/ Production forecasts are based on development of presently known petroleum reservoirs and do not assume new discoveries from the accelerated exploration program. b/ Domestic crude oil production in 1980/81 was adversely affected by political unrest in Assam. c/ Crude oil equivalent of petroleum products converted at 1.0638 tons of crude per ton of products (Annex 2.2). 2.05 These forecasts are realistic provided the accelerated development program of ONGC and OIL, as well as the transport and downstream facilities for the use of the projected gas production, are implemented in a timely manner. However, it is also clear that a substantial exploration program should be maintained if domestic oil production in the late 1980s is to be maintained or increased. Petroleum imports could reach about 33.7 million tons in 1989/90, compared to 20.6 million tons actually imported (net) in 1981/82, unless additional petroleum discoveries are made. 2.06 Almost all natural gas produced in India at present is associated gas. The quantities produced are relatively small, however, and about 40% is flared, particularly in Assam where the fields are small and dispersed, and potential consumers are far away, making it uneconomic to utilize the small quantities produced. The role of gas as an energy resource is therefore minor so far, with consumption in 1981/82 at only about 2 billion Nm3 (1.6 million toe), equivalent to 1% of commercial primary energy consumption and 4% of crude oil consumption. With the development of the South Bassein gas field just about to begin (1983/84-1985/86), and prospects for commercial quantities of either free or associated gas from the Krishna-Godavari basin, the role of gas in the commercial energy sector is expected to increase rapidly and become significant in the late 1980s. - 10 - b. Pricing Policies 2.07 India, in recent years, has consistently followed a policy of maintaining composite retail prices of oil products at international levels, with a cross-subsidy from gasoline towards kerosene (on social and environmental grounds) and naphtha (for fertilizers). The price of a reconstituted barrel of petroleum products is $46.721/ at the retail level based on prices in effect since July 11, 1981. In spite of the cross-subsidy from gasoline to kerosene, the latter's consumption growth has been relatively slow at 2.5% per year during 1970/71-1980/81 compared to 5% per year for all light distillates and 6.5% per year for all middle distillates. Most of the growth in consumption has been for naphtha, diesel oil, LPG and fuel oil. Prices are as follows for the main products: Prices as of July 1981 Rs per Liter US$ per US Gallon Retail a/ India Turkey France cif imports Retail a! Retail Retail Gasoline 6.07 1.07 2.55 2.072 .83 Kerosene 1.81 1.14 0.76 1.39 - Diesel Oil 3.02 1.10 1.27 1.40 2.10 Fuel Oil 2.79 0.75 1.20 0.88 1.50 a! Prices in New Delhi, about average for India. Natural gas, unlike crude oil, is sold directly by the producers (OIL and ONGC) to the consumer, on the basis of long-term contracts (which require government approval). Offshore gas is priced on the basis of the end-use; onshore gas prices can vary considerably from one customer to the next as they are affected, for instance, by the year in which the contract was entered into, local surpluses of gas being flared, etc. ONGC's gas prices are discussed further in paras. 6.06 and 6.07. 2.08 Domestic crude oil is sold to the refineries at Government-regulated prices which were raised substantially in July 1981. Although below international levels, the current domestic crude oil prices (para 6.05) ensure satisfactory profits and financial performance for the producers as well as allow them to finance from internally generated funds a major portion of their investment programs. Finally, exploration and development decisions are based on international oil prices, rather than the relatively lower domestic price, and the latter price does not act as a disincentive to invest in oil exploration or development. The average level and structure of petroleum prices in India are considered satisfactory at present. 1/ The cost of a reconstituted barrel was calculated by weighting the price per barrel of each product by its proportion in consumption, using 1980/81 weights. - 11 - Petroleum Resources, Past and Future Development a. Petroleum Resources 2.09 Petroleum reservoirs are found in sedimentary basins. In India, there are 27 sedimentary basins with a total area of approximately 1.7 million km2 of which about 1.4 million km2 (82%) is onshore with the remainder, offshore (to a water depth of 200 meters). Commercial petroleum production has been established in only three sedimentary basins. The first is the Upper Assam Shelf in parts of Assam in the eastern part of the country. The second is the Cambay basin comprising an area in Gujarat. The third is the Bombay offshore basin which includes the giant Bombay High field and several other smaller fields (North Bassein, South Bassein, Heera and Ratnagiri). However, petroleum has been found in seven other basins: Krishna-Godavari, Cauvery, Rajasthan, Bengal, Himalayan Foothills-Ganga Valley, Andaman Islands and the Assam-Arakan Fold Belt. In addition, four other basins, Saurasthra, Kutch, Konkan-Kerala and Mahanadi are considered prospective on general geological grounds. The Krishna-Godavari and Cauvery basins are the most promising new areas today with the Krishna-Godavari particularly standing out as the next likely major commercial discovery after Bombay High. Magnetic and gravimetric surveys have been undertaken for most of the potential petroleum bearing areas. However, modern geophysical surveys have covered less than 50% of the prospective areas; and no exploratory drilling has been carried out in more than 65% of the areas. 2.10 As of March 1981 cumulative oil production in India totalled 141.8 million tons of oil; and from 1970/71 to 1980/81 some 19.3 million toe of gas were produced. The Government's estimate of remaining recoverable proven and probable reservesl/ from existing fields is as follows: Estimate of Remaining Recoverable Proven and Probable Reserves as of January, 1981 Onshore Offshore Total Oil (million tons) 140 330 470 Natural Gas (billion m3) 80 330 410 (in million toe a/) 65 265 330 Total Petroleum (million toe) 205 595 800 a/ 0.81 toe per 1,000 cubic meters of gas. Source: Ministry of Petroleum. 1/ The estimates of recoverable petroleum reserves from fields already producing or just recently discovered are generally classified into proven reserves, probable reserves and possible reserves. Proven reserves have the highest degree of certainty and are based only on areas delineated by actual drilling and successful testing. Probable reserves are those inferred from the full lateral extent of the reservoir structure, that is, beyond the limits defined by existing wells. Possible reserves include the additional recovery that could reasonably be expected from the known reservoirs if enhanced oil recovery schemes are implemented. - 12 - 2.11 The long-term estimates of the total geological petroleum resources (i.e. initial oil or gas in-place) and the recoverable resources of a country are based on prognostic studies, using geological extrapolations and interpolations, as well as technical and economic assumptions. The results of such studies are highly speculative and subject to wide divergence of opinion. Nonetheless, they provide a broad indication of potential petroleum resources and a framework for developing long-term energy sector policies and petroleum subsector exploration and development strategies. A recent study has estimated the total potential Indian geological resources of petroleum at about 15 billion tons of oil equivalent, of which about 30% is considered recoverable. About two-thirds of the potential recoverable petroleum resources are estimated to be located offshore, and about three-quarters of the potential reserves are gas. While these estimates may be considered as optimistic, they are indicative of the substantial undiscovered potential. b. The Role of the Private and Public Sectors in the Development of India's Petroleum Potential 2.12 Commercial quantities of petroleum were first discovered in India in 1889 at Digboi, Assam, by the Assam Oil Company, a private firm. In 1915 the Burmah Oil Company (UK) also began exploration in Assam and in 1921 acquired full control of the Assam Oil Company. Until the 1950s, petroleum exploration was concentrated in the northeastern part of the country, namely in Assam, Tripura and Nagaland. In 1954, ONGCl/ began as a department of the Geological Survey of India, and it was established in its present form by an Act of Parliament in 1959. Oil India Limited (OIL) was established in 1959 following an oil discovery in Assam by Burmah Oil Company (UK). The Government of India initially took a one-third equity interest in OIL, then increased its equity interest to 50% in 1961, and in October 1981, purchased the entire Indian assets of the Burmah Oil Company, covering its interest in OIL and in the Assam Oil Company. Starting in 1959, ONGC discovered petroleum reserves in Cambay (1959), Ankleshwar (1960), Kalol (1961), and Sanand (1962), all in Gujarat. Later, ONGC discovered oil in Lakwa (1964) and Geleki (1968) in Assam. 2.13 Following the oil crisis of 1973, exploration activities accelerated particularly offshore, resulting in the discovery by ONGC in 1974 of the giant offshore field of Bombay High and a number of significant but smaller fields in its vicinity. Assam was the major petroleum producing area (4.2 million tpy) in the country until the early 1970s when production from Gujarat also reached just over 4 million tpy. By 1979/80, production from Bombay High had also exceeded 4 million tpy and by 1981/82 reached 8 million tpy. 2.14 International oil companies have been involved in petroleum exploration in India intermittently. Prior to 1950, the Assam Oil Company and the Burmah Oil Company were the only firms active in petroleum exploration. In 1954, the Indo-Stanvac (Standard Oil and Socony Vacuum, now Exxon and Mobil, U.S.A.) agreement with a 25% GOI interest was signed, providing for an 1/ ONGC's organization is reviewed in Chapter V. - 13 - exploration area of 10,000 km2 in West Bengal. The venture was abandoned in 1959, after drilling 10 (dry) wells. From 1974 to 1977, three joint-venture agreements each covering 25,000 km2 of offshore area, were also concluded with Asamera (Canada), Natomas (USA), and Reading and Bates (USA) but the companies withdrew following completion of the minimum work requirements due to the discouraging results. In the following years, the Government did not encourage participation of foreign oil companies in petroleum exploration. 2.15 In late 1980, recognizing the urgent need to accelerate the pace of exploration but aware of the technical and financial constraints on ONGC's own exploration efforts, the Government decided to actively promote open arees for exploration by foreign firms. Thirty-two blocks, each ranging in size from 10,000 to 30,000 km2 offshore and onshore, were offered to international bidders. The total area offered, almost 0.9 million km2, represented about 50% of the country's sedimentary basin area. Although 34 foreign oil companies were invited, only seven submitted bids and offers were concentrated on just two offshore blocks in the vicinity of oil producing areas. This response was somewhat disappointing but can be partly explained by the probable concern of some companies that India would likely exercise its option to buy back their oil share. Undoubtedly, the companies have so far adopted a .."wait and see" attitude and still view India's new exploration strategy with caution after a substantial period in which private industry involvement has been minimal. Thus, it is not surprising that the initial round of bidding involving relatively unknown areas with what can be regarded as modest geological potential, as well as untested government policies, attracted only a few bids which concentrated on the most promising blocks offered (i.e. near producing areas). One production-sharing agreement has so far been signed with a consortium led by Chevron (USA) for an 18,500 km2 block in the Saurasthra basin offshore Gujarat, north of the Bombay High field. The terms of the production sharing agreement provide for Chevron to drill at least three wells, spending a minimum of US$29 million over a three-year period, at its own risk. Upon commercial discovery, ONGC may assume up to 50% joint venture in future development (without payment of exploration costs), and production will be split according to a scale which escalates with field profitability. Until India achieves self-sufficiency in oil, GOI has the option to purchase Chevron's share of the oil produced at international prices. Chevron started its seismic survey after contract signing and it was completed in July 1982; drilling started in late 1982 after the monsoon season. Meanwhile, invitations to bid on a second round of offerings were issued end-August 1982 to 37 foreign oil companies and bids are expected to be received in February 1983. The second offering includes about 50 blocks both onshore and offshore, including new areas such as west of the Bombay High field (in 200 m of water), and the outer-shelves of the Krishna-Godavari and Mahanadi deltas. In view of the fact that (i) ONGC has recently made a discovery in one of the blocks previously offered (Palk straits) but not bid upon by companies; and (ii) the contractual framework has enabled one major oil company to enter into an exploration contract, the response to the offering in this second round is expected to be much better. Therefore, one may conclude that a process has been initiated which, if supported by further discoveries, will, over time, lead to a substantial increase in private sector activities and an acceleration of exploration work to levels commensurate with India's prospective acreage. 2.16 In the public sector two companies, ONGC and OIL, have traditionally undertaken exploration activities. ONGC has had, and will continue to have, - 14 - by far the largest involvement in the petroleum sector as the principal entity in charge of petroleum exploration and development. OIL is much smaller than ONGC and produces about 3 million tpy of oil, all from Assam. Until recently, it had a licence covering only about 2,500 km2 in Assam and Arunachal Pradesh. The company has explored its license area extensively and has replenished its reserves through steady but small discoveries. Since late 1981, OIL obtained exploration rights in Orissa (the Mahanadi basin), both onshore and offshore, and in areas in Rajasthan. 2.17 The Ministry of Petroleum is in charge of policy making in the petroleum sector. It monitors activities in the sector closely and, inter alia, has to vet all the programs and budgets proposed by public sector enterprises. The Oil Industry Development Board (OIDB), a public body created in 1974, provides financing to public sector enterprises in the petroleum production and refining sectors. Its only source of revenues is a cess levied on domestic oil production. The attached map (IBRD Map No. 16183) presents the main features of India's petroleum subsector. c. Development Prospects and Investment Strategy 2.18 The petroleum subsector program of the Government has four principal components: (i) to increase production from existing fields, primarily by accelerating development programs by ONGC and OIL in areas where petroleum has already been discovered; (ii) to accelerate exploration for yet undiscovered resources both by the national and foreign oil companies; (iii) to modernize the existing refineries and construct new ones; and (iv) to develop the gas pipeline system and construct additional gas-using plants (e.g. fertilizer and petrochemical plants) to use more effectively the significant gas reserves currently untapped. 2.19 Following the successful implementation of the initial four phases of development of the Bombay High field as well as the encouraging results of recent exploration activities, GOI has authorized both ONGC and OIL to accelerate their petroleum exploration and development programs. Thus, while the current Plan (1980/81-1984/85) originally earmarked about Rs 33.3 billion in 1980/81 prices for petroleum exploration and development, representing a 47% real increase above the actual expenditures during the previous five-year period (1975/76-1979/80), ONGC and OIL have responded with a much higher revised budget proposal of about Rs 53.8 billion in 1980/81 prices for exploration and development, most of which has already been approved. The focus of this revised program is the accelerated implementation of the fifth and sixth phases of the Bombay High field, the development of the offshore South Bassein gas field and further exploratory drilling in Krishna-Godavari basin. As mentioned earlier, several other areas are expected to be explored by foreign firms on a production-sharing basis during the current Plan period. 2.20 The accelerated petroleum exploration and development program would also mean larger investments in petroleum refining and distribution facilities as well as investments for downstream processing plants (e.g. fertilizer and petrochemical plants). In particular, the development of the South Bassein gas field will require the rapid implementation of six new gas-based fertilizer plants and related gas pipelines. A comparison of the actual expenditures for the petroleum sector during 1975/76-1979/80 as well as the original budget provisions and the revised estimate for the current Plan (1980/81-1984/85) is shown below: - 15 - Petroleum Sector Investments (Public Sector) (In Rs billions and 1980/81 Prices) a/ As % of Total Plan Total Expenditures Exploration & Refining & Petroleum Expl. & Total Pet. Period b/ Development Marketing Sector Dev. Sector ONGC OIL Total 1975/76-79/80 A 20.1 2.5 22.6 8.0 30.6 3.3 4.3 1980/81-84/85 B 30.0 3.3 33.3 8.6 41.9 2.9 4.3 E 47.9 5.9 53.8 N.A. N.A. N.A. N.A. a/ Based on the implicit price deflator of gross domestic capital formation. b/ A stands for actual, B for original budget, and E for revised estimate. The Bank's Role and Lending Strategy in the Petroleum Subsector 2.21 Most of the Bank's lending operations to India in energy have been in the power subsector (27 Bank/IDA operations for a total of US$3,059.0 million) and spans a period of 32 years. However, the Bank's involvement in the petroleum subsector has grown substantially. Three loans have been made to ONGC including two for the development of the Bombay High fieldl/ (US$ 0 million in all), and one for exploration in the Krishna-Godavari delta_ (US$165.5 million); a US$200 million loan was made in April 1982 for the modernization of several refineries3/. 2.22 The Bank's role in the Indian petroleum sub-sector continues to address several inter-related aspects with varying degrees of emphasis depending on the specific projects. These aspects are: (i) providing policy advice on hydrocarbon exploration, development, processing and utilization strategy through Bank involvement in key projects; (ii) assisting the domestic petroleum companies develop their technical expertise and capability in each major phase of hydrocarbon exploration, development and processing; (iii) contributing to improve the technical design and implementation arrangements of major projects; and (iv) strengthening the profitability and financial structure of project entities so that they can self-finance a substantial portion of their investments and attract more commercial financing for such investments. 2.23 With regard to oil exploration, India's policy of having parallel efforts by national and international oil companies is fully justified and is 1/ Loan No. 1473-IN approved in June 1977, and Loan No. 1925-IN approved in December 1980. 2/ Loan No. 2205-IN approved in October 1982. 3/ Loan No. 2123-IN approved in April 1982. - 16 - well focused. In this respect, the Bank is helping to implement the "open door" policy which India has recently adopted. The Bank has also, to a considerable extent, assisted ONGC and GOI in defining the Krishna-Godavari Project, using oil industry practices, with a view to minimize the risks inherent in such a large and technically complex exploration venture. 2.24 The Bank has been associated with Bombay High development since the early stages, and was instrumental in ensuring that all the required reservoir and field development studies had been carried out in accordance with industry practice before the huge development program was launched. Subsequently GOI requested Bank financing for Bombay High development. The development of the Bombay High field has proceeded largely according to plans, with ONGC implementing progressively more complex and larger phases, after reservoir studies and actual production performance have confirmed the initial expectations. In line with modern oil industry practices, ONGC has planned early for the introduction of reservoir pressure maintenance through water injection, which should constitute the bulk of the next development phase. Throughout the development of Bombay High, ONGC has used experienced foreign consultants and contractors, to optimize the oil recovery and the technical design, as well as to su~ lement ONGC's own capabilities. A Project Performance Audit Report_ for the first Bombay High Project was submitted to the Board in October 13, 1982. 2.25 ONGC's efforts in the Bombay High development were supported by the Bank through the two loans mentioned earlier which included undertakings by GOI regarding the adoption of oil and gas pricing policies which would enable ONGC to earn satisfactory profits, thereby improving its creditworthiness, and increasing its commercial borrowing capability to help finance its large investment program. In this regard, the Bank encouraged GOI and ONGC to seek external financing for Bombay High development. The first Eurodollar borrowing (US$50 million) was obtained on highly favorable terms in connection with the first Bombay High Project loan, which paved the way for subsequent larger recourse to private external sources in support of the Bombay High program. From 1977-78 through 1981/82, ONGC obtained commitments for approximately US$409 million from commercial sources, compared to nil prior to that period. Though most of these borrowings cannot be categorized as cofinancing, they can be credited, to some extent, to the Bank's advice and catalytic role in securing commercial financing. More recently, GOI adopted a policy of using ONGC as a major vehicle for commercial financing; under the new policy, all eligible items put to competitive bidding are offered with a request for commercial financing proposals (para. 3.23). Under this new policy, ONGC has obtained during the first nine months of 1982/83, about US$254.4 million of commercial loans/credits. Thus ONGC is currently one of the largest Indian borrowers on the international capital markets. 2.26 While ONGC has acquired considerable expertise in offshore oil development during the past seven years, it still faces substantial technical and financial challenges during the next decade in undertaking a large and ambitious investment program on its own as well as in any joint-venture development efforts that would hopefully materialize with international oil companies. Technically, ONGC will need to concentrate its capabilities 1/ Project Performance Audit Report No. 4139, October 13, 1982. - 17 - primarily on those areas where discoveries have already been made. Financially, ONGC will need to continue mobilizing large amounts of foreign exchange. So far, ONGC has successfully borrowed increasingly larger amounts to help finance its investment requirements from foreign commercial loans/credits, as discussed in paras. 3.23 and 6.12; the Bank will continue to encourage GOI and ONGC to increase recourse to foreign commercial borrowing 2.27 Over the past two years, the Bank has had an extensive dialogue with ONGC and GOI in relation to the development of India's offshore free gas reserves, concentrating in particular on the optimization of the design s,f the development of the largest gas discovery to date, South Bassein, and the build-up of a market for natural gas. The development of South Bassein represents a new challenge to ONGC as it is the first major gas development project in India; unlike crude oil, such a project has to be optimized, not only in terms of reservoir considerations, but also in relation to the future market for natural gas. The Bank therefore discussed with GOI, ONGC, and its consultants, at various stages of project preparation, the scope of market studies to be carried out and their conclusions. As a result the main components of the Project have been optimized in terms of the anticipated market. 2.28 In relation to the utilization of offshore gas, until 1980, a policy decision had been made to dedicate practically all of India's offshore reserves of associated and free gas to fertilizer production. In view of the potential for large-scale gas discoveries, as being experienced in other countries, the Bank in 1980 commissioned an independent study aimed at identifying the various potential economic uses of gas in the economy. The study, which was subsequently discussed with the Government, examined the merits of gas utilization for different purposes in India, and concluded that gas would be an economic resource, not only for fertilizer production, but also for a variety of other uses involving the replacement of liquid fuels, and even for special cases of power generation as bottlenecks in coal supplies cause, in turn, power shortages with adverse repercussions for the manufacturing sector. Furthermore, as sizeable investments are required for new gas-based industries, Bank has encouraged the development of India's gas resources by participating in the financing of several projects based on offshore gas. During the implementation of the proposed Project the Bank intends to continue helping GOI formulate a long-term gas strategy designed to accelerate the development of free gas reserves while building a market for gas both as feedstock, and as a replacement of liquid hydrocarbons. - 18 - III. THE PROJECT Objective 3.01 Natural gas, currently a minor source of energy, could become an important source of energy by the end of the decade, given the potential large gas reserves and prospects, not only as fertilizer feedstock but also as substitute for liquid hydrocarbon fuels in a highly industrialized and heavily populated part of India. The proposed Project consists of the first phase of the South Bassein field development which is currently estimated to have the potential to sustain a production rate of 20 million Nm3 per day (MMCMD) of gas for a period of at least 20 years. The Project will bring the production capability of the field to 5 MMCMD, help meet the feedstock requirements of two fertilizer plants, and begin to meet the demand in Maharashtra and Gujarat for the replacement of liquid hydrocarbons. The Project will also constitute the cornerstone for the basic infrastructure required for the development and utilization of offshore gas reserves in Western India. Main Characteristics of the South Bassein Field 3.02 The South Bassein field is located approximately 65 kilometers west of Bombay in the Arabian Sea at a water depth of 57 m. The discovery well was drilled and completed as a gas producer in early 1976. Since then twelve wells were drilled to delineate the structure and the reservoir. Map 16183 shows the location of the field. 3.03 The South Bassein field is located on the southern culmination of an asymmetrical anticlinal feature having two well defined culminations aligned in a north-northwest, south-southeast direction. The northern culmination of the anticlinal feature constitutes the structure for the Panna (or North Bassein) oil field. Production is obtained from the A Zone and B Zone carbonate reservoirs of Lower Oligocene/Upper Eocene age encountered at about 1,600 m subsea. The entire South Bassein field is underlain by water and a thin oil column. At the B Zone oil-water contact, the field is about 33 km long and 10 km wide and has a total hydrocarbon column of 160 m. 3.04 The hydrocarbon reserves of the South Bassein field are estimated by D.R. McCord and Associates (Consultants, USA) as follows: Million Cubic Meters (MMCM) A Zone B Zone Free gas 30,900 244,100 Condensate 4.4 35.2 Oil 3.9 214.6 Solution gas 700 37,100 The oil reserves (218.5 million m3 or 1.4 billion Bbls) are widely distributed throughout the reservoir within a 20-meter interval containing relatively high transitional water saturations. To date all efforts to produce oil from this thin oil column have been unsuccessful due to early water and/or gas encroachment. About 74.5% of the free gas reserves (204.9 MMCM or 6.8 TCF) are estimated to be recoverable in about 30 years, along with 29.5 MMCM (185.5 - 19 - million barrels) of condensate. The reservoir is capable of maintaining a plateau production rate of 20 MMCMD for at least 20 years through some 24 wells. The reserves of the South Bassein field and the production characteristics are examined in more detail in Annex 3.1. Project Design and Optimization 3.05 The Ministry of Petroleum appointed an Expert Committee on April 28, 1980 to consider ONGC's proposal for laying a pipeline from the South Bassein gas field to Gujarat and other locations to the north. Its major task was to select the optimum pipeline route, a matter of vital interest to the states of Maharashtra and Gujarat. The choice finally devolved on two alternatives: to make landfall at Nawapur in Maharashtra and then overland to the IDA-assisted (Cr. 1125-IN of March 1981) Hazira fertilizer complex in Gujarat and on north or whether to make the landfall at Umrat near Hazira in Gujarat (see Map IBRD 16184). After an exhaustive study of all pertinent factors and data related to the two routes and the gas utilization plans, the Committee selected the Umrat route. The results of these studies showed this alternative to be marginally preferable, but the decisive factor in the selection was the fact that construction could be completed at least a year earlier by taking the offshore route. 3.06 D. R. McCord and Associates (USA) carried out geological and geophysical studies of the field; the results of these studies form the basis for the reservoir evaluation and development plan for the field (Annex 3.1). Earl and Wright (USA) prepared the conceptual studies necessary for the sizing and specification of the facilities required for the offshore production complex, following a careful evaluation of the available alternatives. 3.07 Snamprogetti (Italy) was assigned to study optimization of the pipeline from South Bassein to the Hazira terminal. An important element of the study was to determine whether the pipeline should transport "dry" or "wet" gas, the latter being a gas which would undergo some degree of condensation depending on its composition and transient temperature and pressure conditions in the pipeline. To avoid any condensation in the pipeline the South Bassein gas would have to be chilled to around 100C to drop out all the condensate before the gas enters the pipeline. Snamprogetti's calculations show that at 20 MMCMD flow rate, a 36"-diameter pipeline is needed to transport "wet" gas but only 32" for "dry" gas. This reduction in pipe size would save approximately US$50.0 million in materials and construction costs. However, these savings would be offset by the necessity to install additional offshore platform space along with the required refrigeration, condensate, ancillary and utility facilities at a cost of about US$35.0 million, and higher operating costs (about US$11.0 million per year for fuel alone if one assigns the fuel oil equivalency value to natural gas). Further, whenever the refrigeration unit is down for repairs or maintenance, pipeline capacity would be reduced to about 75% of normal design flow rate. This would require some consumers to accept periods of load shedding or the installation of 100% refrigeration standby once the line capacity is fully committed. On the basis of these and some other important considerations the decision was made to transport "wet" gas to Hazira and take care of the condensate removal there. The Bank agrees with this decision. 3.08 To determine the optimum pipe diameter Snamprogetti calculated the investment and operating costs for 20, 25 and 30 MMCMD throughput at various - 20 - inlet pressures and pipe diameters. The terminal pressure at Hazira was kept constant at 820 psig which is a reasonable selection from the standpoint of the fertilizer plants' requirement, the cryogenic turbo-expansion unit to be installed for LPG and C2/C31/ recovery, and flexibility to increase throughput by adding compression at the terminal to make up for any drop in pressure needed to induce a greater flow rate. The optimum pipe diameter for 20, 25 and 30 MMCMD was found to be 36", 40" and 42" respectively with an optimum inlet pressure of 100 atmospheres.2/ The 36" diameter option (20 MMCMD) was selected because: (a) 20 MMCMD is the estimated plateau production rate from the South Bassein field and forecasts indicate that this is a realistic demand rate as well; (b) should production capacity and demand eventually exceed 20 MMCMD, throughput can be increased by additional compression at South Bassein and/or at the terminal; and (c) 40 and 42" pipelines have not yet been installed in offshore waters. This poses a technical risk, and since construction costs and durations were extrapolated from experience with 36" pipeline construction there is the possibility that costs for the larger diameter pipelines could have been substantially underestimated. The Project gas reserves and optimization study are in the Project file (Annex 7.1). The Project 3.09 The Project comprises ONGC's Phase I development of the South Bassein gas field which will provide a production capacity of 5 MMCMD. The remainder of the development program will be implemented during 1984/85 - 1987/88 and will raise the production capacity to 20 MMCMD. For the Project, the major offshore facilities will consist of a central platform complex, located near Well SB-7 at approximately latitude 19o-11' north and longitude 720-7' east, and a 235-km pipeline (217 km will be under water) to the Hazira terminal. The complex will have four steel platforms fixed to the ocean floor and interconnected with bridges to accommodate respectively well drilling, gas processing, gas flaring and operator living quarters. The primary function of the complex is to serve as a gas gathering and shipping terminal for South Bassein gas and as a compressor station for associated gas from Bombay High. However, it will also serve as the nucleus for the expanding operations at South Bassein and satellite fields in the coming years. 3.10 Six wells with the capability of producing a total of 5 MMCMD of gas under normal operating conditions will be drilled from the fixed drilling platform. Provisions will be included to permit drilling three more wells to test oil bearing strata in the structure. An adjoining processing platform 1/ Ethane/propane mixture. 2/ Equivalent to 1,470 psig. - 21 - will have provisions for separating natural gas liquids (NGL with an API gravity of 52.20) and moisture from the gas. The NGL will be pumped into the existing 30" Bombay High crude oil trunk line via a 12" tie line, and the gas will be shipped to Hazira over a 36" pipeline (see Map IBRD 16184). It will also be possible to ship South Bassein gas to Uran through a 20" tie-line into the existing 26" Bombay High gas trunkline and ship Bombay High associated g_ to Hazira through the same tie-line. Compression facilities on the process platform will have the capability of delivering up to 5 MMCMD of Bombay High associated gas to Hazira. A platform for flaring gas in an emergency situation and a platform containing living quarters for 125 persons completd the central platform complex.l/ 3.11 The 36" gas pipeline will make landfall at Umrat in Gujarat and proceed overland to the Hazira terminal (the actual locality is Kawas, a short distance from Hazira) located adjacent to the fertilizer complex. The terminal will consist of facilities for condensate extraction, and stabilization, together with ancillary and utility units. An LPG recovery plant is scheduled to be built by 1985/86 on the terminal site, but is not included in the project scope. 3.12 The major components of the proposed project are summarized below. A detailed description of these facilities appears in Annex 3.2. - Drilling Platform: Installation of one four-pile fixed platform and drilling of six production wells (the platform will have extra slots for three more wells) located in the vicinity of the process platform. The two platforms will be connected by a bridge which will also carry the production and test flow lines from the wells to the process units. - Process Platform: One two-deck, eight-pile fixed platform containing natural gas and natural gas liquids processing facilities designed to handle 10 MMCMD of free gas. The platform will be installed in the vicinity of well SB-7 in approximately 60 m of water. - Living Quarters Platform: One four-pile, two-deck fixed platform located in the vicinity of the process platform and connected to it by a bridge. The platform will provide living quarters and amenities for 125 persons and will contain the necessary utilities and a helideck. - Flare Platform: a four-pile fixed structure connected to the process platform by a bridge, with a flare. 1/ In subsequent phases three drilling platforms supporting 18 production wells, one 10-MMCMD process platform, and about 1,000 km of onshore gas pipelines will be installed at an estimated cost of US$1.1 billion in end-1982 prices to increase South Bassein's production capacity to 20 MMCMD. In addition, four LPG plants and two C2/C3 plants will be installed at a cost of US$0.5 billion. The first LPG plant is being built in conjunction with the proposed Project. - 22 -- - South Bassein to Umrat Pipeline: a 36", 217-km long submarine pipeline designed to carry 20 MMCMD of gas. - Umrat to Hazira Pipeline: a 36", 18-km long land pipeline to the terminal at Kawas adjacent to the Hazira fertilizer complex. - South Bassein - Bombay High Gas Tie-in: a 20", 17-km long submarine line from the South Bassein process platform to the 26"-Bombay High gas transmission line. - NGL Line: a 12", 17-km long submarine line from the South Bassein process platform to the 30" Bombay High crude oil transmission line. - Hazira Terminal Facilities: condensate separation, stabilization and storage, pigging, utilities and ancillary facilities. - Engineering and Technical Services and Reservoir Consultancy: includes consultants to prepare engineering design and bid packages, assistance in construction supervision and overall project management, other project services such as surveys and certifications of offshore structures, and assistance to ONGC in implementing and monitoring the gas production program. Engineering and Construction 3.13 ONGC relies almost entirely on expatriate expertise in the engineering and construction of its offshore installations. Earl and Wright have prepared bid documents for all the offshore structures, production, processing and utility units. The successful bidder for the supply of the platforms will be responsible for detailed design and engineering, procurement, and fabrication, and will also act as the main contractor for the platform complex. Transportation, installation, hook-up and commissioning of the platforms will be bid separately and the successful bidder will act as a subcontractor to the main contractor; worldwide there are several fabrication yards (i.e. shipyards) and about a half dozen or so installation firms with the expertise and resources to undertake projects of this magnitude and complexity. The supply of pipe materials will be bid separately from the transportation and pipeline installation job. The latter requires highly specialized pipe-laying expertise but there are several qualified contractors worldwide. Engineers India Limited (EIL) will assist ONGC in supervising the construction phase. 3.14 Snamprogetti has been assigned design and engineering responsibility for the 36" offshore pipeline and the Hazira terminal. The consultant will also assist ONGC in preparing all procurement documents, bid evaluations and construction supervision. Construction of the land portion of the pipeline and the terminal facilities will be contracted to qualified local firms. During negotiations assurances were obtained that ONGC will continue to use consultants whose qualifications, experience and terms of reference are satisfactory to the Bank in the design, engineering and preparation of bidding documents and the supervision of construction of the project facilities. - 23 - Execution 3.15 The project will be executed by the Bombay Offshore Project (BOP) group which is responsible for all operations related to Bombay High and the surrounding areas. 3.16 Overall supervision of the project will be assigned to experienced senior BOP staff at the General Manager and Deputy General Manager levels who, along with senior project managers, have had extensive experience in the Bombay High development program. The organization is burdened with a heavy work load, but with the provisions which have been made for outside assistance, the project should be successfully completed on schedule. 3.17 BOP's arrangements for executing the project have been reasonably effective in the past and are satisfactory to the Bank. The central platform complex, the onshore and the offshore portion of the South Bassein-Hazira pipeline will be under the direction of the Construction Division with a Deputy General Manager assigned to each of the three components along with other project management staff from the division. A similar arrangement exists for the Hazira terminal component under the direction of the Production Division. The wells will be drilled by the Operations Division either with an ONGC rig or a contract rig depending which is available for the time slot allotted to the drilling. Supporting services will be provided by the other BOP divisions. 3.18 In addition to the consultant assistance mentioned previously ONGC has engaged the services of King Wilkinson (USA) to provide back-up support for its entire offshore construction program. The consultants' assignment is to provide advice and assistance during all facets of offshore construction projects including: (i) project planning, scheduling and controls including appropriate computer based techniques; (ii) supervision during fabrication, construction and installation of offshore facilities; (iii) trouble shooting throughout the project cycle; and (iv) preparation and administration of a comprehensive training program. Implementation Schedule 3.19 The project is scheduled to be completed and commissioned by the end of May 1985 (Annex 3.3). For the pipeline and terminal facilities about 15 months have been allotted from tendering in March 1983 to the commissioning in May 1984, which is tight but achievable. The platform complex will be commissioned one year later in May 1985, about 25 months after tendering. The pipeline work schedule is tight, because of ON GC's fertilizer gas supply commitments beginning in early January 1984 0. With no unforeseen major equipment delivery or construction setbacks, ONGC should succeed in meeting its project completion target. 1/ GOI/ONGC confirmed during negotiations that supply of gas to the Hazira fertilizer plant during the testing and trial production in early 1984 will be arranged from ONGC's Gujarat gas production. From June 1984 to April 1985, Bombay High associated gas will be supplied to Hazira through the South Bassein pipeline. - 24 - Estimated Cost 3.20 The total project financing requirement is estimated at about US$702 million including the capitalized front-end fee on the Bank loan, contingencies and customs duty on imported materials and equipment for the onshore facilities and the subsea pipeline within the territorial waters of India. The foreign exchange component is estimated at US$603 million or 86% of the total cost. Estimated project costs are summarized below; a detailed cost breakdown appears in Annex 3.4. Project Cost Summary Rs Million US$ Million Local Foreign Total Local Foreign Total Process Complex - 1,250.10 1,250.10 - 138.90 138.90 Tie-in to crude oil & gas trunklines - 272.07 272.07 - 30.23 30.23 Wells (6) 67.95 67.95 135.90 7.55 7.55 15.10 South Bassein-Hazira pipeline 352.75 2,638.80 2,991.55 36.19 293.20 329.39 lazira terminal facilities 64.29 24.30 88.59 10.15 2.70 12.85 Telecom & Telecontrol 20.09 9.00 29.09 2.23 1.00 3.23 Land 36.00 - 36.00 4.00 - 4.00 Engineering & Supervision a/ 207.45 90.54 297.99 23.05 10.06 33.11 Reservoir Consultancy - 126.90 126.90- - 14.10 14.10 Subtotal]i/ 748.53 4,479.66 5,228.19 83.17 497.74 580.91 Physical Contingency -/ 74.86 447.93 522.79 8.32 49.77 58.09 Price Contingency 66.29 466.74 533.03 7.37 51.86 59.23 Front End Fee - 29.70 29.70 - 3.30 3.30 Total Financing Required 889.68 5,424.03 6,313.71 98.86 602.67 701.53 a/ Includes US$ 1.0 million for surveys and US$2.5 million for certification fees. b/ Local cost includes duties of Rs 280.35 million for pipeline (Rs 266.35 million), for Hazira terminal facilities (Rs 10.2 million) and for telecom and telecontrol facilities (Rs 3.8 million). c/ At 10%. - dI Foreign Cost: At 8% in 1983/84, and 7.5% in 1984/85, as well as 1985/86. Local Cost: At 7.5% per fiscal year during the project implementation. Exchange rate is Ra 9.00 - US$1.00 Phasing of expenditures appears in Annex 3.5 and can be summarized as follows: US$ Millions ONGC Fiscal Year 1983/84 1984/85 1985/86 Total (Ending March 31) 393.69 259.91 47.93 701.53 - 25 - 3.21 Development drilling costs were derived from ONGC's historical costs in the Bombay High field for wells drilled to similar depths as the South Bassein wells. The cost of the offshore platform complex is based on current steel tonnage and equipment cost of similar facilities being installed on the Second Bombay High Project. The offshore and onshore pipeline and shore terminal costs were estimated by the consultants, Snamprogetti. Overall engineering services have been estimated at 8% to 10% of the basic project cost in line with past experience on this type of project. The expected average cost per man-month for the various engineering services required for the project is US$12,000 and US$1,800 for foreign (800 man-months) and local consultants, respectively, including travel, subsistence and overheads. Reservoir consultants (850 man-months) are expected to average US$17,500 per man-month. These consultancy costs are based on actual contracts or in line with those presently experienced by ONGC in other projects. A physical contingency of 10% was applied to the total base cost (expressed in January 1983 prices) for all Project items which is considered satisfactory in view of the advanced stage of project design. ONGC's Financing Plan 3.22 The proposed Project represents about 6%, while the full development program about 19%, of ONGC's overall investment program of about Rs 109.6 billion (US$12.2 billion) over 1982/83 - 1985/86. The financing plan of the overall investment program of ONGC is shown in para. 6.10, and indicates that internally generated funds will finance about 68%, and borrowings about 32%, of the investment program. The aggregate Bank disbursements!' for the 1982/83 - 1985/86 investment program is projected to be about US$566 million, or approximately 5% of ONGC's total investment program and about 9% of ONGC's total foreign exchange requirements. 3.23 In recent years, the strategy of GOI and ONGC has increasingly been to diversify the sources of financing to ONGC, essentially by securing suppliers' credits when advantageous, and by Eurodollar borrowings otherwise. The policy, adopted in late 1981 by the Government, is to utilize as much external financing as feasible to meet the foreign exchange requirements of ONGC's investment program; as a regular practice, ONGC now requests financing proposals as it issues bids for major procurement items. Once ONGC has evaluated the bids, a decision on final award, taking into account the most suitable financing arrangement (e.g., bilateral loans, suppliers' credits, commercial loans) is taken by the Government. During 1980/81 and 1981/82, against a total foreign exchange requirement of about US$1.1 billion, ONGC utilized about US$230 million (21%) from commercial loans/credits, and about US$385 million (35%) from official development assistance, with the balance (44%) covered by foreign exchange purchased with internally-generated resources. Following the recently adopted procedure described above, it is expected that a substantial proportion (30-50% or roughly US$2 to 3 billion) of ONGC's foreign exchange requirements for investments during the period 1982/83 - 1985/86 could be met with foreign commercial loans/credits. As mentioned earlier (para. 2.25) ONGC has already obtained about US$254.4 million of commercial loans/credits during the first 1/ Disbursements from the Second Bombay High Offshore Development Project (Loan 1925-IN), the Krishna-Godavari Exploration Project (Loan 2205-IN), and the proposed South Bassein Gas Development Project. - 26 - nine months of 1982/83, in addition to about US$206.2 million of bilateral and multilateral loans (including US$165.5 million from the Bank for the Krishna- Godavari exploration project). Furthermore, bids with an aggregate value of about US$167 million for which financing proposals have been received are under evaluation and will be awarded shortly. Several major bid packages requesting financing proposals with a combined value of about US$283 million have also recently been issued or will be issued by the end of 1982/83. Finally, ONGC is considering a Eurodollar loan of about US$300 million within the next several months. Given that the worldwide demand for petroleum equipment is declining and interest rates are expected to decrease somewhat, it is reasonable to expect that ONGC can mobilize substantial commercial loans towards its investment program during 1982/83 - 1985/86. Project Financing Plan 3.24 The South Bassein Project is highly suitable for external commercial financing, both in the form of suppliers' credits, and commercial bank loans (para. 3.26). In line with the procedure described earlier, ONGC intends to ask bidders for the pipes, the platform complex (equipment and fabrication), the drilling materials and some of the equipment for the terminal facilities to submit financing proposals together with their bids. As a result, the financing plan for the Project can be anticipated to be as follows: Project Financing Plan US$ Million % Suppliers' Credit (Pipe) 150.0 21.4 Suppliers' Credit (Platforms, Drilling Materials & T rminal Facilities) 100.0 14.3 Proposed IBRD a/ 222.3 31.7 Kuwait Fund 50.0 7.1 ONGC 179.2 25.5 701.5 100.0 a/ Including Front-End Fee b/ The Kuwait Fund has negotiated an agreement with ONGC for about US$50 million towards the financing of the Project. The loan will be for 20 years including a 5 year grace period with an annual interest rate of 4% to GOI and an onlending rate of 12% to ONGC. The loan will finance part (US$30 million) of the pipe-laying contract, the pipe coating/wrapping contract (US$18 million) and some technical and consultancy services (US$2 million). ONGC's contribution would represent about 2% of its internal cash generation during the period. During negotiations assurances were be obtained that, if required, GOI will provide ONGC, or cause ONGC to be provided with sufficient funds to meet ONGC's financial requirements for the Project. 3.25 The Bank loan of US$222.3 million would represent about 32% of the Project cost, and about 37% of its foreign exchange cost. The Bank loan would be made to GOI at standard IBRD interest terms over 20 years including a five- year grace period with a front-end fee of 1.5%. GOI would onlend the proceeds - 27 - of the Bank loan to ONGC at an interest rate of at least 12% (in line with rates to public sector enterprises) over, at most, 15 years including a five- year grace period. The onlending maturity of 15 years is sufficient considering the substantial cashflow potential of the full development program after it is completed in 1987/88. The grace period of 5 years is necessitated by the need for additional investments (US$1.6 billion in end-1982 prices) during 1984/85 - 1987/88 over and above the Project requirements to complete the development program and raise production capacity to 20 MMCMD from the Project's initial phase development of 5 MMCMD (para. 6.08). In general, the onlending terms are reasonable considering the long-term nature of the investment and economic life of the gas reserves, the relatively long duration of the full development program, and the need to invest in substantial infrastructure (i.e., pipelines) particularly inland. The foreign exchange and interest rate risks would be borne by GOI.l/ The onlending rate is expected to exceed domestic inflation rates which are not likely to be over 8% annually in the next five years. Execution of the Subsidiary Loan Agreement on terms and conditions satisfactory to the Bank would be a condition of effectiveness of the proposed loan. Items Proposed for Bank Financing 3.26 A substantial proportion of the project costs, in particular the offshore platforms and the pipes, are suitable for financing by export credit agencies and by supplier's credits which generally provide financing of up to 80% of the FOB cost. Foreign engineering and consultancy services, as well as offshore platform installation, pipe-laying, and drilling contracts, however, are not normally financed by export/supplier's credits, especially pipe-laying since the barges for this activity often do not fly the flag of the contractor's nationality. These latter items have therefore been considered for Bank financing. In selecting the specific items for Bank financing and determining the proposed amount for the Bank loan, the following additional factors were taken into account: (i) items most suitable for ICB and which will involve the minimum (if any) retroactive financing will be selected; (ii) that the Bank's financial involvement will continue throughout the implementation period; (iii) that the weighted average of the grace periods and the maturities of all the loans should be satisfactory for a project of this type; and (iv) that the Kuwait Fund has already agreed to finance some technical assistance, part (US$30 million) of the pipe-laying contract, as well as the coating and wrapping of the main pipes. On the basis of these considerations, it was judged that the platform transportation and installation, about 85% of the pipe-laying contract and the pipeline materials other than the bare pipe, would be the most appropriate items for Bank financing. The foreign exchange cost of these items are estimated to be about US$219 million, equivalent to almost 24% of the total project cost. A Bank loan equivalent of US$222.3 million would meet the aforementoned objectives and maintain an adequate Bank financial presence in the Project; the loan would also finance the front-end fee of about US$3.3 million (which would be capitalized) as shown below. 1/ The new IBRD lending terms (i.e. variable interest rate) were discussed during negotiations. - 28 - Amount Allocated % of Expenditures (US$ million) to be Financed 1. Offshore pipeline (excluding bare pipes) 170.0 100% of foreign exchange expenditures a/ 2. Offshore Platform Complex (excluding equipment, structural materials and fabrication) 47.0 100% of foreign exchange expenditures 3. Engineering and Technical Services 2.0 100% of foreign exchange expenditures 4. Front-End Fee 3.3 Amount due Total 222.3 a/ Except for the portion (US$30 million) of the pipe-laying contract to be financed by the Kuwait Fund. Procurement and Disbursements 3.27 ONGC procurement procedures, which for imported items are similar to the Bank's international competitive bidding (ICB) procedures, will be used for the following items for which suppliers or exim-bank financing proposals will also be sought for major items (para 3.23); bare pipe materials (US$170 million CIF); fabrication and supply of platforms (US$120 million FOB); well materials and supplies such as casings, wellheads, drilling mud, cement, etc. (US$9 million CIF); and terminal equipment and instruments, as well as telecommunication and telecontrol equipment (US$5 million CIF). Bank ICB procedures will be used for the following contracts: installation of the main 36" offshore pipeline and tie-in pipelines including supply of flanges, valves, anodes, etc. (US$200 million); and transportation, installation, hook- up and commissioning of the platforms (US$47 million). Kuwait Fund procurement procedures will be followed for the pipe coating and wrapping contract (US$18 million). The estimated values of the various packages mentioned above include provisions for physical and price contingencies. Bid invitation and evaluation will be the responsibility of ONGC with assistance from consultants as required. The bidding documents, bid evaluations and contracts for the two Bank-financed packages will be subject to Bank review and approval. 3.28 Disbursement of the Bank loan is expected to be completed by March 1985. The closing date would be December 31, 1985. The disbursement schedule can be found in Annex 3.6. The schedule is based on a three-month time lag between the time the expenditure is estimated to have been incurred and the time the equivalent funds have been disbursed from the loan. Ecology and Safety 3.29 The proposed project will cause few environmental disturbances of any significance except possibly for short intervals during the installation of - 29 - the offshore platforms and pipeline, and during drilling. Offshore platforms, after they are installed, generally attract a large aggregation of marine life and are not considered to be detrimental to the ecology. There is essentially no risk of oil spillage or other oil pollution. Petroleum condensate (i.e., NGL) separated from the gas will be piped directly into the crude oil trunkline. Water produced with the gas will be degassed and then processed through a corrugated plate interceptor which will remove entrained hydrocarbor. liquids to less than 25 parts per million oil content before disposal. Two sewage treatment plants are included, each sized to handle the total occupancy (125 men) of the accommodation platform, along with chlorinating facilities for the effluent. Both the onshore and offshore portions of the pipelinr -ill be buried, and the original surface features along the pipeline route will be restored. 3.30 Care has been taken in design to ensure the structural integrity of offshore installations. All such installations including the offshore portion of the pipeline will be designed and constructed in accordance with the latest standards and practices of the offshore petroleum industry. Design criteria are based on the report "Meteorological-Oceanographic Conditions Affecting Offshore Petroleum Operations in the Bassein Area, Offshore Bombay, India" by A.H. Glenn and Associates (U.S.A.). Soil data for the pipeline route and platform area was obtained and compiled by Fugro Geotechnical Engineers and Surveyors (Holland). A major international certifying agency will be appointed to inspect and approve the various stages of design, fabrication and installation of the offshore facilities. 3.31 All measures are being taken to minimize fire and other hazards. During drilling ONGC will monitor and enforce blow-out prevention and well control regulations and the use of appropriate safety equipment. The completed wells will be equipped with subsurface and surface safety devices which will allow automatic or manual shutdown of gas flow during emergency situations. The platforms (but excluding the flare platform) will have gas detectors at all strategic locations along with an alarm system. A similar system will be installed for fire detection which will comprise smoke, ultra violet and heat detectors. A deluge type fire water spray system will be automatically activated by the ultra violet sensors and by fusible plugs melting at 1850 F. In addition, a dry chemical fire fighting system will be installed on each platform deck and a Halon fire suppressing system for all enclosed areas except living quarters. Ample abandonment and recovery equipment will be provided including two survival crafts one for each of the two continuously manned platforms. The measures discussed above are in compliance with the Bank's general environmental guidelines for offshore petroleum projects. During negotiations, agreement was reached that ONGC will take precautions, in line with standard industry practices satisfactory to the Bank, to protect workers and the environment during the installation and operations of the offshore project facilities. IV. THE GAS MARKET AND JUSTIFICATION Introduction 4.01 Unlike crude oil, which .is an easily-traded commodity, natural gas cannot generally be traded in small volumes and therefore can be used beneficially only if there is a specific distribution system and market established for its use. Such a market would generally consist of users which - 30 - have shifted to gas from other energy sources, or of facilities which have been specifically established to take advantage of gas as fuel or feedstock. Obviously, developing a market for natural gas requires time and sizeable investments; however, the returns are often attractive as there is generally a wide spread between the full cost of gas development and its value as a fuel or feedstock replacement. The problems are compounded in the case of associated gas (i.e. gas produced together with crude oil) as, unless there is a market for it, usually, there is no alternative other than flaring it. 4.02 Gas is a minor commercial energy source in India at present, with a production in 1981/82 of approximately 3,840 MMCM (3.1 million t.o.e.) of which approximately 40% was flared because of the absence of either a distribution network or the small and dispersed nature of the supply. Until recently, the systematic development of a market for the economic utilization of natural gas was given low priority as the emphasis was to accelerate India's exploration and oil development activities to reduce the country's dependence on costly crude oil imports. However following the rapidly increasing production of Bombay High crude and its associated gas (in 1981/82, Bombay High accounted for 35% of gas production), and the discovery offshore Bombay of sizeable free gas reserves (particularly the South Bassein field), the Government has recognized that gas is a significant resource whose utilization can substitute for either fertilizer imports (by using gas as a feedstock for domestic manufacturing) or oil products (particularly LPG, naphtha and fuel oil) presently imported (whether in the form of crude oil or as products); as a result, increasing attention is being given to the optimal use of natural gas. Current Pattern of Gas Production/Utilization 4.03 At present, gas is produced in Assam (both by OIL and ONGC), Gujarat (ONGC) and in the Bombay High field; 1981/82 production and consumption figures are as follows (MMCM): 1981/82 Gas Production/Utilization Balance (MMCM) Assam Gujarat Bombay High Total Production 1,728.5 764.5 1,344.6 3,837.6 Flared 768.9 76.5 673.4 1,518.8 Used! 959.6 688.0 671.2 2,318.8 a! Includes quantities used by producers either for pressure maintenance or for electric power generation and heating processes. 4.04 Assam, located in the very northeastern part of India is a province with limited development potential because of (i) its remoteness from the major population and industrial centers of India; (ii) limited availability of land suitable for agriculture; and (iii) harsh climatic conditions (particularly heavy rainfalls 6 months out of 12). Historically, associated gas production began in Assam, but significant quantities of gas had to be flared (44% of the gas produced in 1981/82, as shown above) because many of the oilfields are widely dispersed and individually have small associated gas production, while the gas markets are located at considerable distances, making the use of the gas uneconomic. Major consumers of gas in Assam today are the Assam Electricity Board (gas turbines for power generation), the tea - 31 - estates, the Namrup fertilizer plant (currently being expanded), and a refinery. OIL is currently constructing an LPG recovery plant in Assam. It is estimated that, by 1985/86, consumers would be able to absorb 4 MMCMD against a production of 6.4 MMCMD. Therefore, notwithstanding current efforts to develop a market for associated gas in Assam, gas will continue to be flared in the foreseeable future. 4.05 The situation is dramatically different in Gujarat, which is an important industrial state. Production of crude oil began in the early 1960's and within a few years, a market was developed, capable of absorbing virtually the full production of associated gas. ONGC therefore contracted for gas sales equivalent to 2.18 MMCMD against a production capability of 2.25 MMCMD. Additionally, ONGC has committed supplies of 0.25 MMCMD which it intends to produce by (i) developing small free gas fields; (ii) recovering associated gas from certain isolated oil fields and laying new pipelines; and (iii) compressing low pressure gas currently flared. Nevertheless, it remains that Gujarat is considered a "mature" producing area; production of the main reservoir (Ankleshwar) is declining and, ONGC's oil and gas production in Southern Gujarat, unless new discoveries are made, is on a downward trend. 4.06 Approximately 55% of the gas sold in Gujarat is used for fertilizer production by two fertilizer plants, 22% for power generation, 20% for five industrial users (mostly as industrial fuel), and the balance for domestic consumption in Baroda. Consumption of natural gas in Gujarat could exceed by a considera le margin the present levels if additional quantities were made available._ 4.07 At Bombay High, which went into commercial production in May 1976, associated gas was initially flared. Following the completion of the 4.5 MMCMD gas processing and compression facilities as well as pipeline from that field to the Uran terminal (South of Bombay) in mid-1978, gas utilization rose rapidly from 0.6 MMCND in 1978/79 to 2.7 MMCMD in 1982/83. A second associated gas processing and compression facility, with a capacity of 5 MICMD will be installed shortly and completed in 1984/85 since associated gas production will reach about 7 MMCMD in 1983/84 and about 9.4 MMCMD by 1988/89. 4.08 At present there are three users for Bombay High gas: (i) the Tata Electric Company LTD (TEC) plant at Trombay (north of Bombay); (ii) the RCF fertilizer plant at Trombay; and (iii) the gas turbines of the Maharashtra State Electricity Board (MSEP) near Uran. TEC operates a power plant presently consisting of four units with a combined capacity of 337.5 MW of which 275 MW can also use natural gas as fuel. However the actual quantities of natural gas that can be absorbed also depend on contractual obligations of TEC with the two refineries in Bombay to acquire a fuel oil residue (low sulfur heavy.stock or LSHS) for which there is no alternative use at present.!' An additional 500 MW unit is to be installed in early 1983, whose 1/ The State of Gujarat is the second largest user of oil products after Maharashtra, accounting for instance for 20% of fuel oil and 20% of the naphtha consumption in India. 2/ Under the Refineries Conversion Project (Loan 2123-IN of April 1982), catalytic cracking facilities are to be installed in a Bombay refinery by mid- 1984, which will help resolve the problems of LSHS surplus. - 32 - boilers will also operate on coal, LSHS or natural gas.l/ By then, TEC will be able to absorb as much as 3 MMCMD of natural gas. 4.09 The RCF fertilizer complex at Trombay, consists of 4 units producing essentially ammonia (1,250 tpd), methanol (130 tpd) and phosphate fertilizers. The older units switched in 1978 from naphtha to natural gas as feedstock, while the newer ones-were designed to use gas as feedstock. Fuel requirements are met largely by natural gas, although fuel oil or LSHS can also be used. RCF Trombay can use 1.82 MMCMD of gas as feedstock and up to 0.45 MMCMD of gas as fuel. 4.10 MSEB commissioned in the first half of 1982 four 60-MW gas turbines, which can also operate on diesel oil. These were connected by a 7-km gas pipeline to Uran in June 1982. MSEB intends to use the turbines to meet the base load as long as power shortages continue in Maharashtra. Subsequently, they will be used for peaking only. Another set of four 60-MW units is currently under consideration by GOI. MSEB can currently use up to 1.8 MMCMD of natural gas. 4.11 In recent years, large quantities of Bombay High associated gas were flared on account of: (i) a significantly higher gas production than anticipated initially due to the acceleratred development program and higher than expected gas/oil ratios2/; (ii) the requirement for TEC to use LSHS surpluses as fuel, as explained in para. 4.08 above; and (iii) the delay in the build-up of the market for gas. However, the situation is expected to change dramatically in the next three years, with the commissioning of additional gas-based industries. Current Policy for Gas Utilization 4.12 In March 1979, the Ministry of Petroleum established a Working Group to "recommend the most economic and optimum utilization of offshore gas keeping in view the production program of crude oil/associated gas and free gas." That Working Group proceeded on the assumption that the offshore gas production potential was 21-27 MMCMD starting in 1982/83. The Working Group recommended that: (i) for the C3/C4 fraction, conversion to LPG would be the optimum use as LPG was a convenient substitute for kerosene; (ii) for the C2/C3 fraction, its use as a petrochemical feedstock for ethylene and propylene production (where it substitutes naphtha) would be optimal; and 1/ It is financed in part under Loan 1549-IN, of April 1978. 2/ For instance in 1980, production of gas was forecast to be 652.1 MMCM in 1981/82. In 1981, the forecast for the same year was 617 MMCM against an actual of 1,344 MMCM. For 1984/85, the old and current forecasts are as follows: Year Made 1984/85 Forecast (MMCM) 1980 878 1981 1,348 1982 3,770 - 33 - (iii) for the Cl (or lean gas) fraction, the optimal use would be as a fertilizer feedstock; alternative utilizations of the Cl fraction for industrial uses were discarded on various grounds (except for sponge iron where it was recommended that minor quantities of gas be considered for the reduction process). Use of the Cl fraction for power generation was turned down in view of the.economic advantage of coal. Furthermore, the Working Group recommended that no free gas be injected in the Bombay High-Uran gas pipeline in order to avoid diluting that gas (which is richer in C3/C4). 4.13 As a result, the Working Group recommended the establishment of J new 1,350-tpd ammonia units in addition to the 4 under construction (two at Thal in Maharahstra, South of Bombay, and two at Haziral! in Gujarat). The locations and proposed commissioning dates for the new plants are the states of Madhya Pradesh - 1986/87; Rajasthan - 1987/88; and Uttar Pradesh - two plants in 1987/88 and another two in 1988/89. With the plants currently under construction and the proposed six new plants, Nitrogen fertilizer production in India is forecast to reach about 4.6 million tons of Nitrogen in 1984/85, and 5.8 million tons in 1989/90 and onwards. However, Nitrogen fertilizer demand is still expected to exceed production by about 0.9 million tons of Nitrogen in 1984/85, 1.9 million tons in 1989/90 and 4.5 million tons in 1994/95. Thus, out of a total anticipated gas production capability of 21-27 MMCMD, 19 MMCMD were recommended to be used for fertilizer production; with respect to the balance of gas, detailed feasibility studies were recommended. As a result use of natural gas, even on an interim basis for replacement of liquid hydrocarbons in the vicinity of the pipeline was ruled out. 4.14 Over the past two years, GOI progressively realized that those recommendations had to be re-examined on the following grounds: (i) following additional offshore discoveries, the production potential of free gas has increased to 25-30 MMCMD over 20 years; (ii) associated gas production forecast had increased from 7 MMCMD to about 10 MMCMD over 1984/85-1990/91; (iii.) the realization that the utilization of gas for liquid hydrocarbons replacement was an attractive proposition even though the potential demand might not be as large as that for fertilizer feedstock.2/ As a result, in October 1981, the Ministry of Petroleum, established a new task force with detailed terms of reference which called for inter alia: (i) optimization of the pipeline from Hazira in Gujarat to UP taking into account the feasibility of extracting LPG on different locations on the pipeline route (which will affect the size of the pipeline); (ii) examining the feasibility of providing lean gas to cities such as Bombay, Ahmedhabad, Baroda and Surat (the largest cities on the pipeline route) for domestic consumption; (iii) the feasibility / The Hazira fertilizer plant is being financed in part through Cr. 1125-IN of March 1981, 2/ In 1980/81, fuel oil consumption in India was 7.4 million tons compared to a production of only 6.1 million tons. By 1990/91 the annual deficit is expected to double to 2.6 million tons (equivalent to 2.9 billion cubic meters or almost 8 MMCMD of gas) as consumption increases to about 10.2 million tons. About 57% of the expected fuel oil demand and 70% of the deficit in 1990/91 will be in the west and the northwest regions, where South Bassein gas can be used as fuel oil substitute. - 34 - of establishing additional fertilizer plants based on offshore gas, taking into account alternative feedstock possibilities; and (iv) improving the utilization of associated gas from Assam and Gujarat taking into account the long-term potential of the oil fields. The task force appointed consultants to execute specific studies, and is expected to complete its various assignments by April 1983. The Market for South Bassein Gas 4.15 The task force has already completed a conceptual exercise aimed at identifying the potential market for South Bassein gas both in Maharashtra (South Bassein gas could be injected into the existing gas pipeline from Bombay High to Uran) and in Gujarat and inland states. This forecast is not based on an exhaustive review of all the opportunities of gas utilization; it is based on the potential gas requirements of existing plants and plants under construction and limited utilization of gas in selected sectors where it appears a priori attractive to replace liquid hydrocarbons with natural gas. In Maharashtra, the main consumers for Bombay High and South Bassein gas would be as follows: a. Feedstock - the RCF-Trombay fertilizer complex already in operation; - the Thal fertilizer complex to be commissioned in July 1984 (first unit) and December 1984 (second unit); - the Deepak Fertilizers and Petroch l7icals Corporation Limited 272-tpd ammonia plant near Trombay- ; and - the Union Carbide petrochemical complex near Bombay. b. Liquid Hydrocarbons Replacement - the replacement of LSHS, fuel oil or diesel oil in boilers of RCF, in the refineries, in the petrochemical complex, and in the gas turbines; and - the introduction of lean gas to the existing town gas supply in Bombay City, and in a new system to be established in Greater Bombay. The existing system has a limited capacity (about 180,000 CMD), and is coal based (with adverse implications on the environment). Presently, the system supplies 30,000 consumers, while another 40,000 are on the waiting list (and potential users cannot any longer be added to the waiting list). It is estimated that for this system, within three years, and on the basis of 1/ This firm is the beneficiary of an IFC loan and equity investment (Investment 493-IN of November 1979). - 35 - only the potential consumers at a distance of less than 6 km from the existing pipeline grid, sales could reach 1.3 MMCMD of which 0.8 MMCMD would be for textile mills currently using fuel oil and LSHS. c. Coal Replacement - This category includes the provisions of gas for power generation at the TEC plant and as boiler fuel for the Thal fertilizer plant. 4.16 In Gujarat, the main consumers would be: a. Feedstock - The Hazira fertilizer plant together with six future fertilizer plants to be commissioned over 1986/87-1988/89 (para. 4.13). Each 1,350-tpd ammonia/urea plant will have a peak requirement of about 1.5 MMCMD of gas as feedstock and about 0.5 MMCMD as boiler fuel. - Feedstock requirements of enterprises located near the proposed inland pipeline route and who are presently using naphtha feedstock. b. Hydrocarbon Replacement - The boiler requirements of the six future fertilizer plants; - The shortfall in the supplies of Ankleshwar gas to meet the existing and future requirements of the existing ONGC grid (para. 4.05). - Fuel requirements of enterprises located near the proposed inland pipeline route and who are presently using fuel oil or LSHS. c. Coal Replacement - The boiler requirements of the Hazira fertilizer plant. 4.17 It is anticipated that both in Maharashtra and Gujarat, the LPG and C2/C3 fractions would be extracted before supplying the lean gas to consumers. ONGC already operates a 4-MMCMD LPG plant at Uran whose capacity is being doubled for commissioning in 1984/85. A third LPG plant will be required around 1986/87. With regard to Hazira, ONGC has obtained Government approval for that LPG extraction plant. In view of the high benefits of LPG extraction, confirmation was obtained during negotiations that this plant will be commissioned in 1985/86. The C2/C3 fraction will only be extracted when new petrochemical complexes are commissioned; both the Gujarat and the Maharashtra C2/C3 complex are due for commissioning in 1988/89. 4.18 The demand for South Bassein lean gas has been estimated by first establishing the demand in Maharashtra and in Gujarat for fertilizer feedstock, for liquid hydrocarbon (fuel) replacement and for limited cases of - 36 - coal replacement respectively. The feedstock requirements of the six proposed fertilizer plants in Madhya Pradesh, Rajasthan, and Uttar Pradesh were then added to arrive at the total feedstock requirement. The resulting demand forecast is shown in Annex 4.1. A forecast of the associated gas production from Bombay High and nearby offshore fields as well as the proposed South Bassein development program was then prepared (Annex 4.2). The lean associated gas production is then assumed to be allocated first for feedstock requirements and any surplus to liquid hydrocarbon and then coal replacement respectively, reflecting the priorities for gas utilization. The balance of the feedstock, liquid hydrocarbons and coal replacement demands not met by the lean associated gas supply is then the market for the South Bassein lean gas. This market is shown below which indicates a lean gas feedstock market developing in the mid-1980s but increasing rapidly as associated gas production peaks in 1988/89 and declines thereafter. As the table below indicates, the potential lean gas requirements for feedstock will exceed the production capability of the proposed Project by 1988/89 and that liquid hydrocarbon replacement alone could utilize the entire Project production. The combined feedstock and liquid hydrocarbon replacement requirements exceed the Project capacity the year production starts in 1985/86 and the production capacity of the full development program (i.e, 20 MMCMD) by 1989/90. In the third case, (i.e., including some coal replacement) the gas requirement would clearly exceed the full development production of gas at all times. South Bassein Lean Gas Market for Different Gas Uses (MMCMD) Demand for South Bassein Lean Gas Gas Used As Gas Used As South Bassein Lean Feedstock & Feedstock, Gas Supply Gas Used As Hydrocarbon Hydrocarbon and Year Phase I Phase II Total Feedstock only Replacement Coal Replacement 1984/85 - - - (1.34) 2.79 6.85 1985/86 3.72 2.26 5.98 1.38 8.91 13.50 1986/87 4.53 4.53 9.06 1.67 10.70 16.32 1987/88 4.53 8.51 13.04 3.91 12.94 19.06 1988/89 4.35 12.91 17.26 7.17 16.20 22.82 1989/90 4.34 13.00 17.34 9.99 19.52 27.14 1990/91 4.32 12.94 17.26 10.87 20.40 28.52 1991/92 4.30 12.88 17.18 11.78 21.31 29.43 1992/93 4.28 12.82 17.10 12.43 21.96 30.08 1993/94 4.28 12.82 17.10 13.14 22.67 30.79 1994/95 4.28 12.82 17.10 13.74 23.27 31.39 1995/96 3.73 11.19 14.92 14.42 23.95 32.07 1996/97 3.68 11.06 14.74 14.86 24.39 32.51 1997/98 3.62 10.87 14.49 15.25 24.78 32.90 1998/99 3.56 10.63 14.25 15.59 25.12 33.24 1999/2000 3.50 10.50 14.00 15.87 25.40 33.52 4.19 Although the Government's task force is to complete its studies only in April 1983 (para. 4.14), GOI has apparently decided that free gas would, under normal circumstances, be used essentially as feedstock and for liquid hydrocarbons replacement. This policy appears reasonable at present. During - 37 - negotiations GOI confirmed its preliminary plans in relation to gas utilization and that the Bank will have the opportunity to review and comment on the recommendations of the task force when its report on gas utilization is completed. As the volume of gas reserves are expected to increase in the coming years, the market for gas will therefore have to be reviewed from time to time. Agreement was reached with the Government tnat until March 1988, Lt will update and furnish to the Bank the gas production and utilization forecasts affecting the South Bassein and Bombay High gas whenever: (i) a major development of a gas project is envisaged; or (ii) significant changes in gas production from operating fields are expected; or (iii) signifi-ast changes in either the mix of gas users or the total gas consumption becomes evident. Economic Rate of Return 4.20 The main assumptions used in the economic analyses are shown in Annex 4.3. The analyses are done for, the Project (5 MMCMD production) as well as the full development program (20 MMCMD production). All economic costs and benefits are expressed in constant end-1982 prices. For the case of the full development program, the economic capital costs include the Project costs (excluding custom duties and taxes), plus the additional investments for the four LPG and the two C2/C3 extraction plants, three more production platforms, one more process platform, as well as the 1,000-km inland pipeline from Hazira to Uttar Pradesh. 4.21 The economic benefits were taken to be the savings in imports attributable to the Project. For the Base Case, the Project's gas production is assumed to be entirely used for hydrocarbon replacement (i.e., fuel oil substitute) which would give a conservative rate of return. The case where the gas is used both as feedstock and fuel oil substitute according to the expected demand mix is evaluated in the sensitively analysis. With regard to feedstock for fertilizers, the netback value for the gas was estimated (Annex 4.4).l/ With regard to hydrocarbon replacement and LPG produced through the TiW-ject, the values for the gas were estimated on the basis of its closest substitute. The NGL fraction was valued on the basis of its best opportunity use (i.e. naphtha). On the above basis, the gas values are as follows: 1/ In case there is a choice of either utilizing the gas as fuel at year t or as feedstock x years later, then the netback value (US$192 per 1,000 Nm3) should be discounted at the opportunity cost of capital for x years and the discounted value compared to the fuel oil equivalent price (US$160 per 1,000 Nm3). If the discounted netback value is less than the fuel oil equivalent price, then it is more economic to use the gas as fuel in year t than as feedstock in year t + x. In this particular case, if the opportunity cost of capital is at least 10%, then it would be more economic to use the gas as fuel at any year t if the alternative use as feedstock will be at least 2 years later. In the sensitivity analysis, part of the Cl gas fraction is valued at the netback value and part at the fuel oil replacement value. - 38 - Gas Fraction Valuation Basis End-1982 Prices US$/1000 Nm3 us$/1000 SCF Cl - Hydrocarbon Replacement (Base Case) Fuel Oil 160 4.29 Cl - Feedstock (sensitivity analysis) Netback 192 5.15 Cl- Coal Replacement Coal 64 1.72 C2/C3 Netback (approx.) 200 5.35 LPG (US$ per ton) Kerosene a/ 408 - NGL (US$ per ton) Naphtha b7 300 a/ India currently does not import LPG but imports kerosene. Thus it is expected that domestic LPG will replace kerosene imports. In view of the low demand for gasoline in India, the anticipated NGL from the Project is expected to be blended with naphtha. 4.22 For the Base Case, these prices are kept constant throughout the economic life of the investments. A sensitivity analysis was also performed assuming energy prices will increase in real terms by 2% to 3% per year between 1984/85 through 1994/95 and 1% per year thereafter, after initially falling by 4% between 1982/83 and 1983/84. The Base Case rate of return calculations are shown in Annex 4.5 (the Project) and Annex 4.6 (the Program) while the sensitivity analyses are shown in Annex 4.7. 4.23 Under the assumptions above, the economic rate of return of the Project is 38% and that of the full program is 49%. The sensitivity tests are summarized as follows: Economic Rate of Return (Z) Cases Project a/ Full Development Program 1. Base Case 38 49 2. Capital Cost Up 20% 32 41 3. Gas, LPG, etc. Prices Down 20% 29 38 4. Project or Program Delayed One Year 31 39 5. Worst Case (Combination of 2, 3 and 4 above) 21 26 6. Gas, LPG, etc. Prices Increase Annually in Real Terms b/ 41 53 7. Netback Value Used for Gas Feedstock 43 51 8. Gas, LPG, etc. Prices Up 20% 46 58 9. Capital Cost Down 20% 47 59 a! In the case of the Project only, the NGL recovered at the process platform and at the pipeline terminal as well as the rich gas (i.e, before the C2/C3 and LPG are extracted) at the Hazira terminal are the products. The rich gas is priced as Cl fuel (US$160 per 1,000 Nm3 in the base case). b/ See Annex 4.7 for details. - 39 - As the above table indicates, the rate of return is higher when gas is used as feedstock (using the fertilizer netback value) but would still be very satisfactory even if all the gas were used for fuel oil replacement only (i.e., base case). Thus, the economics of the Project would still be acceptable even if the proposed six new fertilizer plants are delayed or cancelled. The rate of return is reasonable for this type of project and development program. In the worst alternative, the rate of return is still an acceptable 21 % for the Project and 26% for the full program. The high rate of return is explained by the relatively low production cost of rich gas (about US$95/MCM or US$2.54/MCF at 12% discount rate for the Project) when compared to its economic value (plus the value of the NGL recovered with the gas) and the fact that all the past exploration costs of the field are considered as "sunk costs." 4.24 The rates of return above understate the benefits of gas utilization, particularly as the offshore natural gas is virtually free of pollutants (in particular sulfur), so that replacing fuel oil by gas would have a significant environmental benefit particularly in the Greater Bombay area. Project Risks 4.25 The risks facing this Project fall essentially into three categories: (i) reservoirs may not live up to the expectations; (ii) technical difficulties may affect the timely implementation of the project; and (iii) the development of the gas distribution system beyond Hazira may be delayed cutting off a large portion of the gas market for some time (applies only to the full development program). Regarding the reservoir, reserves have been evaluated, as explained in para. 3.06, independently by DeGolyer and McNaughton (US), McCord and Associates (US) and ONGC who broadly reached similar conclusions. Furthermore, twelve wells have been drilled on the structure, which is in excess of what industry practice would normally require. Therefore, while this risk cannot be discounted entirely, it has been largely minimized. 4.26 The risk of technical difficulties either in drilling or in connection with the construction of platforms and the laying of the pipeline might cause a delay and cost overruns. However, (i) ONGC, while not having previous experience in offshore free gas fields, has already gained considerable expertise in offshore construction and offshore oil and gas pipelines, and has performed generally well in the first two loans for Bombay High Development; (ii) unlike offshore crude oil development where ONGC now relies to a great extent on local consultants, foreign consultants have been hired both for the offshore platforms and the offshore pipelines; and (iii) all facilities are expected to be constructed and installed by experienced contractors supervised by ONGC with the assistance of qualified consultants. 4.27 With regard to the development of the market for gas, the main risk lies with a delay in the installation of the 1,000-km inland pipeline and/or postponement or cancellation of the plans to construct the six fertilizers plants inland. This risk does not however apply to the Project which has a small production capacity that could be easily absorbed by the markets around Bombay and the Hazira terminal. But even in the case of the full development program, the market risk is considered low in view of the importance of these plants to the Indian economy. Nonetheless, even if the gas is used mostly for liquid hydrocarbons replacement, the rate of return remains satisfactory. - 40 - 4.28 Since the main risks of the project have been recognized early, and satisfactory precautions have been taken to minimize these, the Project is highly justified, as it will provide significant savings to the economy by reducing both fertilizer and crude oil imports. V. THE OIL AND NATURAL GAS COMMISSION (ONGC) General 5.01 The Oil and Natural Gas Commission is a Government-owned statutory body created in 1959 by an act of Parliament to "plan, promote and implement the development of petroleum resources and the production and sale of petroleum products produced by it." ONGC's statutes provide that it is a corporate body with power to acquire, hold and dispose of property. ONGC also has authority to contract and borrow. The Commission consists of a Chairman and not less than two, but not more than eight, Members appointed by the Government for a period of five years. 5.02 At present, the Commission consists of the Chairman, six full-time Members (Finance, Materials, Personnel, Exploration, Offshore and Onshore) and two part-time Members (representing the Ministry of Finance and the Ministry of Petroleum. All decisions of the Commission must be approved by a majority of the Members. ONGC owns Hydrocarbons India Ltd, a subsidiary which is responsible for the Commission's ventures abroad (Iran). Organization and Management 5.03 The Commission acts very much as an operating board of directors and is responsible for setting ONGC's policies. Its plans and budgets have to be approved by the Planning Commission, the Ministry of Finance, and the Ministry of Petroleum, before they are sanctioned by Parliament. Over time, the Commission has evolved into a full-fledged oil company. In many areas, ONGC has developed an adequate in-house capability. However, aware of the rapid technological progress in oil exploration and petroleum engineering, ONGC continues to use foreign consultants when the in-house capability is insufficient or to verify critical results obtained in-house. ONGC has followed a consistent policy of ensuring that techniques developed in India reflect the latest technology available worldwide and are properly applied. 5.04 The main administrative and financial functions (planning, procurement and stores, accounting, personnel, computer activities, etc.) are centralized in the corporate headquarters at Dehra Dun, along with the main research and development and training facilities. Operational staff are divided among three regional offices (Central, Western and Eastern Regions) for onshore operations and the Bombay Offshore Project (BOP) for offshore operations. Prior to 1974 most of the operational decisions were taken centrally from Dehra Dun and the Regional Managers had little, if any, operational authority. In recent years, the decision-making process has been decentralized to the regions, which now have operational responsibility and the authority to commit funds within their approved budget. ONGC's Organization Chart appears at Annex 5.1. 5.05 The Bombay Offshore Project (BOP) is in charge of offshore exploration and development. Headed by the Member (Offshore), BOP has been the focus of intense activity over the past seven years with the - 41 - implementation of the successive phases of the Bombay High development and the substantial increase in offshore exploration activity. The increase in its staff has been particularly rapid: from 20 in 1974 to 600 in 1977 to 2,800 at present. The staff is highly motivated by the importance of the offshore projects to the Indian economy. Six General Managers report to the Member (Offshore): Engineering and Planning; Construction; Operations; Production; Exploration; and Materials. Also three Directors report to him (two for Finance, and one for Personnel and Administration). In addition, a ManagemenL Services Group assists the Member in project planning and monitoring as well as in special duties (i.e. safety and environment). This recent organization structure reflects the increasing scope and complexity of assignments given :o BOP; it also aims for greater delegation of authority, as well as a more equitable distribution of work loads, hence for instance the appointment of two General Managers in charge of offshore development activities and two Finance Directors to assist respectively in operations and construction. BOP's organization chart appears at Annex 5.2. While major policy decisions are still being taken at Dehra Dun and New Delhi, BOP has in recent years been delegated sufficient powers to be able to run the offshore program effectively and efficiently. Staffing and Training 5.06 As of April 1, 1982, ONGC had an overall staff of approximately 29,500, including 5,500 technical officers (engineers, geologists, geophysicists, etc.). ONGC gives strong emphasis to the training of personnel, particularly in its offshore operations. Personnel are given training by various institutions operating in India (management, finance, data processing, geology) and abroad (oil companies, laboratories, contractors' facilities), in addition to a wide array of courses and seminars given in- house (ranging from highly technical subjects to "organizational effectiveness" for senior staff). Particularly in the oil industry, where techniquses are evolving rapidly, courses and seminars are important to keep the staff abreast of the latest developments. Management Information Systems 5.07 ONGC has developed in recent years adequate management information systems; particularly in the case of BOP, a comprehensive monthly report is prepared, which highlights to management the status of the different activities and enables the Commission to take corrective actions whenever the need arises. During the implementation of the first two Bombay High projects, ONGC has provided the Bank, on a timely basis, quarterly technical progress reports and, on a semi-annual basis, financial and statistical reports. During negotiations, agreement was obtained that ONGC will continue to provide the Bank with periodic progress and semi-annual unaudited financial reports during project implementation, and a Project Completion Report when the Project is completed. These periodic reports are to be submitted within 45 days after the end of the period covered. Accounts and Audit 5.08 Each project unit has a Finance and Accounts Section reporting to the Project Manager and to the Member (Finance) at ONGC's headquarters. The Internal Audit Section is under the Member, Finance, in Dehra Dun, and performs satisfactorily. ONGC's accounts are audited by the Comptroller and Auditor General, which is acceptable to the Bank. While ONGC's accounts are - 42 - generally available four months after the end of the fiscal year at the latest, GOI rules and regulations provide that ONGC's audited accounts cannot be made public before they have been approved by Parliament. During negotiations, agreement was be obtained that the Commission's audited accounts will be submitted to the Bank not later than twelve months after the end of the fiscal year. Insurance 5.09 ONGC has adequate insurance coverage for its existing offshore installation, equipment, vessels, etc., with several insurance companies in India which are reinsured in the international market. Insuring follows the international practice, whereby designs are certified by independent agencies. ONGC self-insures onshore facilities, which is reasonable given the scope and extent of its onshore activites. ONGC's insurance coverage for its existing facilities is satisfactory. Under the proposed Project, agreement was reached that insurance coverage satisfactory to the Bank will be obtained for the offshore facilities included in the project scope. ONGC's Investment Program (1982/1983 - 1987/88) 5.10 ONGC is now in the third year of the 1980/81 - 1984/85 Plan. The Plan which was revised in August 1981, now provides for expenditures of approximately Rs 97 billion (US$10.8 billion) in current prices against the initial estimate of Rs 40 billion (US$4.4 billion) for the same period. This more than doubling of expenditure reflects the introduction, over the past two years, of the accelerated program for development of the Bombay High field and its neighboring structures as well as the accelerated exploration program. 5.11 The 1982/83 - 1987/88 investment program is based on ONGC's revised five-year Plan, that was submitted in August 1981, and a ten year (1980/81- 1989-90) Core Plan covering exploration and development approved in principle by the Government in July 1982; it is reviewed in detail in Annex 5.3. Proposed investments over 1982/83 - 1985/86 amount to Rs 109.6 billion (US$12.2 billion) averaging nearly Rs 27 billion (US$3 billion) per year. The proposed 1982/83 - 1985/86 investment plan can be summarized as follows: - 43 - Investment Plan 1982/83 - 1985/86 a/ Rs billion US$ billion % Exploration Offshore 18.1 2.0 17 Onshore 14.0 1.6 13 Subtotal 32.1 3.6 30 Development Offshore 60.3 6.7 54 Onshore 16.8 1.9 16 Subtotal 77.1 8.6 70 Misc. items 0.3 - - Total 109.6 12.2 100 a/ Common items have been allocated 75% to development and 25% to exploration. The Bombay High development program will account for 28%, the South Bassein development program 19% and the Krishna-Godavari exploration project 5% respectively, of the total investment program during this period. 5.12 The objective of the current investment program is to increase ONGC's production of oil from 13.1 million tons in 1981/82 to 46.5 million tons in 1989/90.1/ Meeting this objective requires a considerable exploration effort as well as maximum development and optimum operating efficiency of all known field reserves. Bombay High currently contributes over 60% of oil and gas production in India and most of the planned production increases will result from further development of this province. By 1984/85, Bombay High will have reached maximum production, and by about 1989/90 production will start declining as the reservoir is depleted. In the absence of new major discoveries, the reserves/production ratio will decline from about 24 years at present to only 15 years in 1987. This emphasizes the importance of making large new discoveries in the coming years and this is the justification for the ambitious exploration program representing about 30% of total investment over the period. 5.13 The ONGC exploration strategy is to balance the program between areas of lower risk and low potential with areas of higher risk but with greater potential for discovering large new reserves. During the 1982/83 - 1985/86 period, about half of the exploration investment will be in producing areas in Assam, Gujarat and Bombay High which in the near term hold promise of modest but more certain additions to reserves. In addition, ONGC will continue the ongoing evaluation of the Krishna-Godavari delta which is the most promising frontier area in India today and which in the medium term could contribute major additions to petroleum reserves. 1/ The Plan therefore assumes a certain rate of discovery as ONGC's current recoverable reserves can only sustain a production rate of 30 million tpy of crude oil. The investment figures above, however, do not include provisions for the development of future discoveries. - 44 - VI. FINANCIAL ASPECTS Introduction 6.01 ONGC's financial and accounting systems, while governed by GOI regulations, are gradually becoming similar to those of a commercial oil company. Key financial parameters (selling prices, investment programs) are decided upon by GOI, which also arranges all the external financing requirements of ONGC. Within this framework, ONGC operates in a financially responsible fashion. Past policies have enabled ONGC to perform satisfactorily so far, and it is expected that this will continue in the future. Past Performance 6.02 ONGC's audited Income Statements, Balance Sheets, and Sources and Applications of Funds Statements over 1978/79 - 1981/82 as well as the forecasts up to 1987/88 appear in Annex 6.1. The assumptions for the financial forecasts are in Annex 6.2. ONGC's Income Statements over the past four years can be summarized as follows: Summary of Past Income Statements Year 1978/79 1979/80 1980/81 1981/822a/ Million tons Crude oil sales: offshore 3.2 4.2 4.8 7.4 onshore 5.6 5.0 4.1 5.1 Total 8.8 9.2 8.9 12.5 Million Rs Revenues 3,799 4,280 4,501 13,810 Operating expenses 2,774 2,973 3,688 6,658 Operating income 1,025 1,307 813 7,152 Interest and taxes 300 755 477 3,599 Net Profit 725 552 336 3,553 [Dividends] b/ [181] [202] [204] [206] a/ Unaudited results. b/ At 6% of Government Equity. As the above table indicates, ONGC has experienced a steady growth in its activities, primarily because of the expanding offshore production. The results for 1980/81 are disappointing, due to the lengthy stoppage of production in Assam (equivalent to 1.3 million tons of crude oil or about Rs400 million of foregone revenues) on account of political disturbances. Production in Assam has now returned to normal. The 1981/82 results reflect both increases in oil production and selling prices (para 6.05). - 45 - 6.03 Over the 1978/79 - 1981/82 period, ONGCts investments amounted to Rs 17.6 billion (US$2.0 billion) of which Rs 9.7 billion (US$1.1 billion) or 55% was financed from internal cash generation. 6.04 The Balance Sheet, as of March 31, 1982, can be summarized as follows: Summary Balance Sheet as of March 31, 1982 Rs million US$ million % Net Fixed Assets 11,213 1,246 61 Work in Progress 5,093 566 28 Long-Term Investment 250 27 1 Current Assets 6,029 670 33 Less Current Liabilities (4,188) (465) (23) Total 18,397 2,044 100 Represented by: Equity 9,254 1,028 50 Long Term Debt 9,143 1,016 50 Total 18,397 2,044 100 As the above table indicates, ONGC is in a sound financial position with a Debt/Equity ratio of 50:50, and a current ratio of 1.2. Over the past three years, ONGC has obtained Rs 105 million (US$11.7 million) in equity contri- butions from GOI. Most of the balance of its external financing requirements was obtained from GOI in the form of long-term loans (including the IBRD Loan 1473-IN and Loan 1925-IN onlent by GOI to ONGC) and from the Oil Industry Development Board (OIDB). Its debt coverage ratio is high (7.9 in 1981/82). 6.05 The prices at which ONGC sells crude oil and natural gas to refining companies and gas consuming industries are regulated by GOI. Prices to ONGC were raised significantly in July 1981, and are currently as follows: Oil and Gas Prices (Inclusive of Taxes) Rs/ton US$/Bbl Crude Oil 1,182 17.28 Rs/1000 Nm3 US$/thousand SCF Natural Gas Offshore 500-2,500 1.49-7.44 Onshore 150-300 0.45-0.89 The price of crude oil of Rs 1,182/ton includes Rs 161/ton (US$2.35/Bbl) of cess and royalties. Pipeline tolling fees are additional. While the domestic crude oil price is low when compared to international prices, ONGC's netback (i.e. net profits after taxes and royalties) was about US$4 per barrel of oil or oil equivalent of gas in 1981/82 and is in line with the average for western international oil companies. ONGC's netback is also expected to increase to about US$5 per barrel by 1984/85 at the present level of domestic prices provided anticipated increases in oil and gas production are realized. Ultimate selling prices of petroleum products in India (para. 2.07) - 46 - are above import-parity so that the price obtained by ONGC should be considered as a transfer price within the public sector, with the difference accruing to GOI as current revenues. 6.06 The price of offshore gas is based on its intended use, whether as feedstock or as fuel, and on the domestic price of the alternative feedstock or fuel the gas is replacing. In general, the price of gas is lower when it is used as feedstock than as fuel reflecting GOI's policy of pricing oil products at a lower price when they are used as fertilizer feedstocks. It is also priced lower when substituting for cheaper fuels (e.g. coal) compared to the price when gas substitutes for more expensive fuels (e.g. fuel oil). On average, ONGC receives about Rs 1,380/1000 Nm3 (US$4.11/1000 SCF) for offshore gas, which is well above the cost of production, and in line with its economic value (fuel oil equivalent). Thus, the average level of gas prices is currently satisfactory, but the price structure may need revisions as the number and type of consumers change with expanding supplies. This issue will be carefully monitored during Project supervision. 6.07 In the case of the onshore gas in Assam, the price is low, on average only about Rs 150/1000 Nm3, reflecting the surplus of associated gas which is being flared due to the small size of the market. In the case of the onshore gas in Gujarat, where the demand for gas has already exceeded the supply, the average price of the gas (about Rs 300/1000 Nm3) is heavily influenced by the low price stipulated in old long-term contracts. As these contracts are renewed or renegotiated (which ONGC is trying to do), prices are being increased with the ultimate objective of applying the same principles as those for offshore gas. Taking into account the relatively small quantities of onshore gas, these revisions are expected to have a minimum impact on ONGC's overall finances. Financial Analysis of the Project and the South Bassein Development Program 6.08 The proposed project, as a "stand-alone" investment with a capacity of 5 MMCMD of gas, and no additional investments to raise production to 20 MMCMD (para. 4.20) has a financial rate of return of about 19% after taxes (Annex 6.3), and a payback period of about 7 years (including the construction period), assuming two-thirds of the gas will be sold as feedstock and the rest as fuel. The return is sensitive to the sales mix between feedstock and fuel because of the large differential in the financial prices of gas when used as feedstock (Rs 1.241 per cubic meter) and as fuel (Rs 2.461 per cubic meter). When all the project's gas output is sold as feedstock, then the return drops to about 14% but is still satisfactory. A 20% increase in capital cost or a one-year delay will result in a return of 16% or 17%, respectively. The South Bassein full development program (i.e. including additional investments to raise future gas production to 20 MMCMD), on the other hand, has an after-tax return of about 26% (Annex 6.4) and a payback period of about 6 years. This comparatively higher return is due to the extraction of the higher-valued gas fractions (i.e. C2/C3 and LPG) for sale, the lower unit operating cost due to economies of scale, and the full utilization of the offshore pipeline capacity. The sensitivity analyses are shown in Annex 6.5. The additional investments to fully develop the South Bassein gas field will stretch until 1987/88 and the full program is therefore not expected to generate positive cash flows until that year in spite of the high financial return. It is therefore preferable that loans with relatively long grace periods be utilized for the Project and the program to the maximum extent possible. On the other - 49 - VII. AGREEMENTS REACHED AND RECOMMENDATION 7.01 The Government confirmed the following during negotiations: (a) the arrangements for a provisional supply of gas to Hazira (para. 3.19); (b) its plans regarding gas utilization (para. 4.19); and (c) the timetable for the construction of the 6 inland fertilizer plants (para. 4.19). 7.02 During negotiations, agreement was also obtained from GOI that: (a) it will provide ONGC or cause ONGC to be provided with sufficient funds to meet ONGC's financial requirements for the Project, and onlend the Bank funds to ONGC on terms and conditions satisfactory to the Bank (paras. 3.24 and 3.25); (b) until March 1988 it will update as required, and provide to the Bank, the gas production/demand forecasts and give the Bank a reasonable opportunity to comment on it (para. 4.19); and (c) it will, from time to time, carry out a review of the prices of crude oil and natural gas to ONGC, which will determine the level of prices required to meet its operating expenses and earn a rate of return on its assets employed in operations sufficient to meet its debt-service requirements, maintain adequate working capital, and finance a substantial portion of its proposed capital investments (para. 6.09); 7.03 During negotiations, the following confirmations and agreements were obtained from ONGC: (a) it will use consultants whose qualifications, experience and terms of reference are satisfactory to the Bank to assist in design - engineering, preparation of bidding documents and supervision of construction of the project (para 3.14); (b) ONGC will take precautions in line with industry practices to protect workers and the environment during the installation and operations of the offshore project facilities (para. 3.31); (c) the LPG plant at Hazira will be commissioned by 1985/86 (para. 4.17); (d) periodic progress and financial reports will be submitted to the Bank during Project implementation (para. 5.07); (e) ONGC's audited accounts will be submitted to the Bank not later than twelve months after the end of the fiscal year (para. 5.08); (f) ONGC will obtain satisfactory insurance coverage for the offshore facilities included in the Project (para. 5.09); and - 50 - (g) ONGC will submit each year to GOI a report containing an analysis of the financial situation of ONGC including a financial evaluation of the South Bassein Project and of any subsequent developments, which will indicate the level of prices which would be required by ONGC to earn a DCF return after taxes of at least 15% for the Project and any such subsequent major developments (para. 6.08). 7.04 Execution of a subsidiary loan agreement between GOI and ONGC under terms and conditions satisfactory to the Bank would be a condition of effectiveness (para. 3.25). 7.05 On the basis of the above assurances, the Project would be suitable for a US$222.3 million loan to GOI for a term of twenty years, including a five-year grace period. Energy Department January 1983 - 51 ANNEX 1.1 INDIA PRODUCTION, TRADE AND CONSUtMPTION OP PRIMARY ENERGY Est. 1960/61 1965/66 1970/71 1975/76 1976/77 1977/78 1978/79 1979/80 1980/81 1981/82 I. PRODUCTION (a) Commercial,Primary Energy Coal (1O'rgmo) 55.7 67.7 73.0 99.7 101.0 101.0 102.0 104.0 114.0 124.7 Lignite (10 tons) - N.A. 3.4 3.0 4.0 3.6 3.2 2.9 3.0 3.0 Solid Fuels (106 toe) 27.8 N.A. 37.1 50.4 51.2 51.1 51.5 52.5 57.5 62.9 Crude Oil (106 6ono) 0.4 3.5 6.8 8.4 8.9 10.8 11.6 11.8 10.5 16.2 Natural Gas (10 toe)- N.A. N.A. 0.4 0.8 1.0 1.0 1.3 1.3 1.1 1.6 Petroleuc (106 toe)CY 0.5 R.A. 7.2 9.2 9.9 11.8 12.9 13.1 11.6 17.8 Hydro Power (109 yWh)d/ 7.8 15.2 25.2 33.3 34.8 38.0 47.2 45.5 46.5 N.A. Noclear Power (10 kWh)±/ - - 2.4 2.6 3.3 2.3 2.8 2.9. 3.0. N.A. Primary Power (106 toe)- 1.9 3.6 6.6 8.6 9.1 9.7 12.0 11.6 11.9 13.7 Total Commercial (106 toe) 30.2 N.A. 50.9 68.2 70.2 72.6 76.4 77.2 81.0 94.4 (b) Non-Co E-erclal tnergye/ Firewood,(1O6 too.) 6 99.6 109.3 117.9 133.1 N.A. N.A. N.A. N.A. N.A. N.A. Agricultural Wa te (10 tons) 30.6 33.6 36.3 41.0 N.A. N.A. N.A. N.A. N.A. N.A. Animal Dung (1O tons) 54.6 59.9 64.5 73.0 N.A. N.A. N.A. N.A. N.A. N.A. Total Non-Commercial (106 toe) 74.0 81.2 97.6 98.9 N.A. N.A. N.A. N.A. N.A. N.A. Total Production (106 toe) 104.2 N.A. 138.5 167.1 N.A. N.A. N.A. N.A. N.A. N.A. II. IMPORTS Crude Oil (106 tons) 5.7 6.8 11.7 13.6 14.0 14.5 14.7 16.1 16.2 15.4 Refined Petroleum Prodocts (106 toe) 2.4 2.7 1.1 2.4 2.8 3.0 4.1 4.8 7.5 5.9 Petroleum (or 6 toe) 8.1 9.5 12.8 16.0 16.8 17.5 18.8 20.9 23.7 21.3 Coking Coal (106 tons) N.A. N.A. N.A. N.A. N.A. N.A. N.A. 1.1 1.0 1.2 Total Imports (106 toe)c/ 8.3 N.A. 13.0 16.4 N.A. N.A. N.A. 21.7 24.3 22.5 III. EXPORTS Refined Petroleum Praductg (106 toe) 0.2 0.4 0.3 0.2 0.1 0.1 0.1 0.1 Nil 0.1 International Bunkers (10 toe) 0.6 N.A. 0.7 0.9 0.9 0.7 0.7 0.8 0.6 0.6 Coal (106 tons) N.A. N.A. 0.5 0.5 0.5 0.5 0.3 Nil 0.1 0.2 Total Exports (106 toe)-/ 0.8 N.A. 1.2 1.2 1.2 1.0 1.0 0.9 0.7 0.8 IV. APPARENT CONSUMPTION (106 toe) - Solid Fuelc/7 27.8 N.A. 37.1 50.6 N.A. N.A N.A. 53.2 58.4 63.6 PetroleumOc 7.9 N.A. 19.0 24.1 25.7 28.5 30.9 33.1 34.7 38.4 Primary Power 1.9 3.6 6.6 8.6 9.1 9.7 12.0 11.6 11.9 13.7 Sub-total Commercial 37.6 N.A. 62.7 83.3 N.A. N.A. N.A. 97.9 104.8 115.7 Non-Commercial 74.0 81.2 87.6 98.9 N.A. N.A. N.A. N.A. N.A. N.A. Total Consumption 111.6 N.A. 150.3 182.2 N.A. N.A. N.A. N.A. N.A. N.A. S Self-Sofficiency Petroleum 6 N.A. 38 38 38 41 42 40 33 46 Commercial Primary Energy 80 N.A. 81 82 N.A. N.A. N.A. 79 77 82 Total Primary Energy 93 N.A. 92 92 N.A. N.A. N.A. N.A. N.A. N.A. MEMORANDUM ITEM: Gross Power Generation (109 kWh) Generation by Utilities 26.9 33.0 55.8 79.2 88.3 91.3 102.6 104.6 110.8 122.0 Self-Generation by Industry 3.2 3.8 5.4 6.7 7.3 7.6 7.6 8.2 N.A. N.A. Total Power Generation 20.1 36.8 61.2 85.9 95.6 98.9 110.2 112.8 N.A. N.A. a/ Based on the following conversion factors: one ton of oil equivalent (toe) equals: 2 tons of domestic coal; 5.88 tons of lignite; 1.39 tons of imported coking coal; 0.94 tons of refined petroleum products and international bunkers; 1,235 cubic meters of natrual gas; 4,166 kWh of primary power; 2.04 tons of firewood; 2.33 tons of agricultural waste; and 4.54 tons of animal dung. b/ Natural gas production excludes quantities flared and used in field operations. c/ Data that is not available at present have been estimated in arriving at total figures for selected years (i.e. 1960/61, 1970/71 and 1980/81). d/ Gross power generation. e/ Non-commercial energy production figures are not available and the figures above are estimated consumption, which are taken as equal to supply. f/ Apparent consumption equals production plus imports less exports. It does not take into account changes in stock levels. Sources: Working Group on Energy Policy (1979); Indian Petroleum and Petrochemicals Statistics (1980/81and 1981/82); Annual Coal Statistics (1981); Central Electricity Authority; Economic Situation and Prospects of India (Report No. 38972-IN, March 1982); Bank staff estimates. Energy Department January 1983 - 52 - ANNEX 1.2 INDIA SECTORAL DISTRIBUTION OF ENERGY CONSUMPTION Million Tons of Oil Equiv lent YEAR/SECTOR Oii' Electricity" Coal"' Total _ 1980/81:__ Household 4.5 2.2 2.4 9.1 11.2 Agriculture 1.8 3.4 - 5.2 6.3 Industry 4.6 13.7 27.0 45.3 55.5 Transport 12.6 0.6 5.9 19.1 23.4 Others 0.4 1.9 0.6 2.9 3.6 Total 23.9 21.8 35.9 81.6 100.0 1970/71: Household 4.3 0.9 2.0 7.2 13.7 Agriculture 0.7 1.1 - 1.8 3.4 Industry .1.7 8.3 15.6 25.6 48.9 Transport 7.3 0.3 8.0 15.6 29.8 Others 1.0 1.1 0.1 2.2 4.2 Total 15.0 11.7 25.7 52.4 100.0 1960/61: Household 2.5 0.4 1.7 4.6 14.9 Agriculture 0.4 0.2 - 0.6 1.9 Industry 1.1 2.8 9.5 13.4 43.4 Transport 2.7 0.1 8.6 11.4 36.9 Others - 0.5 0.4 0.9 2.9 Total 6.7 4.0 20.2 30.9 100.0 a/ Excluding quantities used for power generation and for oil, excluding non-energy use (e.g. feedstock for fertilizers, etc.). b/ Estimated electricity consumption at the consumer level (gross power generation less internal power plant uses transmission and distribution losses). c/ Provisional. Sources: Working Group on Energy Policy (1979); Indian Petroleum and Petrochemicals Statistics (1980/81); Annual Coal Statistics (1981). Energy Department April 1982. INDIA Crude Oil Supply (Million Tons) Actual Forecast 1970/79 1979/80 1980/81 1981/82 1982/83 1983/84 1984/85 Crude Production 11.63 11.77 10.51 16.19 20.98 26.40 30.20 ONGC-Offshore 3.31 4.42 4.99 7.98 12.11 17.34 20.69 ONGC-Onshore-Gujarat 4.24 3.77 3.81 3.42 3.40 3.60 4.10 ONGC-Onshore-Assam 1.36 1.32 0.42 1.77 2.40 2.80 2.80 Oil India Limited 2.67 2.22 1.24 ) 3.02 3.07 2.66 2.61 Assam Oil Company 0.05 0.04 0.05 ) (included in figures for Oil India Ltd) Crude Imports 14.66 16.12 16.25 15.36 14.42 9.10 11.69 Crude Invent. & Ref Losses 0.32 0.42 0.88 1.41 0.60 0.70 0.80 Refinery Throughput 25.97 27.47 25.84 30.14 34.80 34.80 41.09 Product Production 24.19 25.83 24.12 28.20 32.36 32.36 38M21 Product Import (Net) 3.88 4.48 7.06 4.92 4.12 6.79 3.81 Products: Domestic Availability 28.07 30.31 31.29 33.12 36.48 39.15 42.02 Domestic Consumption 28.24 29.88 30.89 32.33 35.58 38.25 41.12 w Inventory & Losses 0.40 0.79 0.9 0.9 0.9 Imports: Crude-Volume 14.66 16.12 16.25 15.36 14.42 9.10 11.69 US$ Unit Value $/ton 104.03 167.99 261.07 284.44 290.98 325.04 359.31 US$ Value Millions 1,525.00 2,708.00 4,242.00 4,369.00 4,196.00 2,958.00 4,200.00 Products-Volume 3.88 4.72 7.25 4.92 4.12 6.79 3.81 US$ Unit Value $/ton 135.22 283.42 333.19 341.06 379.46 430.21 448.31 US$ Value Millions 525.00 1,338.00 2,416.00 1,678.00 1,563.00 2,920.00 1,706.00 POL Import: US$ MN 2,050.00 4,046.00 6,657.00 6,047.00 5,759.00 5,878.00 5,906.00 Crude Equivalent 18.79 21.14 23.96 20.06 18.80 16.32 15.74 Memo: OPEC Average price (US$/Bbl) (Calendar Year) 18.60 30.50 34.20 34.00 38.10 42.20 46.40 (Fiscal Year) 14.33 21.58 31.43 34.15 35.03 39.13 43.25 Fiscal Year Index 0.46 0.69 1.00 1.09 1.11 1.25 1.38 Source: Ministry of Petroleum, Chemicals and Fertilizers, and Bank staff estimates. Energy Department January 1983 INDIA Production and Consumption of Petroleum Products (M llion Tons) Actual Forecast 1975/76 1976/77 1977/78 1978/79 1979/80 1980/81 1981/82 1982/83 1983/84 1984/85 Production Light Distillates 3.63 3.82 4.05 4.30 4.46 4.10 5.14 5.77 5.90 7.13 LPG 0.33 0.36 0.38 0.40 0.41 0.37 0.41 0.59 0.62 0.78 Petrol 1.28 1.34 1.42 1.52 1.51 1.52 1.61 2.12 2.16 2.59 Naphtha 1.91 1.99 2.12 2.26 2.42 2.12 3.00 2.95 3.01 3.62 Others 0.11 0.13 0.13 0.12 0.12 0.09 0.12 0.12 0.12 0.14 Middle Distillates 10.77 11.23 12.08 12.48 13.08 12.12 14.14 16.67 16.87 20.15 Kerosene 2.44 2.58 2.45 2.51 2.54 2.40 2.91 3.51 3.66 4.50 Jet Fuel/Aft 0.93 0.98 1.08 1.18 1.10 1.00 1.01 1.34 1.34 1.58 High Speed Diesel 6.29 6.40 7.13 7.35 7.98 7.37 9.05 10.10 10.21 12.18 Light Diesel Oil 0.95 1.09 1.22 1.23 1.23 1.11 0.95 1.39 1.33 1.51 Others 0.16 0.18 0.20 0.21 0.23 0.24 0.22 0.32 0.32 0.38 Heavy Ends 6.43 6.38 7.09 7.42 8.26 7.91 8.92 9.93 9.59 10.93 Fuel Oil 5.08 4.73 5.33 5.65 6.35 6.12 6.95 7.55 7.21 8.12 Lube Oil 0.34 0.37 0.41 0.49 0.49 0.43 0.41 0.55 0.54 0.62 Bitumen 0.70 0.95 0.99 1.10 1.10 1.08 1.29 1.48 1.50 1.79 Others 0.31 0.33 0.36 0.32 0.32 0.28 0.27 0.35 0.33 0.39 Total 20.83 21.43 23.22 24.20 25.79 24.12 28.20 32.36 32.36 38.21 Consupt ion Light Distillates 3.60 4.04 4.23 4.57 4.46 4.38 5.14 5.20 5.68 5.93 LPG 0.34 0.37 0.39 0.41 0.41 0.40 0.49 0.65 0.46 0.85 Petrol 1.28 1.32 1.39 1.50 1.49 1.52 1.60 1.53 1.58 1.64 Naphtha 1.84 2.20 2.29 2.51 2.41 2.32 2.93 2.86 3.17 3.26 Others 0.14 0.15 0.16 0.15 0.15 0.14 0.12 0.16 0.17 0.18 Middle Distillates 11.65 12.65 13.77 15.19 16.32 17.01 17.79 19.54 21.13 23.09 Kerosene 3.10 3.32 3.63 3.96 3.87 4.21 4.70 4.52 4.82 5.22 Jet Fuel/Aft 0.90 0.96 1.04 1.15 1.14 1.13 1.12 1.33 1.46 1.62 High Speed Diesel 6.60 7.11 7.74 8.65 9.80 10.33 10.73 12.18 13.27 14.59 Light Diesel Oil 0.88 1.08 1.16 1.22 1.27 1.13 1.03 1.29 1.35 1.44 Others 0.17 0.18 0.20 0.21 0.24 0.21 0.21 0.22 0.22 0.22 Heavy Ends 7.20 7.40 7.54 8.50 9.10 9.40 9.39 10.84 11.44 12.10 Fuel Oil 5.78 5.73 5.84 6.67 7.08 7.42 7.20 8.17 8.54 8.95 Lube Oil 0.44 0.45 0.48 0.54 0.57 0.59 0.60 0.60 0.63 0.67 Bitumen 0.69 0.88 0.91 0.94 1.07 1.08 1.30 1.50 1.65 1.83 Others 0.29 0.34 0.31 0.34 0.38 0.31 0.29 0.57 0.62 0.65 ____ _ __ _ 3 Total 22.45 24.10 25.54 28.24 29.88 30.79 32.32 35.58 38.25 41.12 Source: Ministry of Petroleucm, Chemicals and Fertilizers, and Bank staff estimates. Energy Departnent January 1983 - 55 - ANNEX 3.1 Page 1 of 3 INDIA SOUTH BASSEIN OFFSHORE GAS DEVELOPMENT PROJECT Reserve Estimates and Production Projections Geology 1. The Bassein structure on which the South Bassein field is located is in an elongated asymmetrical anticline having two culminations separated by a low saddle area. This feature trends north-northwest, south-southeast, nearly parallel to the Indian shoreline some 65 km to the east. Of the two culminations, the southern one (South Bassein) is appreciably larger than the northern one (Panna or North Bassein), exhibiting a length of 33 km and a width of 10 km at the oil-water contact. On the basis of seismic and well data, the total hydrocarbon column in South Bassein is determined to be about 160 m. 2. The geological section in South Bassein consists of 2,200 m of Tertiary formations lying over the pre-Cambrian basement (Daccan trap). The upper 1,200 m are predominantly clastic, mainly shale with a few limestone beds and some fossil debris and range in age from recent to Miocene. The remaining 1,000-meter sedimentary sequence (Miocene to Eocene in age) is limestone composed of varying amounts of included clay and shale interbeds with a basal sand and coal section, about 100 m thick. The reservoir section includes the interbedded limestone and share of early Oligocene age (A Zone) and the relatively pure limestone of Upper Eocene age (B Zone). A 10-meter thick hard zones are encountered between 1,600 and 1,900 meters subsea. The thickness of the A Zone is on the order of 50 m, while that of the B Zone approaches 200 m. The porosity and permeability of the reservoirs gradually deteriorate towards the south, the facies change in the A Zone being more pronounced than in the B Zone. 3. The A and B Zones contain hydrocarbons in both the North and South Bassein areas. North Bassein (Panna) has an oil column of about 20 m in the B Zone overlain by a large gas cap which is mostly confined to the A Zone. The thickness of the oil column in the B Zone reduces rather abruptly to about 10 m in the northern part of South Bassein. South Bassein has a very large gas cap in the A and B zones. Reserves Estimates 4. The hydrocarbon reserves of the South Bassein field consit of (i) free gas, (ii) natural gas liquids (condensate), (iii) oil, and (iv) solution gas contained in the oil. Using a three-dimensional mathematical model based on reservoir data obtained from 19 wells drilled on the Bassein structure, D. R. McCord and Associates (Consultant, USA) have estimated the hydrocarbon reserves in place as follows: - 56 - ANNEX 3.1 Page 2 of 3 A Zone B Zone Total Free gas, billion Nm3 30.9 244.1 275.0 Condensate, miilion m3 4.4 35.2 39.6 Oil, million m 3.9 214.6 218.5 Solution gas 0.7 41.9 42.6 5. About 74.5% of the South Bassein free gas reserves (204.9 billion Nm3 or 6.8 tcf) along with 29.5 million m3 (185.5 million barrels) of condensate produced gas are methan (75.8%), ethan (7.22%) and propane (4.98%). Butanes and heavier hydrccardons (5.61%) and carbon dioxide (6.32%) are also present. The condensate that separates from the gas has an API gravity of 52.20 and is free 6f sulfur compounds. Although the volume of oil estimated to be present in the reservoir is substantial (218.5 million m3 or 1.374 billion Bbls), its production does not appear to be economical at this stage (para. 7). Reservoir formation and fluid properties are summarized in the table at the end of this Annex. Production Characteristics 6. Three dimensional reservoir model studies indicate that: (i) the reservoir is expected to produce by pressure depletion although partial water drive, which would be economically beneficial, cannot be ruled out; (ii) gas production from both A and B zones can be commingled in the same well without adverse effects on either well productivity or ga recovery; (iii) to prevent botton-water coning, which would reduce both well productivity and reserve recovery and increase production costs, completions in the main gas reservoir (B zone) should be distributed along the highest structural elevations in the reservoir; and (iv) with the provision of (iii) above, plateau gas production rates of 0.7-1.0 MMCM/day/well could be maintained for approximately 20 years. 7. Although ONGC's efforts in the past to produce oil from the thin oil column ocntaining relatively high transitional water saturations have been unsuccessful due to early water and/or gas encroachment, mathematical model studies indicate that concurrent production of oil and gas could be practicable from a reservoir point of view if the completion interval were confined to the oil zone. Under ideal conditions of well completi sn and siimulation, rates of gas and oil production as high as 800,000 Nm /day and 80 m /day could be expected and the final oil recovery would be on the order of 5% of the initial oil in place. However, any oil production scheme would require the handling of substantial produced water volumes and more than doubling the number of development wells. Therefore, the economic viability of producing oil from South Bassein is stilldoubtful at this stage. Nevertheless ONGC intends to drill and complete one well on each well platform in the oil zone only to investigate the feasibility of oil production in South Bassein. - 57 - ANNEX 3.1 Page 3 of 3 .INDIA SOUTH BASSEIN OFFSHORE GAS DEVELOPMENT PROJECT Reservoir Parameters A-Zone B Ze.ne Depth, m 1,600 1,650 Average Porosity, % 16.0 25.0 Permeability Range, md 5-10 100-150 Average Water Saturation, % 50 15 Initial Reservoir Pressure, kg/cm at 1720m subsea 177.9 Reservoir Temperature, OC at 1720 m subsea 120.1 Initial Gas/Oil Contact, m subsea 1,737 Initial Water/Oil Contact, m subsea 1,745 Oil Gravity, °API 40.5 Oil Viscosity, cp at initial reservoir conditions 0.34 GOR, vol/vol at initial reservoir conditions 107 Gas Specific Gravity (Air = 1.0) 0.779 Gas Viscosity, cp at initial reservoir conditions 0.0202 Water Salinity, ppm total solids 48,000 Water Viscosity, cp at initial reservoir condition 0.34 Condensate Gravity, OAPI 52.2 - 58 ANNEX 3.2 Page 1 of 5 INDIA SOUTH BASSEIN GAS DEVELOPMENT PROJECT Description of Project Facilities Process Description 1. Gas produced from the individual wells is first reduced in pressure at the wellhead to meet the required pipeline system operating conditions. The gas is then directed to the prodluction manifold on the process platform except while a well is undergoing testing, in which case the gas is directed to a separate test manifold. 2. From the production manifold the gas passes through two parallel processing trains each having a normal capacity of 5 MMCMD of gas and 7.5 MMCMD for intermittent periods. The front end of the process trains consists of a gas cooler and high pressure separator for removing entrained liquids from the gas. Gas flow from a well under test will pass from the test manifold to a test separator where the pressure, liquid and gas quantities and other parameters are measured. The test separator gas joins the main gas stream from the high pressure separators. Next the gas passes on to two parallel dehydration units where water is removed from the gas by contact with triethylene glycol (TEG). The dehydrated gas from both trains (less than 112 kg per MMCM under contract) is recombined, metered and introduced into the Hazira pipeline either by itself or in company with any spare Bombay High associated gas also being shipped to Gujarat. Compression facilities are included to enable the delivery of 5 MMCMD of Bombay High associated gas to the Hazira terminal. In place of shipping Bombay High gas to Gujarat it is also possible to deliver South Bassein gas to the Uran terminal via the 26" trunkline from Bombay High. 3. Liquids leaving the high pressure gas separator are passed to the condensate processing equipment where produced water and condensate are separated. Dewatered condensate is further processed through a filter coalescer to remove any residual water. The condensate is stabilized to the desired vapor pressure by a two stage separation of gas and liquid hydrocarbon. Gas evolved during stabilization is recompressed and combined with the gas leaving the high pressure separators. Stabilized condensate is normally injected into the Bombay High 30" crude line. Offshore Platform Complex Location 4. The offshore platform comp:Lex will be located near well SB-7 at approximately latitude 190-11 north and longitude 720-7' east. The process platform will be set with its long axis running north-south. This same axis will locate the drilling platform approximately 35 m to the north of the process platform. The flare platform will be set on an east-west axis 95 m directly to the east of the process platform. The accommodation platform will A' NN --_ - 59 ~ Page 2 of 5 be set on a north-south axis but offset to the west of the process and drilling platform axis such that its northeast corner will be approximately 35 m from the southwest corner of the process platform measured in a northeast-southwest direction. Bridges, for personnel access and to support piping, cables and other services, will interconnect the four platforms. Drilling Platform 5. The drilling platform is designed to accommodate a cantilever type jack-up drilling rig. If consists of a jacket and piling for four major support legs and a superstructure comprising a cellar and a drilling deck. The major facilities provided on the platform are a well head control panel with automatic and manual shutdown systems, fire and gas detection and alarms, communications, materials and equipment lifting and handling, fire water deluge and dry chemical fire fighting, corrosion prevention and other utilities. Process Platform 6. The process platform consists of a steel jacket and piling for eight major support legs and a superstructure comprising cellar and upper decks. The main facilities and equipment are: - The process and compression facilities described in para. 2. - High and low pressure flare systems. - Gas turbine generator sets and one diesel driven standby generator, all housed in a separate building together with switchgear, motor control center and transformers. - A process control and RTU/computer center also housed in the same building as the electrical equipment. - A helideck atop the electrical/control building. - Electrical lighting, emergency lighting systems and uninterrupted power supply system. - Navigation aids. - Life rafts, jackets, life rings and survival craft. - Personnel safety and first aid equipment including safety showers and eyewashers in the chemicals handling areas. - Service water pumps and distribution system. - A hypochlorite generator and distribution system using seawater. - A closed loop process cooling system. - 60 - ANNEX 3.2 Page 3 of 5 - Diesel fuel system with storage in the crane pedestal(s) including fill lines at the boat landing. - Instrument and service air compressor and dryer package together with a distribution system. - Fuel gas system. - Fire and gas detection, alarm and suppression systems. - Chemicals and lubricants storage and drum handling system incuding dilution and mixing facilities as required. - Corrosion monitoring system. - Electrical/instrument workshop completely equipped for the repair and testing of electrical equipment and instruments. - Machine shop complete with universal lathe, drill press, sharpening attachments, bench grinder, bench vise, welding machine, etc. - Chemistry laboratory eq[uipped with necessary testing and analytical equipment. - Valve repair shop. - Storage building. Accommodation Platform 7. The accommodation platform consists of a steel jacket and piling for four major support legs and a superstructure comprising a celler deck and supporting beams for the self-contained accommodation module and helideck. Major equipment and facilities include: - Monorails and other materials handling equipment to handle major components, consumable supplies, drums and other items with a high frequency of repair and operational requirements such as pumps and motors. - Galley and dining areas. - Freezer, refrigerator and food storage areas with two weeks capacity. - Recreation rooms. - One-man, two-man and four-man bedrooms. - Bathrooms with showers, toilets, wash basins and urinals. - Offices and communication rooms. - 61 - ANNEX 3.2 Page 4 of 5 An infirmary and hospital. Telephone exchange room. Air conditioning, heating and ventiliation equipment and distributioh system. A 10-ton crane. Two potable water makers, each with the capacity to produce 70 gallons per day per man or 8,750 gallons per day. Potable water storage for 42,000 gallons in two tanks. Two 100 percent capacity sewage treatment units. A diesel driven firewater pump firewater system, hose reels and chemical extinguishers. Disposal caisson and sump pump. Normal lighting and emergency lighting systems. Switchgear room. Navigation aids. Environmental panel and equipment. Helicopter fuel storage tanks, pumps, filters, meters and refueling hose. The tanks, pumps and ancillary equipment will be located beneath the helideck. - Firewater system, fire extinguishers, a safety shower and eyewashers. - Fire and gas detection, alarm and suppression systems. - Unloading lines at both boat landings for potable water and helicopter fuel. - Service water pump and distribution system. - Radio communications equipment. - Survival craft, life rafts, life rings and other life saving appliances. South Bassein-Hazira Pipeline 8. The pipeline will have an outside diameter of 36", and it will be fabricated by the submerged arc welding process from API5L - Grade X60 steel having a thickness of 28.6 mm. The pipeline will be buried throughout its entire length to a depth which will provide three or more meters of cover for - 62 - ANNEX 3.2 Page 5 of 5 the offshore and river crossing portions and one meter cover for the land portion. For corrosion protection the pipe is given a 4 mm thick protective coating consisting of successive layers of a coal tar enamel primer coat applied to the cleaned pipe surface, a coat of coal tar enamel, a glass matte, another coal tar enamel coat and an outer glass fiber wrap. Stability to withstand currents and other forces on pipe laid in water will be provided by a 10 cm or so thick oating of a very dense concrete having a density of at least 3.04 kg per dm (190 lbs per cu ft, roughly 50% greater than ordinary cement). Buoyancy stabilization in marshy areas will be obtained by ordinary concrete weighting. The pipeline will be cathodically protected by zinc sacrificial anodes where exposed to water and by an impressed current on land. Hazira Terminal 9. The gas and entrained hydrocarbon liquids which have condensed due to cooling in the pipeline arrive at a receiver trap in the terminal. The gas then passes through two parallel scrubbers and filters which remove all entrained liquids before it is metered and delivered to the fertilizer plant and other subsequent customers. The liquid is caught in a slug catcher consisting of about 135 m of 36" pipe designed in such a manner as to dissipate the kinetic energy of the liquid and to provide hold-up for the estimated 190 m per hour flow rate at maximum design throughput. To produce a condensate that can be safely handled, stored and transported, the liquid is stabilized to a Reid vapor pressure of 10 psi in a distillation column. The light ends which are stripped off are recompressed and returned to the gas stream. Storage and shipping facilites for the stabilized condensate are included in the terminal facilities. INDIA SOUTH BASSEIN OFFSHORE GAS DEVELOPMENT PROJECT Implementation Schedule 1982 1983 1984 [ 1985 T NDaI Tc W X X X I TIA| I IJ!AI Sl | ID eW Prcrment Fabrcto Inst*llation CENTRAL PLATFORM COMPLEX (Turnkey Contract) _om F m Drilling DRILLING 6WELLS SOUTH BASSEIN-HAZIRA AND CONNECTING PIPELINES: Line Pipe Procurement 8 CD Protective Coating Other Procurement Design andI TD 8 C Offshore Pipelaying Contract En g i Deign and Engineering T 8 C Construction Onshore Pipelaying Contract _____ _ _ Pipeline Testing and Commissioning _. TERMINAL FACILITIES: Design and Engineering t Materials and Equipment Design and Engineering CI o riontruction Civil Works - I - Denign and Engineering rC Constr ction Mechanical Works . _ - Testing and Commissioning Source - ONGC t Tender Documents Issued B v Bids Due 4' Contract Award or Purchase Order Date D _' Material and Equipment Delivery Energy Department January 1983 World Bank-24099 INDIA SOUTH BASSEIN OFFSHORE GAS DEVELOPMENT PROJECT DETAILED COST ESTIMATE COST IN MILLION RUPEES COST IN MILLION US DOLLARS LOCAL FOREIGN TOTAL LOCAL FOREIGN TOTAL A. PROCESSING COMPLEX Central Production Complex -- 1,250.10 1,250.10 -- 118.90 118.90 Platform Installation -- 180.00 180.00 -- 20.00 20.00 Drilling Wells 67.95 67.95 135.90 7.55 7.55 15.10 South Bassein-Bombay High Pipeline -- 272.07 272.07 -- 30.23 30.23 B. SOUTH BASSEIN-UMRAT PIPELINE Pipe Materials -- 1,334.70 1,334.70 -- 148.30 148.30 Pipelines Laying - 1,215.00 1,215.00 -- 135.00 135.00 Umrat-Hazira Onshore Pipeline 86.40 89.10 175.50 9.60 9.90 19.50 C. OTHER FACILITIES Hazira Terminal 44.55 14.85 59.40 4.95 1.65 6.60 Condensate Stabilization Unit 9.54 9.45 18.99 1.06 1.05 2.11 Telecontrol & Telecommunications 16.29 9.00 25.29 1.81 1.00 2.81 1 Land (Including Development) 36.00 -- 36.00 4.00 -- 4.00 D. ENGINEERING AND SUPERVISION 207.45 90.54 297.99 23.05 10.06 33.11 E. RESERVOIR CONSULTANCY -- 126.90 126.90 -- 14.10 14.10 F. CUSTOM DUTIES 280.35 -- 280.35 31.15 -- 31.15 Base Cost (Jan. 1983 Prices) 748.53 4,479.66 5,228.19 83.17 497.74 580.91 Physical Contingencies 74.86 447.93 522.79 8.32 49.77 58.09 Price Contingencies 66.29 466.74 533.03 7.37 51.86 59.23 Subtotal 141.15 914.67 1,055.82 15.69 101.63 117.32 FRONT END FEE -- 29.70 29.70 -- 3.30 3.30 TOTAL 889.68 5,424.03 6,313.71 98.86 602.67 701.53 ENERGY DEPARTMENT January 1983 - 65 - ANNEX 3.5 INDIA SOUTH BASSEIN OFFSHORE GAS DEVELOPMENT PROJECT I PHASING OF EXPENDITURES LOCAL AND FOREIGN CURRENCY PORTION IN MILLION RUPEES 1983/1984 1984/1985 1985/1986 TOTAL A. PROCESSING COMPLEX CENTRAL PRODUCTION COMPLEX 390.60 745.20 114.30 1,250.10 PLATFORM INSTALLATION - - - - DRILLING WELLS - 67.95 67.95 135.90 SOUTH BASSEIN-BOMBAY HIGH PIPELINE - 204.12 67.95 272.07 B. SOUTH BASSEIN-UMRAT PIPELINE PIPE MATERIALS 1,019.70 180.00 - 1,199.70 PIPELINES LAYING 1,012.50 337.50 - 1,350.00 UHRAT-HAZIRA ONSHORE PIPELINE 131.40 44.10 - 175.50 C. HAZIRA TERMINAL FACILITIES 94.50 45.18 - 139.68 CONDENSATE STABILIZATION UNIT - - - - TELECONTROL I TELECOMMUNICATION - - - LAND (INCLUDING DEVELOPMENT) - - - - D. ENGINEERING AND SUPERVISION 108.00 117.00 72.99 297.99 E. RESERVOIR CONSULTANCY - 126.90 - 126.90 F. CUSTOM DUTIES 280.35 - - 280.35 SUBTOTAL 3.037.05 1,867.95 323.19 5,228.19 PHYSICAL CONTINGENCIES( 303.71 186.77 32.31 522.79 PRICE CONTINGENCIES 172.76 284.48 75.79 533.03 SUBTOTAL 476.47 471.25 108.10 1,055.82 FRONT END FEE 29.70 - - 29.70 TOTAL 3,543.22 2,339.20 431.29 6,313.71 ENERGY DEPARTMENT PETROLEUM PROJECTS DIVISION 1 - 66- ANNEX 3.6 INDIA SOUTH BASSEIN GAS DEVELOPMENT PROJECT Estimated Schedule of Disbursement IBRD Fiscal Year Cumulative Disbursement and Quarter at end of Quarter (US$ Million) 1983/84 September 30, 1983 16.3 December 31, 1983 69.3 March 31, 1984 134.3 June 30, 1984 173.3 1984/85 September 30, 1984 179.3 December 31, 1984 203.3 March 31, 1985 222.3 Source: Mission Estimate January 1983 INDIA SOUTH BASSEIN GAS DEVELOPMENT PROJECT Lean Gas Demand for Feedstock In Million Cubic Meters Per Day (MMCMD) Sub-total Gujarat and Inland States Gujarat Maharastra Sub-total Total Year Hazira MP-I Rajasthan-I UP-I & II UP-III & IV Others & Inland RCF-Trombay a RCF IFPCL hOC & BEL a! Others Maharashtra Peedstock 1982/83 - - - - - 1.65 0.28 0.25 0.16 - 2.34 2.34 1983/84 - - - - - - - 1.65 0.53 0.25 0.15 - 4.87 2.58 1984/85 1.60 - - - - - 1.60 1.65 2.80 0.30 0.18 - 4.93 6.53 1985/86 3.00 - - - - - 3.00 1.65 3.00 0.30 0.21 - 5.16 8.16 1986/87 3.00 0.25 0.25 - - - 3.50 1.65 3.00 0.30 0.36 - 5.31 8.81 1987/88 3.00 1.20 1.20 0.50 - - 5.90 1.65 3.00 0.30 0.36 - 5.31 11.21 1988/89 3.00 1.50 1.50 2.40 0.50 - 8.90 1.65 3.00 0.30 0.36 - 5.31 14.21 1989/90 3.00 1.50 1.50 3.00 2.40 - 11.40 1.65 3.00 0.30 0.36 - 5.31 16.71 1990/91 3.00 1.50 1.50 3.00 3.00 - 12.00 1.65 3.00 0.30 0.36 - 5.31 17.31 1991/92 3.00 1.50 1.50 3.00 3.00 - 12.00 1.65 3.00 0.30 0.36 - 5.31 17.31 1992/93 3.00 1.50 1.50 3.00 3.00 - 12.00 1.65 3.00 0.30 0.36 - 5.31 17.31 1993/94 3.00 1.50 1.50 3.00 3.00 - 12.00 1.65 3.00 0.30 0.36 - 5.31 17.31 1994/95 3.00 1.50 1.50 3.00 3.00 - 12.00 1.65 3.00 0.30 0.36 - 5.31 17.31 1995/96 3.00 1.50 1.50 3.00 3.00 - 12.00 1.65 3.00 0.30 0.36 - 5.31 17.31 1996/97 3.00 1.50 1.50 3.00 3.00 - 12.00 1.65 3.00 0.30 0.36 - 5.31 17.31 1997/98 3.00 1.50 1.50 3.00 3.00 - 12.00 1.65 3.00 0.30 0.36 - 5.31 17.31 1998/99 3.00 1.50 1.50 3.00 3.00 - 12.00 1.65 3.00 0.30 0.36 - 5.31 17.31 1999/2000 3.00 1.50 1.50 3.00 3.00 - 12.00 1.65 3.00 0.30 0.36 - 5.31 17.31 a/ Lean gas to replace present naphtha feedstock. Sourcet Ministry of Petroleum; ONGC. 0.l§ Energy Department December 1982 INDIA SOUTH BASSEIN GAS DEVELOPMENT PROJECT Lean Gas Demand for Hydrocarbon Replacement In Million Cubic Meters Per Day (MMCMD) GUJARAT MAHARASTR.A Gujarat Koyali Ultran Gas Sub-total Bombay RCF BPCL/HRCL Petchem Sub-total Year Gas Grid a/ Refinery b/ Turbine Others Gujurat City a Trombay b/ Refineries b agothana a/ MSEB b/ Others Maharastra Total 1982/83 - - - - - _ 0.68 0.20 - 1.80 - 2.68 2.68 1983/84 - - - - - _ 0.68 0.40 - 1.80 - 2.88 2.88 1984/85 0.5 - 0.35 - 0.85 0.40 0.68 0.40 - 1.80 - 3.28 4.13 1985/86 1.0 0.50 0.35 - 1.85 1.00 0.68 0.40 - 3.60 - 5.68 7.53 1986/87 1.5 0.50 0.35 - 2.35 2.00 0.68 0.40 - 3.60 - 6.68 9.03 1987/88 1.5 0.50 0.35 - 2.35 2.00 0.68 0.40 - 3.60 - 6.68 9.03 1988/89 1.5 0.50 0.35 - 2.35 2.00 0.68 0.40 - 3.60 - 6.68 9.03 1989/90 1.5 0.50 0.35 - 2.35 2.00 0.68 0.40 0.50 3.60 - 7.18 9.53 1990/91 1.5 0.50 0.35 - 2.35 2.00 0.68 0.40 0.50 3.60 - 7.18 9.53 1991/92 1.5 0.50 0.35 - 2.35 2.00 0.68 0.40 0.50 3.60 - 7.18 9.53 1992/93 1.5 0.50 0.35 - 2.35 2.00 0.68 0.40 0.50 3.60 - 7.18 9.53 1993/94 1.5 0.50 0.35 - 2.35 2.00 0.68 0.40 0.50 3.60 - 7.18 9.53 1 1994/95 1.5 0.50 0.35 - 2.35 2.00 0.68 0.40 0.50 3.60 - 7.18 9.53 1995/96 1.5 0.50 0.35 - 2.35 2.00 0.68 0.40 0.50 3.60 _ 7.18 9.53 1996/97 1.5 0.50 0.35 - 2.35 2.00 0.68 0.40 0.50 3.60 - 7.18 9.53 1997/98 1.5 0.50 0.35 - 2.35 2.00 0.68 0.40 0.50 3.60 - 7.18 9.53 1998/99 1.5 0.50 0.35 - 2.35 2.00 0.68 0.40 0.50 3.60 - 7.18 9.53 1999/2000 1.5 0.50 0.35 - 2.35 2.00 0.68 0.40 0.50 3.60 - 7.18 9.53 a/ The liquid hydrocarbons being replaced are LPG, Kerosene, and fuel oil. b/ Low Sulphur Heavy Stock (LSHS) replacement. This has a lower priority than the other liquid hydrocarbon replacement in case of gas supply constraints. NOTE: In addition to the substitution possibilities listed above, there are several enterprises near the proposed inland pipeline route who are presently using liquid hydrocarbons that can be replaced by lean gas. The additional subsitution will involve naphtha (1.5 million tons per year equivalent to 3.1 million cubic meters/day of lean gas) as well as fuel oil and LSHS (0.6 million tons per year equivalent to 1.9 million cubic meters/day of lean gas). The enterprises are located in Barauch (GNFC), Baroda (GSFC and IPCL), Kota (SFC), Kampur (IEL) and Gorakhpur (FCI). Source: Ministry of Petroleum; ONGC. e. Energy Department December 1982 INDIA SOUTH BASSEIN GAS DEVELOPMENT PROJECT Lean Gas Demand for Selected Coal Replacement In Million Cubic Meters Per Day (MMCMD) Gujarat and Inland States Maharastra Hazira Boilers & RCF-Thal Boilers New Plants Others Sub-total TEC Boilers Others Sub-total Total 1982/83 3 - - - 3.00 0.53 - 3.53 3.53 1983/84 - - - 3.00 1.06 - 4.06 4.06 1984/85 - - - - 3.00 1.06 - 4.06 4.06 1985/86 0.53 - - 0.53 3.00 1.06 - 4.06 4.59 1986/87 1.06 0.50 - 1.56 3.00 1.06 - 4.06 5.62 1987/88 1.06 1.00 - 2.06 3.00 1.06 - 4.06 6.12 a, 1988/89 1.06 1.50 - 2.56 3.00 1.06 - 4.06 6.62 1989/90 1.06 2.50 - 3.56 3.00 1.06 - 4.06 7.62 1990/91 1.06 3.00 - 4.06 3.00 1.06 - 4.06 8.12 1991/92 1.06 3.00 - 4.06 3.00 1.06 - 4.06 8.12 1992/93 1.06 3.00 - 4.06 3.00 1.06 - 4.06 8.12 1993/94 1.06 3.00 - 4.06 3.00 1.06 - 4.06 8.12 1994/95 1.06 3.00 - 4.06 3.00 1.06 - 4.06 8.12 1995/96 1.06 3.00 - 4.06 3.00 1.06 - 4.06 8.12 1996/97 1.06 3.00 - 4.06 3.00 1.06 - 4.06 8.12 1997/98 1.06 3.00 - 4.06 3.00 1.06 - 4.06 8.12 1998/99 1.06 3.00 - 4.06 3.00 1.06 - 4.06 8.12 1999/2000 1.06 3.00 - 4.06 3.00 1.06 - 4.06 8.12 Source: Ministry of Petroleum; ONGC Energy Department December 1982 INDIA SOUTH BASSEIN OFFSHORE GAS DEVELOPMENT PROJECT BOMBAY HIGH AND SATELLITES GAS PRODUCTION In Million Cubic Meters Per Day (MMCMD) BOMBAY HIGH AND SATELLITES S H R I N K A G E CRUDE RICH RICH LEAN GAS OIL GAS PLATFORM GAS NGL LPG C2/C3 FUEL/C02 AVAILABLE YEAR MMTPY PRODUCTION USE EX-PLATFORM (A) (B) (C) (D) (E) 1982/83 12.11 5.49 0.60 4.89 0.03 0.22 -- 0.15 4.49 1983/84 17.35 7.89 0.90 6.99 0.04 0.22 -- 0.22 6.51 1984/85 20.68 10.33 1.50 8.83 0.05 0.44 -- 0.47 7.87 1985/86 19.23 9.50 1.80 7.70 0.04 0.42 -- 0.46 6.78 1986/87 19.10 9.91 1.80 8.11 0.04 0.44 -- 0.49 7.14 1987/88 18.95 10.09 1.80 8.29 0.04 0.44 -- 0.51 7.30 1988/89 18.73 11.15 1.80 9.35 0.05 0.44 0.69 1.13 7.04 1989/90 18.53 11.05 1.80 9.25 0.05 0.44 0.97 1.07 6.72 1990/91 16.68 10.86 1.80 9.06 0.05 0.44 0.95 1.18 6.44 1991/92 14.91 9.58 1.80 7.78 0.04 0.42 0.81 0.98 5.53 1992/93 13.23 8.66 1.80 6.86 0.04 0.37 0.72 0.85 4.88 1993/94 11.84 7.66 1.80 5.86 0.03 0.32 0.61 0.73 4.17 1994/95 10.51 6.82 1.80 5.02 0.03 0.27 0.52 0.63 3.57 1995/96 9.14 5.86 1.80 4.06 0.02 0.22 0.42 0.51 2.89 1996/97 8.16 5.25 1.80 3.45 0.02 0.19 0.36 0.43 2.45 1997/98 7.29 4.70 1.80 2.90 0.02 0.16 0.30 0.36 2.06 1998/99 6.53 4.22 1.80 2.42 0.01 0.13 0.25 0.31 1.72 1999/2000 5.90 3.82 1.80 2.02 0.01 0.11 0.21 0.25 1.44 NOTE: (A) 0.53% of rich gas (B) 5.45% of rich gas. Capacity limit of Uran plant -- 4.0 MMCMD rich gas up to 1983/84 and 8.0 for 1984/85 onwards. (C) 10.47% of rich gas. Capacity utilization 60% in 1988/89, 85% in 1989/90, and 100% thereafter; C2/C3 extraction capacity is 11 MMCMD of rich gas (330 operating days per year). (D) C02 recovered at the C2/C3 plant. (E) Until 1983/84 the associated gas processing and compression facilities will have a capacity of only about 4.5 MMCMD and some gas will be flared until that time. By X 1984/85, the capacity will be increased to about 9.5 MMCMD. X 0~ Petroleum Projects Dept. December 1982 INDIA SOUTH BASSEIN GAS DEVELOPMENT PROJECT South Bassein Production Forecast Million Cubic Meters per Day (MMCMD) Total Extracted Fractions Rich Gas Platform Rich Gas Ex-Platform NGL NGL in LPG and C2/C3 Plantsd/ Lean Gas Lean Gas Uses Year Production Use a/ Phase I Phase II Total EN-Platformb/ Ex-Pipelinec/ NGL LPG C2/C3 C02 Sub-Total Available Internal FuelSC For Sale 1984/85 - - -- -- -- -- -- -- -- - _ __ 1985/86 6.80 0.20 4.10 2.50 6.60 0.204 0.097 0.050 0.303 -- -- 0.353 6.247 0.264 5.983 1986/87 10.20 0.20 5.00 5.00 10.00 0.305 0.147 0.076 0.459 -- -- 0.535 9.465 0.400 9.065 1987/88 14.59 0.20 5.00 9.39 14.39 0.437 0.212 0.109 0.661 -- -- 0.770 13.620 0.576 13.044 1988/89 20.49 0.65 5.00 14.84 19.84 0.614 0.292 0.151 0.911 0.102 0.325 1.489 18.351 1.094 17.257 1989/90 20.65 0.65 5.00 15.00 20.00 0.618 0.294 0.152 0.918 0.163 0.325 1.558 18.442 1.100 17.342 1990/91 20.90 0.65 5.00 15-00 20.00 0.626 0.294 0.152 0.918 0.244 0.325 1.639 18.361 1.100 17.261 1991/92 20.90 0.90 5.00 15.00 20.00 0.626 0.294 0.152 0.918 0.325 0.325 1.720 18.280 1.100 17.180 1992/93 21.30 0.90 5.00 15.00 20.00 0.626 0.294 0.152 0.918 0.407 0.325 1.802 18.198 1.100 17.098 1993/94 21.80 1.30 5.00 15.00 20.00 0.638 0.294 0.152 0.918 0.407 0.325 1.802 18.198 1.100 17.098 1994/95 21.80 1.80 5.00 15.00 20.00 0.653 0.294 0.152 0.918 0.407 0.325 1.802 18.198 1.100 17.098 1995/96 21.80 1.80 5.00 15.00 20.00 0.653 0.294 0.152 0.918 0.712 1.298 3.080 16.920 2.000 14.920 1996/97 21.80 1.80 5.00 15.00 20.00 0.653 0.294 0.152 0.918 0.895 1.298 3.263 16.737 2.000 14.737 1997/98 21.80 1.80 5.00 15.00 20.00 0.653 0.294 0.152 0.918 1.139 1.298 3.507 16.493 2.000 14.493 1998/99 21.70 1.70 5.00 15.00 20.00 0.650 0.294 0.152 0.918 1.383 1.298 3.751 16.249 2.000 14.249 1999/2000 21.60 1.60 5.00 15.00 20.00 0.647 0.294 0.152 0.918 1.627 1.298 3.995 16.002 2.000 14.005 a/ Platform fuel consumption (for process units, utilities and compressors). Rich gas production and transmission is on the basis of 365 operating days per year. NGL condensate recovered at the platform at the rate of 29,949 cubic meters per million cubic meters of total rich gas production (ex-wellhead). NGL condensate in the offshore pipeline recovered at the Hazira terminal at a rate of 14,702 cubic meters per million cubic meters of rich gas ex-platform. d/ Four LPG plants (with a each processing capacity of 5 MMCMD of rich gas) are scheduled to start production each year from 1985/86 through 1988/89, respectively. The first C2/C3 recovery plant will have a capacity of 5 MMCMD of rich gas and will start operating in 1988/89. The second C2/C3 recovery plant will have a capacity of 15 MMCMD of rich gas and start operating in 1995/96. The capacity utilization build-uip of the C2/C3 plants are as follows: first year -- 25%, second year -- 40%, third year -- 60X, fourth year -- OOX, R fifth year -- 100%. Both LPG plants and C2/C3 plants operate on the basis of 330 stream days per year. The maximum extractable fractions as a percentage of the rich gas (%x- platform) volume is as follows: NGL -- 0.76%, LPG -- 4.53%, C2/C3 -- 8.13% and CO2 -- 6.49% (recovered in C2/C3 plant). To convert to weight basis use for NGL -- 291.7 Nm Iton, "'M LPG -- 446.7 Nm /ton, C2/C3 -- 671 Nm3/ton, CO2 -- 509 Nm /ton, internal fuel used -- 1,380.2 Nm /ton. e/ Internal fuel consumption at the Hazira terminal, LPG and C2/C3 recovery plants as well as the inland pipeland compressor stations. Energy Department December 1982 INDIA SOUTH BASSEIN GAS DEVELOPMENT PROJECT Annual Production and Sales Mix of Project and of Full Development Program PROJECT ONLYA/ FULL DEVELOPMENT PROGRAM In 1,000 Tons In 1,000 Tons In Million Cubic Meters In Million _ __- NGL NGL Total Cubic Metev/ NGL NGL NGL Ex- Total Lean Gas Lean Gas Year Ex-Platform Ex-Pipeline NGL Rich Gas - Ex-Platform Ex-Pipeline LPG Plant NGL LPG C2/C3 As Fuel As Feedstock 1984/85 1985/86 157.39 75.42 232.81 1,496.50 255.26 121.37 56.56 433.19 247.58 -- 1,680.10 503.70 1986/87 191.12 91.98 283.10 1,825.00 381.64 183-94 95.10 660.68 375.05 -- 2,699.17 609.55 1987/88 191.12 91.98 283.10 1,825.00 546.76 264.72 123.31 934.79 488.29 -- 3,333.91 1,427.25 1988/89 194.87 91.98 286.85 1825.00 767e86 364.97 170.82 1,303.65 672.96 33.66 3,681.75 2,617.05 1989/90 194.87 91.98 286.85 1,825.00 773.86 367.92 171.95 1,313.73 678.14 53.79 2,683.48 3,646.35 1990/91 194.97 91.98 286.85 1,825.00 773-86 367.92 171.95 1,313.73 678.14 80.52 2,332.71 3,967.55 1991/92 196.75 91.98 288.73 1,825.00 783.23 367.92 171.95 1,323.10 678.14 107.25 1,971.00 4,299.70 1992/93 196.75 91.98 288.73 1,825.00 783.23 367.92 171.95 1,323.10 678.14 134.31 1,703.82 4,536.95 1993/94 198.62 91.98 290.60 1,825.00 798.22 367.92 171.95 1,338.09 678.14 134.31 1,444.67 4,796.10 1994/95 202.36 91.98 294.34 1,825.00 816.92 367.92 171.95 1,356.83 678.14 134.31 1,225.67 5,015.10 1995/96 202.36 91.98 294.34 1,825.00 816.96 367.92 171.95 1,356.83 678.14 234.96 182.50 5,263.30 1996/97 202.36 91.98 294.34 1,825.00 816.96 367.92 171.95 1,356.83 678.14 295.35 -- 5,379.00 1997/98 202.36 91.98 294.34 1,825.00 816.96 367.92 171.95 1,356.83 678.14 375.87 __ 5,289.94 1998/99 202.36 91.98 294.34 1,825.00 813.21 367.92 171.95 1,353.08 678.14 456.39 __ 5,200.88 1999/2000 202.36 91.98 294.34 1,825.00 809.46 367.92 171.95 1,349.37 678.14 536.91 -- 5,111.82 a/ In the case of the Project only, no LPG or C2/C3 are considered to be extracted since the extraction plants are not included in the Project scope. Thus, the entire rich gas produiction (ex-platform) is considered as the product sold by the Project. X b/ Two-thirds of the rich gas is sold as feedstock and one-third as liquid hydrocarbon substitute (e.g., fuel oil substitute) in the Base Case financial rate of o returni analysis of the Project. Energy Department December 1982 - 73 - ANNEX 4.3 Page 1 of 3 INDIA SOUTH BASSEIN GAS OFFSHORE DEVELOPMENT PROJECT Economic Rate of Return -- Assumptions I. Capital Cost 1. The capital cost of the Project is based on the Appraisal estimate excluding custom duties, taxes and price contingencies. As a producticn platform has a capacity of 5 MMCMD, a process platform of 10 MMCMD, and an LPG plant of 5 MMCMD, additional provisions were made for future investments, in the above, as the demand for gas develops, based on the following end-1982 prices: US$ Million Three Production Platforms (with a total of 18 wells) 135 One Process Platform (with flare) 75 Four LPG Plants (including the one to be completed in 1985/86) 300 Two C2/C3 extraction plants1/ 245 Furthermore, the Hazira-UP 1,000 km pipeline, which will bring the gas to the six future fertilizer plants, was incorporated in the investment program over 1985/86 - 1987/88, with a capital cost of US$700 million (economic cost; for the financial cost, add US$160 million for import duties and taxes) in end- 1982 prices (including 3 compressor stations, pressure reducing stations and telemetry/telecontrol). II. Operating Cost 2. The operating costs were taken to be 8% of the investment cost in operating assets plus variable costs of US$20 per 1,000 Nm3 of rich gas produced (ex-platform). a. Unit Values 3. A separate value was given to each fraction of the gas of the basis of its opportunity cost. In the case of the lean gas (Cl fraction or methane), the netback value was calculated for feedstock use; for other uses, the replacement value was calculated on the basis of calorific equivalence. All prices were kept constant at their base values (para 6) for the base case but a sensitivity analysis, assuming real term increases in energy prices during the next 20 years, has also been performed. These real term price increases are based on the following trend for oil and coal (expressed in 1981 prices): 1981 1982 1983 1985 1990 1995 Oil (US$/Bbl) 34.3 32.0 31.0 32.0 37.0 41.0 Coal (US$/ton) 55 53 52 51 55 59 - 74 - ANNEX 4.3 Page 2 of 3 4. The value of natural gas liquids (NGL) was take:> -o be the f.o.b. price of naphtha.l/ as India currently produces an excess of gasoline, which is blended with naphtha. Naphtha is exported, although i- small qua?tities, at present. The LPG value is based on the coi.f. orice c- L-erosene . The C2/C3 fraction should be based on the netback value of ga2 :or petrochemicals. A conser7vative ebstimate was made at US$5 _5/1,000 SCF. 5. With regard to the Cl fraction, different valu2s -.ere assigned, depending on the end-useO When lea. gas is used as feeds.-ck-, the netback for fertilizer production was taken as the measure of benefits D The netback value was taken to be the one for which the econcmic rate of reL>rn of a fertilizer project in India would reach 12%, the opportunity cost olf capital. The calculation was made on the basis of the next fertilizer cliant scheduled to be built, using the actual capital costs of the Hazira fertizer complex as a base for estimating the costs. 6. When the lean gas is used for hydrocarbon replase-ent, it essential y replaces fuel oil. Therefore, the value oL g2s was taken to be fuel oili' equivalence, after adjusting for the calorific -values. When lean gas is used to replace coa}, calorific equivalence was calculated to obtain the value of natural gas._ The cost of gas for various a.plications is, therefore, as follows: End-Kl ,2 Prices US$/l,000 US$ 1,000 SCF NGL (US' per ton) 300 -- LPG (US$ per ton) 408 -- C2/C3 200 5.35 Cl-Hydrocarbor. Replacenment (base case) 160 4.29 Cl-Feedstock (sensitivity- netback value) 192 5.15 Cl-Coal Replacement 64 1.72 Quantities 7. Quantities of South Bassein gas required to meet -he three demand scenarios were established on the. basis of Annex 4.1. rhE priority for gas use is as follows: first as feedstock, second as liquid .ydrocarbon replacement and lastly, as coal replacement in a few selc--ad cases. 4! f.o.b. price of naptha at US$300/ton- 2/ c.i.f. kerosene price of US$389/ton adjusted for calcr-°:ic equivalence. - The end-1982 c.i.f. Bombay price oi fuel oil was take-, - be US$200/ton which is equivalent to US$160/l,C0O0 Nm of natural gas. 4/ The end-1982 price of coal was taken as US$53/ton fo-- with a calorific value of 6,600 kcal/kg- 75 ANNEX 4.3 Page 3 of 3 However, the feedstock plus hydrocarbon replacement demand always exceeds the South Bassein lean gas supply and, therefore, none of the gas is assumed to be used for coal replacement in the economic analysis. Energy Department January 1983 INDIA Calculation of Netback Value of Gas Used as Feedstock (US$ Million in End-1982 Prices) Capacity Quantities Costs (Excluding Feedstock) Year Utilization (1) Gas (1000 a3- Ammonia Urea Capital Working Fixed Fuel Other Total Value of Net Feedstock Fuel (tons) (tons) cost Capital Costs Costs Variable Costs Costs Production Benefits 1 (1983) - - - 28.1 - _ _ - 28.1 - (28.1) 2 - - - - - 79.4 - - - - 79.4 - (79.4) 3 - - - - - 88.1 - _ _ 88.1 - (88.1) 4 - - - - - 98.5 - - - - 98.5 (98.5) 5 (1987) 40 200,028 69,707 178,206 303,072 44.2 1.2 9.3 11.2 6.1 72.0 97.0 25.0 6 60 300,041 104,560 267,310 454,608 20.8 1.7 18.7 16.7 9.1 67.0 145.5 78.5 7 80 400,055 139,413 356,413 606,144 - 0.8 18.7 22.3 12.1 53.9 194.0 140.1 8 90 450,062 156,840 400,964 681,912 - 0.3 18.7 25.1 13.6 57.7 218.2 160.5 9 90 450,062 156,840 400,964 681,912 - - 18.7 25.1 13.6 57.4 218.2 160.5 10 90 450,062 156,840 400,964 681,912 - - 18.7 25.1 13.6 57.4 218.2 160.5 11 90 450,062 156,840 400,964 681,912 - - 18.7 25.1 13.6 57.4 218.2 160.5 12 90 450,062 156,840 400,964 681,912 - - 18.7 25.1 13.6 57.4 218.2 160.5 13 90 450,062 156,840 400,964 681,912 - - 18.7 25.1 13.6 57.4 218.2 160.5 i4 90 450,062 156,840 400,964 681,912 - - 18.7 25.1 13.6 57.4 218-2 160.5 15 90 450,062 156,840 400,964 681,912 - - 18.7 25.1 13.6 57.4 218.2 160.5 16 90 450,062 156,840 400,964 681,912 (14.4) (4.0) 18.7 25.1 13.6 39.0 218.2 179.2 A. Present Value of Net Benefits without Feedstock Cost = US$294.1 million. B. Present Value of Gas Feedstock Consumption Assuming Unit Price of US$1.00 per 1,000 Nm3 = US$1.53 million. C. Netback Value of Gas as Feedstock (A divided by B) = US$192 per 1,000 Nm3. Notes:- 1. Ammonia/Urea planit with 1,350 TPD ammonia capacity and 2,296 TPD urea capactty. All ammonia p5oduction is converted to urea at the rate3of 0.588 tons ammonia per ton of urea. 100% capacity utilization corresponds to 330 stream days. Gas consumption is 660 Nm per ton of urea for feedstock and 230 Nm per ton of urea for fuel. Capital and operating costs are based on updated costs for the Hazira fertilizer plant currently under construction adjusted for size (llazira has two trains of 1,350 TPD ammonia each) and fuel type (Hazira is based on coal as fuel). 2. Economic prices (in end-1982 US$) are: IJrea - US$320 per ton, Gas as fuel - US$160 per 1,000 Nm3 based on fuel oil equivalence. Other variable operating costs excluding feedstock and f,,el, total US$20 per ton of urea. 3. The presen,t values under A anld B above are based on a 12% discount rate or opportunity cost of capital. 4. Should the netback value of the lean gas be calculated on the savings in capital and operating costs that a gas-based ammonia/urea plant would have over a fuiel oil- based plant of identical output or capacity (with an economic value of US$200 per ton for fusl oil used as feedstock and as fuel), then the netback value of the natural gas used as feedstock and as fuel would range between US$180 and US$190 per 1,000 Nm Energy Department January 1983 - 77 - ANNEX 4.5 INDIA SOUTH BASSEIN OFFSHORE GAS DEVELOPMENT PROJECT ECONOMIC RATE OF RETURN OF THE PROJECT IN MILLION US DOLLARS- END 1982 PRICES BASE CASE ANNUAL PRODUCTION GAS NGL CAPITAL FIXED VAR TOT.OP REVENUS NET MILLION CM 000 TONS COSTS COSTS COSTS COSTS BENEFITS 1982/83 - - - - - - - - 1983/84 - - 340.05 - - - - (340.05) 1984/85 - - 228.30 - - - - (228.30) 1985/86 1,496.50 232.80 39.50 48.63 29.93 78.56 309.28 191.22 1986/87 1,B25.00 283.10 - 48.63 36.50 85.13 376.93 291.80 1987/88 1,825.00 283.10 - 48.63 36.50 85.13 376.93 291.80 1988/89 1,825.00 286.80 - 48.63 36.50 85.13 378.04 292.91 1989/90 1,825.00 286.80 - 48.63 36.50 85.13 378.04 292.91 1990/91 1,825.00 286.80 - 48.63 36.50 85.13 378.04 292.91 1991192 1,825.00 288.70 - 48.63 36.50 85.13 378.61 293.48 1992/93 1,825.00 288.70 - 48.63 36.50 85.13 378.61 293.48 1993/94 1,825.00 290.60 - 48.63 36.50 85.13 379.18 294.05 1994/95 1,825.00 294.30 - 48.63 36.50 85.13 380.29 295.16 1995/96 1Y825.00 294.30 - 48.63 36.50 85.13 380.29 295,16 1996/97 1,825.00 294.30 - 48.63 36.50 85.13 380.29 295.16 1997/98 1,825.00 294,30 - 48.63 36.50 85.13 380.29 295.16 1998/99 1,825.00 294.30 - 48.63 36.50 85.13 380.29 295.16 1999/2000 1,825.00 294.30 - 48.63 36.50 85.13 380.29 295.16 2000/2001 1,825.00 294.30 - 48.63 36.50 85.13 380.29 295.16 2001/2002 1,825.00 294.30 - 48.63 36.50 85.13 380.29 295.16 2002/2003 1,825.00 294.30 - 48.63 36.50 85.13 380.29 295.16 2003/2004 1,825.00 294.30 - 48.63 36.50 85.13 380.29 295,16 2004/2005 1,825.00 294.30 - 48.63 36.50 85.13 380.29 295.16 RETURN ON INVESTMENT - 37.905% FOOTNOTE:(1) ANNUAL FIXED OP. COSTS AT 8X OF CAPITAL COSTS (2) ANNUAL VAR. COSTS AT US $ 20/1,000 CM OF RICH GAS (3) IN THE BASE CASE, ALL THE RICH GAS IS VALUED AT THE FUEL OIL EOUIV. OF US $ 160/1,000 CM OF GAS (4) THE NGL IS VALUED AT US $ 300 PER TON. ENERGY DEPARTMENT PETROLEUM PROJECTS DIVISION 1 INDIA SOUTH BASSEIN OFFSHORE GAS DEVELOPMENT PROJECT ECONOMIC RATE OF RETURN OF THE PROGRAM (US S MILLION - END 1982 PRICES) :FEEDSTOCK AND HYDROCARBON REPLACEMENT: BASE CASE ANNUAL PRODUCTIDN AND SALES INVESTMENT COSTS OPERAIING COSTS YEAR LEAN GAS(A) LEAN GAS(B) NGL LPG C2/C3 TOTAL PROJECT PLATFORMS C2/C3 L.P,G. TOTAL FIXED VAR TOTAL TOTAL NET CASH MILLION CM MILLION CM 000 TONS 000 TONS MILLION CM REVENUES INVEST WITH INLAND PLANTS PLANTS INVEST COSTS COSTS OP.COSTS COSTS FLOWS PIPELINE 1982/83 - 1983184 - - - - - - 340.1 - - 35.0 375.1 30.0 - 30.0 405.1 (405.1) 1984/85 - - - - - - 228.3 270,0 - 75.0 573.3 75.9 - 75.9 649.2 (649.2) 1985/86 503.7 1,6801 433.2 247.6 - 580,4 39.5 325.0 - 75.0 439.5 111.0 48.2 159.2 598.7 (18.3) 1986/87 609.6 2,699.2 660.7 375.0 - 880.6 - 240.0 20.0 75.0 335.0 137.8 73.0 210.8 545.8 334.8 1987/88 1,427,2 3,333.9 934. 488.3 - 1,241.4 - 75.0 40.0 45.0 160,0 150.6 105.0 255,6 415.6 825.8 1988/89 2,617.! 3,681.9 1,303.6 673.0 33.7 1,680.2 - - 15.0 - 15.0 151.8 144.8 296.6 311.6 1,368.6 1989/90 3,646.4 2,683.5 1,313.7 678,1 53.8 1s694.3 - - - - - 151.8 146.0 297,8 297.8 1,396.5 1990/91 3,967.6 2,332.7 i,313.7 678.1 80.5 1,694.9 - - - - - 151.8 146.0 297.8 297.8 1,397.1 co 1991/92 4,299.7 1,971.0 1,323.1 678.1 107.2 1,698.3 - - - - - 151.8 146.0 297.8 297,8 1,400.5 1992/93 4,537.0 1,703.8 1,323.1 678.1 134.3 1,699.0 - - - - - 151.8 146.0 297.8 297.8 1,401.2 1993/94 4,796,1 1,444.7 1,338.1 678.1 134.3 1,703.5 - - 50.0 - 50.0 155.8 146.0 301.8 351.8 1,351.7 1994/95 5,015.1 1,225.7 1,356.8 678.1 134.3 1,709.1 - - 80.0 - 80.0 162.2 146.0 308,2 388.2 1,320.9 1995/96 5,263,3 182.5 1,356.8 678.1 235.0 1,602.0 - 400 - 40.0 165.4 146.0 311,4 351.4 1.250.6 1996/97 5,379.0 - 1,356.8 678.1 295.4 1,603.4 - - - - - 165.4 146.0 311.4 311.4 1,292.0 1997/98 5,289.9 - 1,356,8 678.1 375.9 1,605.3 - - - - - 165.4 146.0 311.4 311.4 1,293.9 1998/99 5,200.9 - 1,353.1 678.1 456.4 1,606.0 - - - - - 165.4 146,0 311.4 311.4 1,294.6 1999/2000 5,111,8 - 1,349.4 678.1 536.9 1,606.8 - - - - - 165.4 146.0 311.4 311.4 1,295.4 2000/01 5,11l.8 - 1,345,6 678.1 536.9 1,605.6 - - - - - 165.4 146.0 311.4 311.4 1,294.2 2001/02 5,111,8 - 1,341.? 678.1 536.9 1,604.5 - - - - - 165.4 146,0 311.4 311.4 1,293.1 2002/03 5,111.8 - 1,338.2 678.1 536.9 1,603.4 - - - - - 165.4 146,0 311.4 311.4 1,292.0 2003/04 5,111.8 - 1,334.4 678.1 536.9 1,602.3 - - - - - 165,4 146,0 311.4 311.4 1,290.9 2004/05 5,111,8 - 1,330.6 678.1 536.9 1,601.1 - - - - - 165.4 146.0 311.4 311.4 1,289.7 RETURN ON INVESTMENT = 48.643Z. 4:- NOTE: (A)FEEDSTOCK AT S/THOUSAND CM 160(BASE CASE) (B)HYDRO-CAREON REPLACEMENT AT S/THOUSAND CM 160 (C)NGL PRICE: S/TON 300 (D)LPG PRICE S/TON 408 (E)C2/C3 PRICE S/THOUSAND CM 200 - 79 - ANNEX 4.7 INDIA SOUTH BASSEIN GAS DEVELOPMENT PROJECT SENSITIVITY ANALYSES - ECONOMIC RATE OF RETURN Economic Rate of Return Cases Project -! Program 1. Base Case 37.9 48.6 2. Capital Cost Up 20% 31.5 41.0 3. Gas, LPG, etc. Prices Down 20% 29.3 38.5 4. Project or Program Delayed One Year 31.3 39.1 5. Combination of 2, 3 and 4 21.3 26.5 6. Netback Value Used for Gas Feedstock 42.7 50.9 7. Gas, LPG, etc. Prices Increase Annually in Real Terms b/ 41.0 52.6 8. Capital Costs Down 20% 46.8 59.3 9. Gas, LPG, etc. Prices Up 20% 45.8 58.0 a! For the case of the Project only, the rich gas (i.e., before LPG and C2/C3 are extracted) at the Hazira terminal and the NGL extracted at the process platform and at the terminal arl the products. The rich gas is priced as Cl fuel (US$160 per thousand Nm ) in the Base Case. bI The real term annual changes in gas, LPG, NGL and C2/C3 prices are as follows: % Price Change From Period Previous Year's Price 1983/84 -4$ 1984/85 to 1985/86 +2% 1986/87 to 1990/91 +3% 1991/92 to 1994/95 +2% 1995/96 to 2004/05 +1% Energy Department January 1983 INDIA OIL AND NATURAL GAS COMMISSION (ONGC) ORGANIZATION CHART Membe Geo Science || Mebr Mme Meer ebr lEopi.)~ ~ ~ ~~~GSi.. (me Drco Director ) O o | rn | Direc., rAd. Direo G.M Dirctr | (Geology) lest D T 2 H rSchOlDp.agod | Opero ) {Westero Rg_oelGeophysics) |M ) , OOperitions) | yinetce of Director | Storerand | Chief Engineer G.M. Director | irector GM. lGeo.raphy) P urchaso Production |bosteroRogiorrl Chief |Geology) |PorIoerrel) IProducnF) Picoce lorSt. rport Stores SDptdg. Engineer|. Pol Expu.) CSbsCell oN Roitral Regonie (Ad- t ~ ~ ~ ~ ~ ~ ~ ~~~~~oe Cel Veifceio Depet SopthsCOue H {1Spdg. GeoloyLDrcorAd.Dretr00. C L Sptd . Engineer P.M. Chief Engineer | CSV L Ploneeg l Elect. J 1 ~~~~~~~West Bengal | )Cioil) Securily.Vig.| Sectioe G.M.~~~~~~~~~~~~~~~~~~~~GM q SupSd. CtemCetj {l RegioScretarit - | od Planoing C_G.M. Suptdg. GeoI.,lo | G.M. Planning sectioffl .Materials Directo; Fio ance| d I~~~~~I INOIA SOUTH BASSEIN OFFSHORE GAS DEVELOPMENT PROJECT Oil and Natural Gas Commission ONGC) Bombay Offshore Projnot (BOP) Organization Chart 1[ X-r- -GC <,co) I Iima (DrlS |''~ |~,r Pnr,,89el (O1h1 PhileCIn l I lgY I~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~~ ~ ~~~~~~~~~~~~~~~~~~~~~~Mrae P'hvrrvn MIa Jll 982 SOUIIP ONGC W,dOn-45 - 82 - ANNEX 5.3 Page 1 of 4 INDIA ONGC'S Investment Program Background 1. ONGC is now in the third year of the five-year plan period 1980/81- 84/85. The initial plan document (June 1980), provided for expenditures of Rs 40 billion (at 1980 prices) approximately; it was revised in August 1981 in order to incorporate the accelerated program, and outlays were increased to Rs 47.9 billion (at 1981 prices). The production target over the plan period was increased from 51.3 million tons of crude oil to 62.8 million tons. 2. In March 1982, ONGC completed a 10-year conceptual planning exercise over the period 1980/81-89/90 where two scenarios are presented: Variant I has an annual production objective of 46.5 million tons of crude oil by 1989/90, while Variant II has an o"bjective of 60.5 million tons in the same year. Taking into account that ONGC's existing reserves cannot sustain a production rate above 30 million tons per annum, both scenarios assume that increased exploration expenditures would yield commercial discoveries which will start producing in the second half of the 1980's. 3. ONGC recognizes that in order to accelerate its exploration program during the seventh plan period (1985/86-89/90), additional exploration and development expenditures will have to be incurred already during 1983/84 through 1984/85 so that when the seventh plan begins, it will have adequate materials and equipment, trained personnel and resources to achieve its objectives. One should note, how vver, that the Government has not yet approved ONGC's recommendations._ In consultation with ONGC, it was decided that for the purposes of the financial projections over the period 1982/83- 1987/88: (i) Variant I of ONGC's expenditures program would be adopted (with all capital costs expressed in current prices); (ii) no new discovery would come under production during the forecast period (a conservative assumption since recent oil discoveries could come under production during the forecast period); and (iii) no expenditure for the development of such discoveries would be provided for. The investmnent program appears at the end of this Annex, which has also been used as an input for the financial projections (Annex 6.1), should therefore be considered as the broad outline of an expenditure program which could be, at relatively short notice, significantly altered, for instance on account of reservoir studies (which would lead to additional investments in producing areas), or commercial discoveries. 1/ The Government in principle approved, in November 1982, all the exploration components as well as the development of presently known reserves proposed in Variant I, but did not approve the speculative portion of the development investments dealing with future (expected) discoveries. These types of development investments will be proposed by ONGC as the discoveries are actally made. The GOI-approved plan is now known as the Core Plan. -83 - r'age L OX 4 Exploration a. Onshore 4. The Western Region includes the Cambay, the Rajasthan, the Saurashtra and the Kutch basins; but only the Cambay basin, has been fairly well explored. The region's recoverable oil reserves are estimated at 113.6 million tons as of 1/1/82 (51.5 million tons as of 1/1/81). The exploration strategy adopted here is to: (i) locate extensions of prospects already delineated; (ii) identify subtle traps in different basement blocks on the basis of sophisticated seismic work and geological modelling; and (iii) explore new areas such as the shoal project in the Cambay Gulf, Kutch, Saurashtra and Rajasthan. Deeper prospects in the existing known areas are also to be drilled. During the forecast period 1982/83-1987/88, ONGC plans to carry out about 22,230 line-km of seismic surveys and drill 200 wells (about 490,000 meters). 5. The Eastern Region (Assam, Nagaland, Meghalaya, etc.) is considered very prospective. Recoverable oil reserves were estimated at 61.4 million tons as of 1/1/82 (50.0 million tons as of 1/1/81). More than 40 prospects identified from seismic and geological surveys are yet to be drilled. Virgin areas such as Dansiri Valley, Naga Hills, and north bank of Brahmaputra are planned for drilling. 14,600 line-km of seismic surveys are planned during the forecast period, together with 156 exploratory wells (altogether 580,000 m). 6. In the Central Region, which comprises the balance of the onshore area, no commercial discoveries have been made so far, but a number of attractive prospects have been identified, including the basins of Bengal, Krishna-Godavari and Cauvery. ONGC also plans to initiate exploration efforts in new areas (Himalayan foothills -- Ganga Valley) and is in the process of acquiring modern equipment for that purpose (digital seismic units, equipment designed for desert conditions, etc.). 47,900 line-km of seismic surveys are now proposed in the forecast period, together with 186 exploratory wells (744,000 m). b. Offshore 7. Offshore exploration activities have given very encouraging results in recent years. In 1981, a new structure known as B-57 has been discovered south-east of the Bassein field. On the east coast, oil has been discovered for the first time in a new structure in the Palk Straits known as PH-9. Offshore recoverable oil reserves are estimated at 345.8 million tons as of 1/1/82 (328.3 million tons as of 1/1/81). The objective of the exploration program here is to complete the seismic reconnaissance and semi-detailed surveys of most of the promising areas, and extend the same to the continental slope and deeper areas offshore. For this purpose, about 165,000 line-km of seismic surveys and 219 exploratory wells (719,000 m) are proposed in the forecast period. - 84 - ANNEX 5.3 Page 3 of 4 Development a. Onshore 8. Primary production for many of the fields in the Western Region is declining, and sophisticated secondary and tertiary recovery techniques (water flooding, polymer injection, thermal in-situ combustion, gas injection) will be needed to maintain production. Contracts have been signed with the USSR to assist in work-over operations, and with Nowasco of Canada to provide advanced technology for well stimulation, acidization and fracturing. 226 development wells are proposed during the plan period (326,000 m). 9. In the eastern Region, an accelerated production program aiming to produce 4.1 million tons by 1985/86 is underway. 273 wells (815,000 m) are proposed for the forecast period. b. Offshore 10 The accelerated offshore production program includes the further development of Bombay High and the development of new structures such as Ratna (R-12), Heera (B-37/38), Bombay High East and Panna (North Bassein). In addition, the South Bassein offshore gas field will be developed. CFP (France) has been retained for the reservoirs studies and development of Bombay High and neighboring fields. 341 development wells (789,000 m) are proposed during the forecast period. Research and Development 11. Three institutes for research and development function within ONGC; the Institute of Petroleum Exploration (IPE) and the Institute of Drilling Technology (IDT), both at Dehra Dun, ONGC's headquarters, and the Institute of Reservoir Studies (IRS) at Abmedabad. These institutes support ONGC's activities both onshore and offshore. IPE primarily frames the exploration strategy, reviews exploration programs, and prepares reserves estimates. IDT aims at improving the drilling techlnology, and to that effect develops tools, carries out research in indigenous development of mud chemicals and cement additives, as well as supervising and monitoring key exploratory wells projected for deeper targets. IRS establishes drilling plans for various discovered fields, monitors the bebLavior of producing reservoirs, carries out economic studies and investigates enhanced recovery methods. 12. ONGC now is considering establishment of an Offshore Technology Research Institute in Bombay, which will be active in offshore oil exploration, development, production and transportation, as well as updating the know-how on offshore technology, deep water techniques, etc. Source: ONGC. Energy Projects Department January 1983 - 15 - ANNEX 5.3 Page 4 of 4 tWIN OIL AD NATURAL OHS eOUI>I31 INUESTKEKT PRDG8eN (MILLION RUPEES) 1982/83 1983/84 1984/83 1985/86 1986/BY 1987/88 TOTAL 1982/83 THRU 1906/87 I. OFFSHORE A. EXPLORATION 1. SURVEYS KRISRNA-GODVOARI 63 139 38 - 240 OINER SURVEYS 9O 94 135 116 124 132 559 2. DRILLIN6 KRISHNA-GODAVARI 757 1,222 1,355 417 - - 3r7sl OTHER DRILLING 1,119 1,337 875 5,527 6,043 6,015 i,s903 - - -- - -- - - -- - - ---- - -- --- - - -- --- -- - -- - SUBTOTAL 2,029 2,192 2,483 6,060 6,169 6,147 19,153 B. DEVELOPKENT E8IIAY HIN PNASE III 54 - - - - - 54 886803 HIGN PHASE IV 1,088 - - - - - 1,388 MA118Y NIGH PHASE V 2,015 1,693 95 - - - 3,803 BOMBAY HIG8 FUTURE 2,101 6,782 8,407 1,073 5334 39 18,897 R8TYe 355 - - - - - 355 NEERA 680 608 - 603 - - t,981 PENNe - 702 2,992 619 - - 4'313 SOOUTH 8SSEIN PHASo 1 - 3,513 2,339 132 - - 6,314 SUTH B 3SSEI9 PHASE 2 - 338 4,108 3,143 4,628 2,068 14,217 - - -- - --- -- --- -- - - -- - --- - - - - --- - -- - - - SU8TDT8L 6,293 13,756 17,940 7,070 5,162 2,907 51,022 C. COMMON CAPITAL ITEtS AND CONSULTONCIES RTSON-GODVRI 11 85 15 - - - III OTHER 5,073 6,131 1,896 3,102 2,865 1,812 22,067 -- --- - - - - - - -- --- -- ------ - ------ --- -- -- -- - SUBTOTAL 5,089 6,216 4,901 3,102 2,865 1,612 22,178 TOTAL DFFSNORE 13,406 22,764 25,235 17,032 14,196 10,866 92,653 II. ONSHORE 6. EXPLORATION 1. SURVEYS KRISHNA-GODN4ARI 34 44 2 - - - 90 OTHFR SURVEYS 249 465 469 471 416 967 2,070 2. DRILLINs KRISHN6-GODAVARI 95 471 460 64 - - 1,090 WESTERN REGION 278 339 350 588 710 014 2,265 EASTERN RE8ION 232 237 306 380 427 482 1,582 OAfHR REGIONtS 314 /43 82B 1,849 3,4t9 9,350 2,193 -- - - ------ - -- -- --- - - - --- --------------- SUDIDT0L 1,202 2,2YP 2,13 3,353 5,012 6,2113 11,21 B. DEVELOPHENT WESTERN REGION 164 263 284 282 333 367 1,326 EASTERN REGION 314 395 426 605 /26 689 2,166 SUBTOTAL 478 658 710 887 1,059 1,256 1.792 C. CO0MON CAPITAL ITES AND CODNSULTANCIES KRISNMA-GODAi RI 49 44 - - - - 93 OTHERS 1,796 3,133 1,114 9,291 9,901 7,779 20,s85 -- - - --- -- - - - - - - -- - --- - - - - -- - - --- -- SUBTOIAL 1,845 3,477 1,164 9,291 9,901 7,7?9 28,678 TOTAL NSHO8E 3,525 6,4s4 7,209 13,531 15,972 i6,248 46,731 - --- - --- -- - ----- -- - - -- - - - - -- -- - --- - -- - III INSTITUTES --------------- 45 65 s0 60 60 S0 290 I. RES090C8 1 DEVELOPMENT -------------------…-… -- 32 35 40 0o 40 40 187 TOTAL 17,008 29,298 32,644 30,663 30,268 26,211 139,981 s88TH BASSE0N PHASE 2 IHCLUDES PLOTFORNS 38808D PIPELINE, LPG PLA61 AND C2/C3 PLANT ENERGY DEPARTNONT PETROLEUN PROJECTS DIVISION 1 11BRD) - 86 - ANNEX 6.1 INDIA Page 1 of 3 OIL fAND NATURAL GAS COMMISSION INCOME STATEMENTS (MILLION RUPEES) ACTUAL PROVISIONAL FORECAST 1978/79 1979/80 1990/81 1981/82 1952/8! 1983/81 1984!85 i985/86 1986/87 197i/88 OPERATING REVENUES OFFSHORE Ir717 2,413 27757 8r650 17,64i7 2 30695 30i18 °2Y!0? 34,443 36:378 ONSHORE 2,059 1,865 1,626 57141 7719?' 8J070 8,751 9,963 10,721 11,221 TJTAL OPERATING REVJ6NUES 3,776 ^,278 4,383 13,791 21,876 327765 38J892-' 42;AX070 64 17K61 OPERATING EXPENSES OFFSHORE OPERATING COSTS 225 178 402 593 769 1,263 1,535 li5L9 1505 1250' SALES TAX/RUYP4AY/LESS 386 520 486 ft881 2,654 3;867 4,658 1,670 4,o860 1i998 DEPRECIATION/DEPLETION 680 761 1,325 1,760 4,446 6r215 l :412 10,100 9,874 9r964 SUBTOTAL l 291 11,59 2213 4r237 7rS69 11t3"5 20r605 16,58? 16,2rr? 16 ,67 UNSHD RE OPERATING COSTS 219 285 293 346 360 432 4190 5A40 546 546 SALES TAX/ROYALTY/CESS 661 623 521 989 1;23i 1,391 1,i3Oi 1.704 182? L,916 DEPRECIfTION/DEPLETION 603 606 661 1,086 1241 2r135 2r680 3-898 5-,95 85294 SUBTOTAL 1;483 1s514 1,475 2s4721 2:835 3.961 4 67'6 6 14' K7 87CI iOs7-S OPERATING INCOIME OFFSHORE 426 954 54q 4,4.13 9,778 13,350 9,533 15;SS 11l,104 .9:1il ONSHORE 576 351 151 27720 41364 IY109 1-078 3,821 2,51l 46A TOTAL OPERAFING IN!OHE 1,002 1,2-05 695 7:13. 1 1142 17,14? 174611 19,339 207Y952 - 20,37? OTHER INCOME 23 2 118 19 - - - TOT(L INCOME 1,025 ls307 ' 813 7,152 14l,156 17:459 13.61b 9 -339 20,955 20,37' LESS-INTEREST 210 235 17' 817 1;343 2,367 3;575 ';581 5,585 6 - O TkX 90 520 - 2-752 5,024 1;7i1 - '7,078 56 1v06 184 NET PROFIT 725 552 336 3r553 7,789 l0i331 ±0,036 968C0 10 262 9, 49 OPERATING RATIOS 1%) OFFSHORE 75.2 6 O.5 80.i 49.0 44.v 45.9 6-°v 51.2 47.3 45,'i ONSHCRE 72.0 8l1 90.7 1i7.1 39.4 IY.1 5i.4 6i.6 ;3. I 95, COMBINED 73.5 P.5 84.1 48.3 43.1 't16. 65i t5.0 53.5 51.I RIFE OF RETUR:iN ON NET ASSETS(Z) OFFSHORE 15.1 2L4.9 11.± t5.5 85.S 638. 27.3; 31.': 33.± 31 4i QNSWIRE 26.7 15.4 6.0 87.2 i3.4 K.4 35.1 21.7 tu 1.3 COMBINED 20.4I 21.4 9.7 72.3 88.0 641..7 2c 3 26,? 25.9 218 ENERi,'( DEPARTMENT FETROLEUM PROJECTS DIVISION I - 87 - ApNEX 6, 1 Page 2 of 3 INDIA OIL AND NATURAL GAS COMMISSION SOURCES 2 APPLICATIONS OF FUNDS (MILLION RUPEES) ACTUAL PROVISIONAL FORECAST 1978/79 1979/80 1980/81 1981/82 1982/83 1983/81 i984/85 1985/86 1986/87 1987/88 FUNDS PROVIDED FROM OPERATIONS OPERATING INCOME lrO02 1r305 695 7r133 14r142 17r459 i3r6ii 19v339 20r955 20r377 DEPRECIATION b283 1,367 17986 21846 5i68/ 87350 17,092 14;298 1J,369 18,257 SUBTOTAL 2,285 27672 2i681 9,979 19,829 25i809 30,703 33,637 36r324 38,634 DEDUCTIONS: ___________ DIVIDENDS 181 200 204 206 206 206 206 206 206 206 DEBT SERVICE: PRINCIPAL 153 149 474 423 656 l1099 1,384 1,564 3,525 4,802 INTEREST 210 235 477 847 1,343 2,387 3;575 41581 5ri85 6rO04 INCOME TAX 90 520 - 2,752 5,024 4,141 5,078 5,106 4,884 WORKING CAPITAL INCREASE (EXCLUDING CASH) 377 (116) (85) 634 529 587 778 712 896 410 SUBTOTAL ,l011 978 ir070 4,862 7r758 9,020 5,943 12r14) i5r3i8 16,306 ADDITION: OTHER INCOME 23 2 118 19 14 - FUNDS AVAILABLE FOR INVESTMENT 1,297 1,696 ir729 5ri36 i2r08J 16,789 24760 21,496 2r10(36 22r328 INVES(MENT PROGRAM 1,920 2,741 4,271 8,692 17,008 29,298 32,614 30,663 307268 26,214 BALANCE TO BE FNAHNCED 623 1,045 2,545 3Y556 4,i 923 12,509 7,884 9,167 92262 37886 FINANCED BY: ___ ____ ___ 601 EQUITY CONTRIBUTIONS 116 50 55 - - - - - - - BORROWINGS 461 1,007 2,484 3r 609 5,061 127501 8,006 9,380 9,600 4,4O0 OIDB GRANTS - - - 11 32 35 40 40 40 40 TOTAL OUTSIDE FINANCING 577 1,057 2,539 3,620 5,096 12,539 B8046 9,420 9:640 4,A40 INCREASE (DECREASE) IN CASH (46) 12 (6) 64 173 30 162 253 .179 554 CUMULATIVE CASH 2'4 36 30 94 267 297 459 712 i090 1,644 DEBT SERVICE COVERoA1E 6.3 7.0 2i8 7,9 9.9 7.4 .2 5.5 40O 3.6 ENERGY DEPARTMENT PETROLEUM PROJECTS DIVISIiJN 1 01/21/83 10 38t06 - 883 ~ ANNEX 6,1 Page 3 of 3 INDIk OIL AID NATURGA MS COMIISSION "ALACE SHEETS (NILLIUDN RUPEES) ACTUAL PROWISIONL FORECAST 1978/79 1979310 1990181 1981182 1982/83 1983/84 1984/85 1985/86 i986/8/ i987/88 ASSETS CUiRENT ASSETS CASH 24 36 30 94 267 297 459 712 1,090 i6A4 ACCOUNTS RECEIVABLE 497 470 563 2:109 1Y477 1b983 2,365 27540 2;689 2i86B STAFF ADYWICES 45 66 15D 186 236 296 366 446 526 526 INVEhTORIES 1,111 11551 2:256 21447 2,432 27712 3:272 3,828 14566 57106 OTHER 657 1:190 1:193 1P193 1r193 1ii93 Pi193 11I93 1r193 ii93 SUBTOTAL 2r334 3:303 4:192 6,029 54605 6:481 77655 8719 i1r064 1l1337 PRPERTY PLANT I EOUIPNENT OFFSHORE GROSS ASSETS SiOl? 6:005 94O2 12:948 241926 391589 766517 93:440 107:468 119i 572 LESS CCNATED DEPRECIATION 1:302 2:063 3:563 5,323 9:769 L57984 30:396 400796 50:670 60:634 OFFSHORE NET ASSETS 3:717 3:942 5:857 7:625 15:15/ 23Y605 46:121 52:6"4 56:798 587938 GRS ASSETS 7:160 7t955 9:930 109S51 14:265 20:i18 27:089 38:717 53:836 70:732 LESS ACCUUlATED OtPRECIATION 4:976 5:582 6:177 7:263 87504 10:639 13:319 17:217 22:712 31:005 011HORE NET ASSETS 2:184 2373 2t653 3:588 50761 9:479 13:770 21:500 316124 390127 TOTAL NET PROPTYr PLANT I EQUIPMENT 5:901 6:315 8:51') 11:213 20:918 33:084 59r891 741ri44 87922 984665 WORK-IN-PROGRESS: OFFSHIRE 352 1:224 1 146 4:251 5:756 13:9:7 2:384 2;593 2:861 1:723 ONSHORE 554 642 804 842 953 1r534 1rB52 3r755 4:608 2:960 SUBTOTAL 906 14866 1:950 5:093 6:709 S1491 4:236 6r348 7s469 44683 LONG-Tu 1INVESTMENTS 250 250 2SD 250 250 250 250 250 250 250 TOTAL ASSETS 9:391 11:734 14:90'2 22y585 33:482 55:306 72032 89:161 1057705 1147935 LIABILITIES I SHARHOLDER EQUITY CLURlT LIABILITIES ACCOUITS PAYABLE 849 1:422 1:67i 2,660 1:969 2:158 2:292 2:291 2:212 2s321 CURIEf PORTION LONG-TERN DEBT 149 212 415i 656 1b099 1:384 1,564 3b525 4:802 4:035 OTHER 314 824 1:374! 1:528 1:093 li:63 1:263 i1363 i1514 1:713 SUBTOTAL 10312 2:458 3:46' 4844 4:161 40705 57119 7,179 8:527 8:069 LONG-TERN DEBT 3:051 3:910 57957 914t3 13:551 24t956 317578 39Y394 45:469 45i067 LESS CUIDRT PORTION 149 212 415 656 1:099 1:384 i1564 3:525 4:802 4sO35 SUJTOTAL 2:902 3:698 5:542 8:487 12:452 23:572 30r014 35rB69 40r667 41:032 S4AREHOlIDFR EOUITY CAPITAL 3P324 3:374 3:429 3:429 3r429 3:429 3:429 3s429 3r429 3:429 RESERVE 17853 27204 27467 5:825 137440 23:600 33:470 42:984 53:082 62:405 SUBtOTAL 5:1/) 5:578 5:896 9:254 16:869 27:029 36i899 46:413 56:511 65:834 TOTALLIABILITIES I SHAREHOI.DER EtlJI[Y 9:391 11:734 14:902 226585 44:482 55:306 72:032 89:461 105:70i 114:935 =_==e=:=== e -.:r:=-= ::==.:=rr :-3 .:=e-Mr=.- _--m== :r=:- :-=: DE8T:D88r PLUS EDUITY 0.37 0.41 0.50 0,50 0.45 0.48 0,46 0.46 0.45 0.41 CLIENT RATIO 1.8 1.3 1.2 1.2 1.3 1.4 1.5 1.2 1.2 1.4 EERGEY DEPARrNENT PETROLEUN PROJECTS DIVISION I - 89 - ANNEX 6.2 Page 1 of 14 INDIA OIL AND NATURAL GAS COMMISSION Assumptions Underlying the Financial Projections I. Background 1.01 The financial projections are based on: (i) ONGC's revised five-year plan 1980-85 submitted to the Government in August 1981; (ii) the revised budget for 1982; (iii) the budget for 1983; and (iv) the Core Plan (1980/81- 1989/90) approved in principle by the Government last November 1982. Appropriate physical contingencies have been incorporated in the investment program, and investment and operating costs include price contingencies (at an average rate of 7.5% per annum). II. Income Statements a. Operating Revenues 2.01 Operating Revenues are calculated on the basis of the prices currently obtained by ONGC for crude oil, natural gas and LPG. The price of both onshore and offshore crude oil was set at Rs 138.535 per Bbl, for 340 API crude, on July 11, 1981, with an escalation formula for lighter crudes. The cost of offshore crude on that basis turns out to be Rs 1,188/ton, including a cess of Rs 100/ton and a royalty of Rs 61/ton. If the crude oil is piped to shore, a pipeline tolling fee of Rs 50-75/ton is added to the crude oil price (the tolling fee is based on a complex formula, taking into account the investment cost, operating cost, the annual quantities of crude oil piped, and a weighted rate of return to ONGC). If the crude is sent to shore by tankers, the users pay directly the transport cost. The price of onshore crude varies between Rs 1,181/ton and Rs 1,204/ton, depending on the quality of the crude. 2.02 The price of gas is, in the case of offshore production based on the replacement value of naphtha, and the end-use. In the case of onshore production, it is based on the consumer's ability to pay, and the end-use. 2.03 The price of LPG is based on the current one, i.e. Rs 1,830/ton, although ONGC has requested an increase in this price. 2.04 Detailed calculations of revenues appear in page 4 of this Annex. Operating Expenses 2.05 Operating Costs for both the onshore and offshore operations include salaries and wages, stores and spares, operating costs of various capital items under leasing arrangements (supply vessels, helicopters, rigs), selling expenses and overheads. 2.06 Sales tax, Royalty and Cess are based on actual qualities of oil and gas produced. Sales tax is only applicable for onshore production. Rates are - 90 - ANNEX 6.2 Page 2 of 14 as follows: 4/104 for onshore crude, 11/111 for Western Region gas, and 7/107 for Eastern Region gas. Royalty is Rs 61/ton for crude oil (both onshore and offshore), and 10% of the well head value for gas. Cess is equivalent to Rs 100/ton, both onshore and offshore. Detailed computations appear in page 5 of this Annex. 2.07 The depreciation of the tangible assets is calculated on the basis of Income Tax regulations. However, depending on the actual use of equipment, the depreciation is allocated to the production, development or exploration activities. 2.08 The expenditure incurred on exploration, including the depreciation allocated as stated above, is charged uniformly at 1/15 th of the gross expenditure incurred year after year until the area is declared abandoned or productive. If the area is abandoned, the balance of the amount not yet written off is depreciated over three years beginning in the year in which the decision is made. If the area is declared productive, the balance of exploration expenditures is written off over a ten-year period beginning in the year in which the decision is made; subsequent exploration expenditures are written off in equal installment, during the ten-year period. Any subsequent exploration expenditures (i.e. beyond the ten-year period) is charged immediately against revenues. 2.09 The cost of surveys is not capitalized and charged immediately against revenues. 2.10 For production assets, typical depreciation rates either by reducing balance or straight line methods, are as follows: Pipelines and Machinery - 10%; Platforms - 30%; Development Wells - 10 years; Stabilization and Processing Plants - 15%. The depreciation schedule appears in page 6 of this Annex. 2.11 The schedule of debt servic,e payments appear in pages 8 to 14 of this Annex. 2.12 Income tax rate is 56.375% iand is based on the following principles: (i) until a decision is made to abandon or develop, exploration expenditures are not deductible - following that decision, exploration expenditures are written off over a three-year period and subsequent expenditures are deductible immediately; and (ii) an amount equivalent to 25% of the value of an asset being commissioned is deductible for tax purposes on that year (investment allowance). III. Balance Sheets 3.01 Gross Assets build-up are based on the investment program in Annex 5.3. 3.02 Long-term investments refers to ONGC's subsidiary, Hydrocarbon India Ltd, which undertakes ventures abroad but is being phased out at present; no further investments are contemplated. - 91 - ANNEX 6.2 Page 3 of 14 3.03 Debtors were forecast on the basis of ONGC's current arrangements, i.e. 24 days of sales for offshore crude and gas, 16 days for onshore crude, 30 days for onshore gas and 16 days for LPG. 3.04 The current portion of the long-term debts are included in current liabilities in this financial projection (although ONGC does not follow this practice). A minimum current ratio of 1.2 is maintained in the forecast period by increasing the cash holdings as necessary. 3.05 The debt schedule appears in pages 8 to 14. Additional medium-term borrowings were assumed to be at 14% over seven years, (including 2 years grace period) a reasonable assumption. The proposed IBRD Loan is assumed to be over 15 years, including a five-year grace period, and a rate to ONGC of 12%. 3.06 Grants in small amounts are anticipated from the Oil Industry Development Board (OIDB) to cover primarily research projects. No provisions are being made to cover an increase in the amount of government equity. IV. Sources and Applications of Funds Statement 4.01 The investment program is examined in detail in Annex 5.3. 4.02 Dividends would continue to be paid to the Government at a rate of 6% of government equity. Energy Department January 1983 92 - ANNEX 6.2 Page 4 of 14 INDIA OIL AND NITURAL GAS COMINSSION BREAKDOWN OF OPERATING REVENU1ES 1982/03 1903/84 1984/85 1985/06 1986/07 1907/80 WITIES CRUDE OIL (MILLION TORI) OFFSHOR BOHBNT HIGH I P4NNA 11.87 15.54 10.35 16.57 16.54 16.07 RATNA T I EERA 0.24 1.,0 2.34 2.23 2.10 1,95 HEERA T - - - - - - PANNAT - T - - - - SOUTH BASSEIN (NGL) - - 0.43 0.66 0.93 SUBTOTAL 12.11 17.34 20.69 19.23 19.30 18.95 ONSHORE AlKLESHiWAR 1.70 1.70 1.70 1.70 1.70 1.70 NORTH GUJMAT 1.70 1.90 2.40 2.50 2.60 2.S0 EASTERN REGO1N 2.40 2.80 2.00 3.60 4.10 4.30 SUBTOTAL 5.80 6.40 6.90 7,00 8,40 8.80 TOTAL CRUDE OIL 17.91 23.74 27.59 27.03 27.70 27.75 Gas (THOLSANO NH3) OFFSHOE ASSOCIATED rA5 1,637 1,640 2,336 2,475 2.606 2,664 FREE 545 - - - 2,183 3,309 4,761 SUBTOTAL 1,639 1,640 2,336 4,658 5,915 7,425 ONSHORE WESTERN REGION 76:1 760 780 000 025 050 EASTERN REGION 139 140 240 360 368 393 SUBTOTAL 900 900 1,020 1,168 1,193 1,243 TOTAL GAS 2,539 2,540 3,364 5,826 7,108 8,660 LPG 0THOUSAN0 TONS) OFFSHORE 100 180 360 591 735 840 OS1ORE1- - 10 58 72 73 TOTAL LPG 180' 10 370 649 S00 921 6006M0A PRICE CRUDE OIL IRS/TON) OFFSHORE 1.250 1,250 1,250 1,250 1,250 1,250 ON1HORE 1,190 1,200 1,200 1,200 1,200 1,200 GAS 1RS/THOUSAJ4 NM3) OFFSHORE 1.330 1,641 1,548 1,500 1,500 1,500 ONSHORE 303 400 400 400 400 400 LPF (RS/TON) ----------- 1,830 1,830 1,830 1,830 1,830 1,030 TOTAL REVENUES 69(ILLION RS) OFFSHORE CRUDE OIL 15.130 21,675 25,063 24,038 24,125 23,600 GAS 2,180 2,691 3,616 6,987 8,873 11,138 LPG 329 329 659 1,082 1,345 1,552 SUBTOTAL 17,647 24,695 30,138 32,107 34,343 36,378 ONSHORE 0E 0OIL 6,902 7,680 8,280 9,360 10,00 10,560 NATURAL GAS 273 360 411 467 477 497 CON06OITE VAX ETC 24 30 30 30 30 30 LPG - - 33 106 134 134 SUBTOTAL 7,199 0,070 8,754 9,963 10,721 11,221 TOTAL REVENUES 24,846 32,765 38,892 42,070 45,064 47,599 ENERGY OEPART S010T PETROLEUM PROJECTS DIVISION I - 93 - ANNEX 6.2 Page 5 of 14 INDIA OIL AND NATURAL GAS COMMISSION SALES TAX /ROYALTY /CESS COMPUTATION (MILLION RUPEES", 1982/83 1983/84 1984/85 1985186 1986/87 1987/88 QUANTITIES OFFSHORE CRUDE OIL(MILLION TONS) 12.11 17.34 20.69 19.+23 19.30 18.95 GAS (MILLION NM3) 1,639 176b40 2,336 4,658 5,?1' 70425 ONSHORE CRUDE OIL (MiLLION TONS) 5.80 6.40 6+90 7.80 8.1'0 3.8C0 GAS (MILLION HM3)8 900 900 1,028 1,168 14193 17243 TAX RATES (RS) ROYALTY-OFFSHORE CRUDE OIL (PER TON) 61 61 61 61 61 61 GAS (PER THOUSAND NHM3) 4 60 60 60 60 60 ROYALTY-ONSHORE CRUDE OIL (PER TON) 61 61 61 61 61 61 GAS (PER THOUSAND NH3).i 8 35 35 35 35 35 SALES TAX RATE(Xi CRUDE OIL 4 4 4 4 4 4 NATURAL GAS OFFSHORE 5.3 5.3 5+3 5,3 5+3 5.3 ONSHORE 10 10 10 1i0 10 10ft CESS (PER TON) CRUDE OIL 100 100 100 100 100 100 TAXES (MILLION RS) OFFSHORE 2,654 3,867 4,658 4,670 4,860 47998 ONSHORE 1,234 ,i394 1,506 1,704 1829 17916 TOTAL TAXES 3,888 5,261 6,164 6,374 6,689 6;914 ENERGY DEPARTMENT PETROLEUM PROJECTS DIVISION 1 - 94 - ANNEX 6.2 Page 6 of 14 INDIA OIL AND NATURAL GAS COMMISSION DEFRECIAl'ION SCHEDULE (MILL:nON RUPEES) 1982/83 1983/84 1984/85 1985/86 1986/87 1987/88 ONSHORE ASSETS AS OF 1.4.1982 485 470 491 501 507 369 ADDITIONS - DURING 82-83 756 336 327 443 134 306 DURING 83-84 - 1,329 561 542 756 743 DURING 84-85 - - 1,301 636 642 923 DURING 85-86 - - - 1,776 1,101 1,179 DURING 86-87 -- - - - 2,055 17570 DURING 87-88 - - - - - 3,203 TOTAL ONSHORE 1,241 2t135 2,680 3,898 5,495 B,293 OFFSHORE ASSETS AS OF 1.4.1982 19172 986 962 896 888 636 ADDITIONS DURING 82-83 3?274 1365 1,142 1,199 1,063 1,007 DURING 83-84 - 3,864 1,703 1,459 1,540 1,390 DURING 84-85 - - 10Y605 4,251 3Y360 2Y983 DURING 85-86 A/ - - - 2,595 1,553 1,430 DIURING 86-87 A/ - - - - 19470 1,062 DURING 87-88 A/ - - - - - 1,456 TOTAL OFFSHORE 4,446 6,215 14,412 10,400 9,874 9,964 A/ IT INCLUDES THE DEPRECIATION DUE TO THE SOUTH BASSEIN INLAND PIPELINE ENERGY DEPARTMENT FETROLEUM PROJECTS DIVISION 1 - 95 - ANNEX 6.2 Page 7 of 14 IND'IA OIL AND NATURAL GAS COMMISSION DEBET SCHEDULE YEAR ENDING MARCH 31is (MILLION RUPEES) 198/2/83 1983/84 1984/85 1985/86 1986/87 1987/88 LOCAL LOANS GOVERNMENT OF INDIA LOAN 2 'L.757. BEGINNING BALANCE 418 327 ?2'6 125 2o 3 DRAWINGS REPAYMENTS 91 101 101 105 17 3 BALANCE 327 22"6 125 20 3 - INTEREST 36 2'7 17 7 1 OIL INDUSTRY DEVELOPMENT BOARD LOAN 1 (4.5Z) BEGINNING BALANCE 774 691 608 525 442 359 DRAWINGS - - - - - - REPAYMENTS 83 83 83 B3 83 47 BALANCE 691 608 525 442 359 312 INTEREST 33 29 26 22 18 15 LOAN 2 (9.q75X) BEGINNING BALANCE 960 839 690 541 392 243 DRAWINGS - - - - - - REPAYMENTS 121 149 149 149 149 149 BALANCE 839 690 541 3921 243 94 INTEREST 88 74 60 45 31 16 LOAN 3 (102+5Z) BEGINNING BALANCE 711 711 831 529 427 325 DRAWINGS - - - - - - REPAYMENTS - 80 102 102 102 102 BALANCE 711 631 529 427 325 223 INTEREST 73 69 59 49 38 28 96 - ANNEX 6.2 Page 8 of 14 LOAN 4 (11.25%) BEGINNING BALANCE 400 400 400 343 286 229 DRAWINGS - _ _ _ REPAYMENTS - - 57 57 I7 57 BALANCE 400 400 343 286 229 1 72 INTEREST 45 45 '12 35 29 23 HYDROCARBONS INDIA LIMITED __________________________ HYDROCARBONS INDIA LIMITED BEGINNING BALANCE 285 285 285 285 285 285 DRAWINGS - - - - REPAYMENTS - - - - - - BALANCE 285 285 285 285 285 285 INTEREST 20 20 20 20 20 20 BEGINNING BALANCE FOR LOCAL LOANS 3,548 3,253 2,840 2,348 1852 1,044 ENDING BALANCE FOR LOCAL LOANS 39253 2,840 2,348 11852 1,441 1,086 - 97 - ANNEX 6. 2 Page 9 of 14 OFFICIAL DEVELOf'MENT AID GOI (WORLD BAN K) LOAN (14,?-I) (10.225Z) BALANCE 1,1 910 ,O39 ? :7 895 3 752 DRAWINGS REPAYMENTS 71 7 72 72 71 72 BALANCE 17039 967 895 823 752 6BO INTEREST 110 103 95 88 85 77 LOAN (1925-IN) (10.75%) BEGINNING BAELANCE 1,993 35600 35600 3?600 3,600 35360 DRAWINGS 1,607 - - - REPAYMiENTS - - - 240 240 BALANCE 35600 3,600 3,600 35600 35360 3, 12 INTEREST 300 387 387 387 374 348 KG LOAN (9205-IN)(12Z) BEGINNING BALANCE - 239 834 I1369 1,490 1r490 DRAWIINGS 239 595 535 121 REPAYMENTS - - - - BALANCE 239 834 1I369 1,490 1!490 1,490 INTEREST 14 64 132 172 179 179 PROPOSED LOAN (S-E) (12Z) BEGINNING BALANCE - - 12'00 25000 '2,000 2000 DRAWINGS - 1 200 800 - - - REPAYHENTS - - - - - - BALANCE - 1,5 200 2_000 2000 2Q000 2JO00 INTEREST - 72 192 240 240 240 KUWAIT LOAN ( 1IZ) BEGINNING BALANCE - - 234 441 450 450 DRAWINGS - 234 207 9 - - REPAYMENTS - - - - BALANCE - 234 441 450 450 450 INTEREST - 14 41 53 54 54 -~ 98ANNEX 6.2 Page 10 of 14 OPEC LOANS LOAN 1 t10t25Z) BEGINNING BALANCE 111 104 97 90 83 76 DRAWINGS REPAYMENTS 7 7 7 7 7 7 BALANCE 104 97 90 83 76 69 INTEREST 10 10 9 9 8 7 LOAN 2 (10.75%) BEGINNING BALANCE 149 270 270 270 270 252 DIRAWINGS 121 - - - - - REPAYMENTS - - - - 18 18 BALANCE 270 270 270 270 252 234 INTEREST 16 29 29 29 28 27 MHS. OFFSHORE ENTERPRISES (5.375%) (KFW) BEGINNING BALANCE _ 198 198 198 190 174 DRAWINGS 158 - - - - - REPAYMENTS - - - 8 16 17 BALANCE 198 198 198 190 174 157 INTEREST 11 11 11 10 10 9 BEGINNING BALANCE FOR O.D.A LOANS 3,363 5,450 71400 8,863 8,90b 8,554 ENDING BALANCE FOR O.D.A LOANS 5,150 7,400 8,863 8,906 8,554 8,200 - 99 - ANNEX 6. 2 Page 11 of 14 EXIM FINANC?NC EXI'i UtP CREDIT' 5.75 BEOIrK}WiN. iALANCE 120 12,0 120 105 75 : ~ ~ ~ ~ ~ ~ 2 - - . - -i - -c F k k - . S S ' - 2 15 _ l3r 30 BALANCt!vE 12,0 12)0 1210 105 75 45 INTILEREST. 9 10 lt 9 8 5 EXIM JAPAN (7.5%) BEEGINNING BALANCE 125 98 71 44 17 DRAYI~NGS REP AYMENTS 27 27 27 72 BALhAilCE 98 71 44 17 INTEREST 9 d 3 2 EXIM CREDIT (5.82) JAPAMN (;D,B) BEGINJNIN, ;,BALANCE - 2 9 REPAYMEN'TS 2 3 3 4 2 CLOSING BALANCE 12 9 6 2- INTEREST i 1 1 I 5KSjv PLATFFORMS FRENCH EXPORT CREDIT s10.SYK) BEGINNING BA,LPNICE - - 146 l97 171 145 DRAWINGSl - 146 64 - - - REPI',MENTS - - 13 26 26 26 BALANiCE - 146 197 171, 145 119 INTEREST - 21 19 17 14 KOREAN EXIM BANKIITARLIhAN C REDTIT(I0) BEGINNING BALANCE - - 758 663 568 473 DRAWiMiGS - 758 - - - - RP;AYJMENTS - - 95 5 95 95 BALANCE - 758 663 568 473 378 INTEREST - 38 71 62 52 42 KOREAN ESIN BANK (I0%) BEGINJNIG BALANCE - 15i 171 150 12,9 108 DRAWIN.G, S 11 20 - - - - REPAYMENTS - - 21 '1 21 21 BALANCE 1s51 17i 150 1129 108 87 INTEREST - 17 l6 14 12 10 BEGINNING BALANCE FOR EXIMP LOANS 125 381 1,.275 sriO ?92 801 ENDING BAL;iMCS FOR EXIM LOANS: 381 1,27,5 17180 ?992 801 62-9 - 100 - ANNEX 6.2 Page 12 of 14 COMMERCIAL LOANS MHS. ROBIN SHIPYARD (11+75%) BEGINNING BALANCE 99 396 347 297 248 198 DRAWINGS 297 - - - - REPAYMENTS - 49 50 49 50 49 BALANCE 396 347 297 248 198 149 INTEREST 29 44 38 32 26 20 CONSORTIUM JAPAN(7.5%) BEGINNING BALANCE - 126 98 70 42 14 DRAWINGS 190 - - - - REPAYMENTS 14 28 28 28 2s8 14 BALANCE 1-26 98 70 42 14 - INTEREST 5 9 7 5 3 1 MHS. ANKERLOKHEN, NORWAY (8.5%) BEGINNING BALANCE - 270 238 206 174 142 DRAWINGS 270 - - - - - REPAYMENTS - 32 32 32 32 32 BALANCE :270 238 206 174 142 110 INTEREST - 22 19 16 13 11 BNP PARIS (8X) BEGINNING BALANCE - 149 131 113 9 77 DRAWINGS 149 - - - - - REPAYMENTS - 18 18 18 18 18 BALANCE 149 131 113 95 77 59 INTEREST 12 11 10 8 7 5 HITACHI FORUM (8%) BEGINNING BALANCE - 357 313 269 225 DRAWINGS - 379 - - - - REPAYMENTS - 22 44 44 44 44 BALANCE - 357 313 269 225 181 INTEREST - 29 27 23 20 16 BEGINNING BALANCE FOR COMMERCIAL LOANS 99 941 1,171 999 82r8 656 ENDING BALANCE FOR COMMERCIAL LOANS 941 1,171 999 828 656 499 - 101 - ANNEX 6.2 Page 13 of 14 EURO LOANS LOAN I (US $ 50 MILLION) BEGINNING BALANCE 300 200 100 DRAWINGS - - - REPAYMENTS 100 100 100 BALANCE 200 100 - - - - INTEREST 45 27 10 - - - LOAN 2 (US $200 MILLION) BEGINNING BALANCE 1,640 1,640 1,312 984 656 328 DRAWINGS - - - - - REPAYMENTS - 328 328 328 328 328 BALANCE 1,640 1,312 984 656 328 - INTEREST 324 292 227 162 97 32 LOAN 3 (SINGAPORE) BEGINNING BALANCE 68 270 270 216 162 108 DRAWINGS 202 - - - - - REPAYMENTS - - 54 54 54 54 BALANCE 270 270 216 162 108 54 INTEREST 30 48 44 34 24 15 LOAN 4 (EURO-YEN) BEGINNING BALANCE - 216 216 216 216 216 DRAWINGS 216 - - - - - REPAYMENTS - - - - - 40 BALANCE 216 216 216 216 216 176 INTEREST 39 39 39 39 39 35 LOAN 5 (EURO-YEN) BEGINNING BALANCE - - 272 272 27? 272 DRAWINGS - 272 - - - - REPAYMENTS - - - - - 39 BALANCE - 272 272 272 272 2'33 INTEREST - 49 49 49 49 45 BEGINNING BALANCE FOR EURO LOANS 2,008 2,326 2,170 1,688 1,306 924 ENDING BALANCE FOR EURO LOANS 2.326 2,170 1F688 1,306 924 463 - 102 - ANNEX 6.2 Page 14 of 14 FUTURE BORROWINGS il-i j BEGINNING BALANCE - 1,200 10,100 16 500 255510 3atO9O DRAFWINGS 'J200 8r?00 69400 9,250 9,600 1,400 REPAYMENTS - - - 2140 2020 37300 EBLANCE 17.'00 i0-100 161500 25,510 33,90 31,I90 INTEREST 84 7°1 1,S62 2,941 i 0 2 ,710 OF-ENING BALANCE 9:1i13 13,55i 24,956 317578 39i39'' 15f469 EDRAWINGS 5T2,, 12,504 80o06 9,*380 9?,600 4,o00 REFAYMENTS 656 1r099 i, 384 1,564 .5.25 1r802 CLOSING BALANCE 13,551 24,956 31,578 39,93?1 i45,69 45,,067 TNTEREST 1,313 2,387 3,575 4r581 5,585 6,001 ENERGY DEPARTMENT PETROLEUii PROJECTS DIVISION i , 1 . 21 '83 10A4'f58 INDIA SOUTH BASSEIN OFFSHORE GAS DEVELOPMENT PROJECT PROJECT FINANCIAL RATE OF RETURN AFTER TAXES IN MILLION OF END 1982 RUFEES BASE CASE GUANTITIES GAS.PROD NGL PROD REVENUS CAPITAL FIXED VAR TOT.OP SALES ROYALTY DEPR TAXES TOT.COSTS NET (MILLION CM) 000.TONS COSTS COSTS COSTS COSTS TAX BENEFITS (FOR IRR) 1982/83 - - - - - - - _ 1983/84 - - - 3,340.76 - - - - - - - 3,3.0.76 (3,340.76) 1984/85 - - - 2,054.72 - - - - - - - 2,054,72 (2,054.72) 1985/86 1,497 233 2,932 335.50 229.24 269.37 498.61 155.40 89.79 270.00 1,081.86 2,161.16 770.84 1986/87 1,825 283 3,574 - 458.48 328.50 786.98 189.42 109.50 286.55 1,241.67 2,327.57 1,246.43 1987/88 1,825 283 3,574 - 458.48 328.50 786.98 189.42 109.50 286.55 1,241.67 2,327.57 1,246.43 1988/89 1,825 287 3,581 - 458.48 328.50 786.98 189.79 109.50 286.55 1,245.41 2,331.68 1,249.32 1989/90 1,825 287 3,581 - 458.48 328.50 786.98 189.79 109.50 286,55 1,245.41 2,331.68 1,249.32 1990/91 1,825 287 3,581 - 458.48 328.50 786.98 189.79 109.50 286.55 1,215.41 2,331.68 1,249.32 ° 1991/92 1,825 289 3,585 - 458.48 328.50 786.98 190.01 109.50 286.55 1,247.55 2,334.04 1,250.96 1992/93 1,825 289 3,585 - 458.48 328.50 786.98 190.01 109.50 286.55 1,247.55 2,334.04 1,250.96 1993/94 1.825 291 3F589 - 458.48 328.50 786.98 190.22 109.50 286.55 1,249.68 2y336.38 1,252.62 1994/95 1,825 294 3,596 - 458.48 328.50 786.98 190.59 109.50 286.55 1,253.42 2,340.49 1,255.51 1995/96 1,825 294 3,596 - 458.48 328.50 786.98 190.59 109.50 286.55 1,253.42 2,340.49 1,255,51 1996/97 1,825 294 3,596 - 458.48 328.50 786.98 190.59 109.50 286.55 1,253.42 2,310.49 1,255.51 1997/98 1,825 294 3,596 - 458.48 328.50 786.98 190.59 109.50 286.55 1.253,42 2,340.49 1.255.51 1998/99 1,825 294 3,596 - 458.48 328.50 786.98 190.59 109.50 286.55 1,253.42 2,340.49 1,255.51 1999/2000 1,825 294 3,596 - 458.48 328.50 786.98 190.59 109.50 286.55 1,253.42 2,340.49 1Y255.51 2000/2001 1.825 294 3,596 - 458.48 328.50 786.98 190.59 109.50 286.55 1,253.42 2,340.49 1,255.51 2001/2002 1,825 294 3,596 - 458.48 328.50 786.98 190.59 109.50 286.55 1,253.42 2,340.49 1,255.51 2002/2003 1,825 294 3,596 - 458.48 328.50 786.98 190.59 109.50 286.55 1,253.42 2,340.49 1,255.51 2003/2004 1,825 294 3,596 - 458.48 328.50 786.98 190.59 109.50 286.55 1,253.42 2,340.49 1,255.51 2004/2005 1,825 294 3,596 - 458.48 328.50 786.98 190.59 109.50 286.55 1,253.42 2,340.49 1,255.51 RETURN ON INVESTMENT = 18.832Z NOTE: FIXED COSTS AT 8Z OF CAPITAL COSTS AND VARIABLE COSTS AT RS.180 PER THOUSAND CUBIC METER OF GAS THE PRICE FOR GAS IS W/THOUSAND CM 1,648 THE PRICE FOR NGL IS 5/TON 2,000 - 104 - ANNEX 6 4 INDIA SOUTH BASSEIN OFFSHORE GAS DEVELOPKENT PROJECT PROGRAM FINANCIAL RATE OF RETURN AFTER TAXES RS MILLION (END 1982 PRICES) BASE CASE t½U35CTiCNi . TOTAL C2 ' -J EAN NGL. LPG C2/C3 PROJECT PLATFORM L.P.SG 02/03 2(77<. 02!E' ROYiTAX TOTAL CASH PLOW D1i GEAS iB) OOO.TON OOd.TON 00O.CM INVEST. PIPELINE PLANTS PLANTS - - - - - 3,341 - 315 - -- - - 766 (3!656) i - - 2 - 2,055 2i880 675 - - . 234 5,944 S 598444 i8.5186 . . ','4 1,650 433 248 - 6YO80 336 3,465 675 - 5/4 482 3r543 8,579 (2,499) :3- )!/87 -.l i 2iG99 661 375 - 9,407 - 2,610 675 180 307. 739 5,134 9,408 (1) *7/E -(7334 935 482 - 12,739 - 675 405 360 l7.__ 937 6F250 8,825 3,914 .3 ,682 17304 673 34 16,217 135 199 1,029 7,718 9,347 6F870 :-'./9 0 9S .6 2,684 1,314 678 54 15,107 - - - '-9' 1li07 65307 9?124 5,953 t ;RjO/v A j 6S ^2;333 1!314 678 81 1469 6 7 2:57 1S 107 6r076 8S893 5r804 - 2 - s / 3 ^ 9 C O y1971 1,323 678 107 14,288 - 3 11 07 5S845 B,662 5,626 . 2 .37 5 ,704 1,323 678 134 13,979 2317 17107 5Y671 8i488 5,491 '3/9 14445 1,138 678 134 13,693 - - _ 450 27953 1,107 5,489 8,792 4r901 4 1 - 5si 13226 1,357 678 134 13,464 - - - 720 2;:91 17040 5Y366 8t996 4 ,468 ~/9 5/76-59'26Z 183 1r357 678 235 1 1407 360 rC 972 49228 7,527 3,880 .70 6/97 5379- 17357 678 295 11,220 2 9 .- 1 *058 4,074 .7,013 4r207 :.97/91 52 90 - 1Y357 678 376 1 1 r 272 - - - - 2 9; 990 4,141 7 , 080 4,192 :. 9 / 9 0 1 ' I - 1,353 678 456 11,313 A - 9 2 403 71412 4,171 . i9DZ2¢ ¢su i7 ''- 1,349 678 537 11,357 - - - - 6 9) 4,22 7,167 4190 . 13346 678 537 11,351 _ - - 22 . 4224 7.163 4,188 - dlJ¢,2 -. 1,7;. 2 1;342 678 537 11343 - - - _4 922 4220 7Y159 4,184 )2/ 7- 1 1338 678 537 11335 . 92 4 , 2 15 7154 4.iR1 - 1J334 678 537 11,327 - . - 92' 421l1 71150 4 , 1 77 t) 4/f0i5 57112 - 1,331 678 537 11,321. - - - - 2 9 22 At207 7,146 4,175 iTURN 7 INVESTHERNT = 26.05 1 P P1C0 OF 08i-3 SOLD AS FEEDSTOCK.RS/THOUSAND CM 1,241 2);F iPfi 2A45 SC1 DS FUEL(FUEL OIL REP.) RS/000 CM 2,461 ') EST TTcER ;TCE OF NEL' RS/THOUSAND CM 2,000 URRN'T PRICE OF L'P92RS/TON 17830 -ESTi'.-ATE RRICE DF 22/Cl3: RS/THOUSAND CP 2,OO 7i . TG ? ECTS 170,jjGN1 ((RO) - 105 - AENEX 6 5 INDIA SOUIT BASSEIN GAS DEVELOPMENT PROJECT SENSITIVTTY ANALYSES -- FINANCIAL RATE OF RETUIRN % Financial Ra e of Return after Taxes Cases Project _ Program - 3ae C-asa 18.8 26.0 z, Car.ta1 Costs Up 20% 15.5 21.2 3 GC-ask TPC, etc. Prices Down 20% 14.2 19.9 4. Prciec Delayed One Year 16.8 22.0 Conmbination of 2, 3 and 4 104 13.6 6D Gas, LPG, etc., Prices Down 25o__/ 14.0 7i 2as. LPG, etc. Prices Up 23.0 31.8 . .CaDital Costs Down 20% 23.5 32.6 -'! For the case of the project only, the rich gas (i.e., before LGP and C2/C3 are extracted) at the Hazira Terminal and the NGL extracted at the process platform and the terminal are the products. Two thirds of the gas is sold as feedstock (Rs 1.241/cm) and the rest as fuel (Rs 2.461/cm) in the Base Case bi This is equivalent to the case where all the gas is sold as feedstock. Energy Department January 1983 - 106 - ANNEX 7.1 INDIA SOUTH BASSEIN OFFSHORE GAS DEVELOPMENT PROJECT Documents Available in the Project File Ine Oil and Nacural Gas Commission Act, September 18, 1959 Ull anUd Natural Gas Commission sive Year Plan (19bu-65) (ievised) Project Preparation Reports (Novemuer 1961 and June 1962J Consultants McCord and Associates - South Bassein Field Initial Development Study, August 1980. Snamprogetti - Project Report on South Bassein-Hazira Gas Pipeline, July 1982. Earl and Wright - South Bassein F:ield Conceptual Design Development Plan, August 1980. A.H. Clenn & Associates - Meteorological-Oceanographic Conditions Affecting Offshore Petroleum Operations in the Bassein Area, October 1976. IBRD 16183 7O| ° .J N 't BO° EO° JULY 1982 I NDIA DEM. REP. OF I'-- JAMMU \ OIL AND NATURAL GAS SECTOR AFG HAN I STAN < * - - JPPtPdipte sp'd'T L RECENT OIL GAS DISCOVERIES AFGHANISTAN < XXSApb~b YIOIL/ GAS FIELDS (_ . a na d )A dpOX by Ind;U EXISTING PRODUCT PIPELINES EXISTING CRUDE PIPELINES KASH MIRB EXISTING REFINERIES f ,_ PET GLEUM 'PSODUCTS DISTRIBUTION ZONAL SOUNDARIES HI CHA A.,-... 8rd, @ o NATIONAL CAPITAL, CITIES AND TOWNS J-vo ./ t PRADESH > a n~~~~~~~~~~1dk-ad by Od- - STATE AND UNION TERRITORY BOUINDARIES IL - Jullund 1. -*- INTERNATIONAL BOUNCIARIES PAKISTAN ChaIdigorh P0A/JB DEhrO: Gun <, H I N Bordv D.n /n,bola 0D kEWC H I N A by yfb,a HARYANA ~~DELHI OPA~n oy UTTAR ~~~~~NEPALDi to, R A J A 5 r H A N >&lD~~~lc " k ,y BHUTANv xC Yi -A-7 .., t,',~a.. t NORTH /,>7 <,,w S ;_.SIliguri/3~~~~~~~~~~~~~~~l- ARUN/ACH/AZ 7 Mathuro BR~~~A DES RAJASTHAN~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~Skty GIIRONI .....SIig-P/Bongaigaon 8L.SA ~ ARNACA EAS W T l W . gX ~~MAHARASHTRA HPC) Bomb y PC ; 7 S /Ba<7y of~~~~~~~~~~~o so ' V wkh t sos Bengal o C1chin ICRL ______________ydwob_d t c,/ t ) NDHRA ,p 9 g ) 4 R~RADESH RIVA 7A KARI ANK N NO 6 ,ROS E 0 80IOTR THMc lru cTskp t> EenguloneO 4~~ M LA 1 fw 5 g @%~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~r Ar aba _ _ t \\ 70!09 m!Jo 711oo 7l!30 200 {0 7213o c ,/ IP3RD 16184~~~~~~~~~~~~~~~~~~~~~~~~IRD 618 \ \20 \" G U J A R A Gopnplb, ,__ a H.3aiV G U J A R A T~~~~~~~~~~~~~~~~~ U A A 21'00\~~~~~~~~~~~ , i A R Albr Touu 3m 1G SOUTH BASSEIN OFFSHORE GAS iE*<,= X\ j r4f :QfW:°lm. DEVELOPMENT PROJECT \\ o e BOMBAY OFFSHORE AREA -- 7 -15Q \ \: W>SIt1.-". P oletoil -nd/or G-s 3sr-e \>{> >2-J P-., 00enO Re2erve (-r sorrd Gos ;-' /J 'U Prp-e Noli rlG.- R-s1- s \:/ i:\ Aso * Pmi-c Fo-r T-rm-1 *2 F-hh-I6S PI-n Und., C-n,-ucl-n\ 0 N.;-c Pl,.-2 PlPlf r O Fuu- Proces Pbpff.2: : f- -- E -Ismi301nchC,.d.0il Rw2l-p\ \ -~-EgistE 26 n-hrRN.1-O G.~P,I-iem ^~DAH*AN/U I ,~ Nh j- sb .. 1- '.f7A/P/?IS, i -10-- ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ , SMSTUCURCTURE 8 ,; X . / 50UJHbXfTST Wto ~ ~ ~~~~~~~~~~~~~~~~I v ; z 1\.*~~~~~~~~~~~l6, F(B-37sA \)r \\|' ';20 a% I 1 ) ; A U a l 7 0 1 2 0' \ \ | rl, D rl\ 7 1 1 91 7 ? ; 9 9 X 7 2|3 D ' } \ A r G n o _R U