India - Krishna - Godavari Petroleum Exploration Project

Document of The World Bank FOR OFFICIAL USE ONLY Report No. 3887a-IN STAFF APPRAISAL REPORT INDIA KRISHNA-GODAVARI PETROLEUM EXPLORATION PROJECT September 10, 1982 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. I  CURRENCY EQUIVALENTS Currency Unit = Rupee (Rs) Rs 1 Paise 100 US$ 1 = Rs 9.0 Rs 1 = US$ 0.11111 Rs I 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) 3 0.62 Miles 1 Cubic Meter (m3) = 35.3 Cubic Feet (cft) 1 Barrel (Bbl) = 0.159 Cubic Meter 1 Metric Ton of Oil (390 API) = 7.60 Barrels 1 Normal Cubic Meter (NmJ) = 33.42 Standard Cubic Feet of Natural Gas 1 Kilocalorie (kcal) = 3.97 British Thermal Units (Btu) MW = 1,000 kilowatts kWh = kilowatt-hour 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 tpy = Ton per year PRINCIPAL ABBREVIATIONS AND ACRONYMS USED BOP - Bombay Offshore Project CFP - Compagnie Francaise des Petroles D-P - Dynamically Positioned GOI - Government of India IOC - Indian Oil Corporation LPG - Liquefied Petroleum Gas OIDB - Oil Industry Development Board OIL - Oil India Limited ONGC - Oil and Natural Gas Commission WGEP - Working Group on Energy Policy FISCAL YEAR April 1 - March 31  FOR OFFICIAL USE ONLY INDIA KRISHNA-GODAVARI PETROLEUM EXPLORATION PROJECT STAFF APPRAISAL REPORT Table Of Contents Page No. I. THE ENERGY SECTOR..........................................1 Background .......... , . ................... 1 Energy Supply and Consumption. 2 Energy Resources. 6 Energy Prospects. 8 II. THE PETROLEUM SUBSECTOR. 9 Introduction .. 9 Petroleum Consumption, Production and Prices. . 9 a. Consumption and Production Trends. 9 b. Pricing Policies .11 Petroleum Resources, Past and Future Development 12 a. Petroleum Resources .12 b. The Role of the Private and Public Sectors in the Development of India's Petroleum potential .13 c. Development Prospects and Investment Strategy 15 The Bank's Role and Lending Strategy in the Petroleum Subsector ..17 III. THE PROJECT .19 Introduction .19 Exploration Activity in the Krishna-Godavari Basin 20 The Project .21 a. Objectives .21 b. Description .22 Execution .23 Implementation Schedule .25 Estimated Cost .25 Items Proposed for Bank Financing .27 Financing Plan .28 Procurement and Disbursements .30 Ecology and Safety .31 This report is based on the findings of a mission that visited India in November 1981 and was prepared by Messrs. T. Fitzgerald, D. Carpio, K. Palmer, and Ms. S. Lazar of the Energy Department, J. Wall of the South Asia Country Programs Department, and M. Heitner (Consultant). 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.  - ii - Table of Contents (Cont.) Page No. IV. PROJECT RISKS AND JUSTIFICATION .......................... . 32 V. THE OIL AND NATURAL GAS COMMISSION. .. ... 34 General...... 34 Organization and Management ..... 34 Staffing and Training....... 35 Management Information Systems .... . .35 Accounts and Auditt........ 36 Insurance..... 36 ONGC's Investment Program (1982/83 - 1987/88) . .36 VI. FINANCIAL ASPECTS. 38 Introduction ....... 38 Past Performance ....... 38 Financial Prospects ....... 41 VII. AGREEMENTS REACHED AND RECOMMENDATION ......43 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 Geology of the Krishna-Godavari Basin 3.2 Implementation Schedule 3.3 Project Cost Estimate 3.4 Details of Cost Estimate 3.5 Phasing of Expenditures 3.6 Disbursement Schedule 4.1 Economic Analysis 4.2 Comparison of Original ONGC Project Scope and Project Agreed with the Bank 5.1 Organization Chart - ONGC 5.2 Organization Chart - Madras Division 5.3 ONGC-s Investment Program 6.1 Financial Tables 6.2 Assumptions Underlying Financial Projections 7.1 Documents Available in Project File MAPS IBRD 16185 and 16186 R  I. THE ENERGY SECTOR Background 1.01 Commercial primary energy (coal, oil, gas, h Yro and nuclear) accounts for about 46% of total primary energy supply- in India, with the 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 relatively 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 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 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 - largely unexplored. Therefore, the exploration for new, and development of existing, petroleum reserves is one of India's most pressing priorities. 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 over the next three to four years, will be a key factor in determining whether indigenous hydrocarbon supplies can be increased sufficiently above current forecasts to meet a major portion of the anticipated growth in demand during the present decade. Energy Supply and Consumption 1. 5 In 1975/76 (the last year for which overall figures are available), prirmary 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 oll equlvalent)A/ 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 & lignitek1 27.8 37.1 50.6 58.2 63.7 2.9 4.7 Petroleum c/ 7.9 19.0 24.1 34.7 38.7 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 83.3 104.8 116.1 5.2 5.3 Noncommercial Primary Energy :5 Firewood 48.8 57.8 65.2 N.A. N.A. 1.7 2.5 -/ 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 74.0 87.6 98.9 N.A. N.A. 1.7 2.5 e/ Total 111.6 150.3 182.2 N.A. N.A. 3.0 3.9 e/ a/ Based on the following conversion factors: one ton of oll equlvalent (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. c/ Natural gas excludes quantities flared and used In field operations. d/ About 94% hydro power and 6% nuclear power in 1980/81. The figures are gross power generation. e/ Growth rate from 1970/71 to 1975/76 only, Is assumed for the 10-year period. f/ Non-commercial energy figures are for consumption which are taken as equal to supply.  - 4 - 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 (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, Chemicals and Fertilizers; 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  - 5 - by the use of liquid fuels (mainly diesel oil) and electricity. Commercial 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 indus'ry 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 11 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 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).  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 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 by 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 l/ 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, with an output three times that of any other developing country. 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 1/ A detailed review of the coal sector is contained in the Bank report India-s Coal Sector, April 1982 (Report No. 3601-IN).  - 7 - 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 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 basic 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 relating 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  - 8 - 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 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 this 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  - 9 - 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. 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 Much of India's potential petroleum-bearing areas are still relatively unexplored and production is concentrated only in a few regions. Historically, the pace and scope of exploration activity has been uneven and scarce resources have had to be concentrated on a few promising areas. Since the discovery and development of the giant Bombay High Field off the West Coast of India in the mid-1970s, India has not established any new major commercial discovery. Ongoing exploration efforts of ONGC, however, have been encouraging and have identified several petroleum-bearing areas which need further exploratory drilling to determine their commercial potential. With production from presently known oil reservoirs able to meet just under one- half of the expected demand by the end of the decade, the Government of India has recognized the urgency of accelerating the pace of petroleum exploration and has adopted new policies to bring this about. 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  - 10 - 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 0.6 million toe of gas by 1984/85, rising to 6 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/ 1981/82 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 ImportsE./ 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 3.40 5.34 8.61 Less: Field Uses N.A. 0.16 0.26 0.21 0.29 0.52 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 1.88 4.21 7.05 Total Petroleum Consumption (million toe) N.A. 19.31 33.01 34.74 38.66 50.12 70.75 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. 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, consumers are far away, making it uneconomic to utilize the small quantities  - 11 - produced. The role of gas as an energy resource is therefore minor so far, with consumption in 1981/82 at only about 2.3 billion Nm3 (1.9 million toe), equivalent to 1% of commercial primary energy consumption and 5% of crude oil consumption. With the development of the South Bassein gas field just about to begin (1982/83-1984/85), 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. 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 2.02 2.83 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. Taxes and royalties on crude oil and its products constitute substantial sources of revenues for the Government of India and State Governments. In 1979/80, GOI received through excise duties, customs duties, corporate income taxes, dividends, cess and royalties on offshore oil altogether Rs 20 billion (US$2.2 billion). In addition State Governments receive a royalty and a sales tax on onshore oil, but overall proceeds are not known. 2.08 Natural gas, unlike crude oil, is sold directly by the producers (OIL I/ 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.  - 12 - 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 consumer 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. 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 a satisfactory 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. 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 1.72 million km2 of which aboumillion km2 (81%) is onshore with the remainder, offshore (to a water depth of 200 meters). Commercial petroleum production has been established in only two sedimentary basins. The first is the Assam-Arakan basin in parts of Assam and extending to Nagaland, Meghalaya, Tripura, Manipur and Mizoram in the eastern part of the country. The second is the Cambay basin comprising an area in Gujarat and also including the Bombay High offshore fields. However, indications of petroleum have been found in six other basins: Konkan, Krishna-Godavari, Cauvery, Rajasthan, Andaman Islands and the Tripura fold belt. The Ratnagari oil field in the Konkan basin is being developed and is expected to start production in late 1982. The Krishna-Godavari and Cauvery basins are by far the most promising new areas today with the Krishna-Godavari particularly standing out as the next likely major discovery after Bombay High. Magnetic and gravimetric surveys have been undertaken for most of the potential petroleum bearing areas. However, the more critical 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  - 13 - probable reservesi/ 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, Chemicals and Fertilizers. 2.11 The long-term view 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 many 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 very 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 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.  - 14 - 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, ONGC1/ 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 Galeki (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 2a 25% GOI interest, was signed, providing for an exploration area of 10,000 km 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 because the results were discouraging. 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 activities, the Government decided to actively promote open areas for exploration by forei n firms. Thirty-two blocks, each ranging in size from 10,000 to 30,000 km 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 want and 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 1/ ONGC-s organization is reviewed in Chapter V.  - 15 - 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. contiguous to producing areas). One production-sharing agreement2has so far been signed with a consortium led by Chevron (USA) for an 18,500 km block 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 is expected to start 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. The second offering includes 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 that 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, 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 Arunchal Pradesh. The company has explored its licensed 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, Chemicals and Fertilizers 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. 16185) describes 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: to increase production from existing fields, primarily by accelerating development programs by ONGC and OIL in areas where petroleum has  - 16 - already been discovered; to accelerate exploration for yet undiscovered resources both by the national and foreign oil companies; to modernize the existing refineries and construct new ones; and 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 development of Bombay High, the development of the offshore South Bassein gas field and further exploratory drilling in the 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 d:^bu., 2;clities as well as investments for downstream processing plants (e.g. fertilizer ind 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: 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--3/4/85 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.  - 1 7 - 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. Two loans have been made to ONGC (US$550 million total) for the development of the Bombay High field, 1/, and a US$200 million loan was made in April 1982 for the modernization of several refineries2/. 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 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 have been carried out in accordance with industry practice before the huge development program was launched. Subsequently GOI requested Bank financing for the Bombay High development. The development of that field has proceeded largely according to plans, with ONGC implementing 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 supplement ONGC-s own capabilities. A Project Performance Audit Report for the first Bombay High Project is currently being reviewed by GOI and will be submitted to the Board during the last quarter of 1982. 2.24 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 formulation and 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 1/ Loan No. 1473-IN approved in June 1977, and Loan No. 1925-IN approved in December 1980. 2/ Loan No. 2123-IN approved in April 1982.  - 18 - and ONGC to seek external commercial financing for the Bombay High development. The first Eurodollar borrowing (US$50 million) was obtained in 1977 with highly favorable terms in connection with the first Bombay High Project, 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 advise and catalytic role in securing commercial financing. More recently, GOI adopted a policy of using ONGC as a privileged vehicle for commercial financing; under a new policy, all eligible items put to competitive bidding are offered with a request for commercial financing proposals (para. 3.18). Under this new policy, ONGC has obtained, so far during 1982/83, about US$245 million of commercial loans/credits. Thus ONGC is currently one of the largest Indian borrowers on the international capital markets. 2.25 While ONGC has acquired considerable expertise in offshore 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 primarily on those areas were 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 to finance its investment requirements from foreign commercial loans/credits, as discussed in paras 3.18 and 6.11; the Bank will continue to encourage GOI and ONGC to increase recourse to foreign commercial borrowing. 2.26 During the 1980's, the complexity and scope of ONGC's operations will continue to increase as more efforts will have to be devoted to exploration, while the pressure for accelerated development of known fields is unlikely to diminish. ONGC is about to embark on the first large-scale gas development project in India involving the South Bassein offshore gas field. This project presents new challenges concerning the project design and the development of a market for natural gas, whose use at present is very small. Since 1980, the Bank has been discussing with the Government the potential supply and alternative uses for gas. 2.27 With regard to oil exploration, India's policy of having parallel efforts by national and international oil companies is fully justified and is well focused. During the preparation of the proposed Project, the Bank had two primary objectives. The first is to support India's accelerated exploration strategy. As part of this, the Bank is helping to implement the "open door" policy which India has recently adopted and also to promote and undertake exploration efforts. Through the Bank's involvement (since 1980) in the conceptual design and preparation of the proposed Krishna-Godavari Project, it has helped the Government undertake the initial steps towards a larger and more immediate role for the private sector in petroleum exploration. In the case of the previous international offering of exploration acreage (para 2.15), the Government, after discussions with the Bank, increased the average block size, and furthermore, added blocks to the offering. Two of these blocks attracted all the bids received. The Bank also  - 19 - provided advice to ONGC and GOI regarding (i) approach to negotiations with foreign oil companies; (ii) contractual matters (e.g., fiscal terms, minimum work program, form of GOI/ONGC participation); and (iii) monitoring of the foreign oil companies exploration and development activities after contracts have been signed. More specifically, Bank staff provided information and comments about standard international practices related to production-sharing agreements and minimum work commitments which helped the Government formulate contract terms in line with industry trends. The Bank intends to continue providing such informal technical assistance in the future, as requested by the Government. 2.28 The second Bank objective concerning exploration is to improve the quality, in terms of both design and implementation arrangements, of large exploration projects in the country through Bank support or advice. The Krishna-Godavari Project is important in this regard since it constitutes approximately one-quarter of ONGC-s exploration efforts over the next three years. Following discussions with the Bank, ONGC agreed to: (i) concentrate the exploration efforts on a smaller area and scale down the project size reflecting both ONGC's technical capabilities and economic considerations; (ii) reduce the considerable risks in the drilling program by introducing technical assistance, experienced foreign contractors and technical precautions; and (iii) improve the cost effectiveness of the project by maximizing the use of information through an integrated onshore, inner-shelf, outer-shelfl/ geological evaluation and by introducing a balanced drilling program in these three environments in terms of potentially large discoveries with high cost and technical risks on one hand, and potentially modest discoveries with lower cost and technical risks on the other hand (para 4.05). III. THE PROJECT Introduction 3.01 The Krishna-Godavari basin, located on the east coast of India about 375 km north of Madras, has the potential to become a major new oil province. The principal geologic feature of the basin is a very thick deltaic sequence resulting from the seaward progradation (outbuilding) of the ancestral Krishna and Godavari river systems. On the basis of present information the basin is known to contain good source rocks and reservoirs and numerous well defined structures. The stratigraphy and structure of the basin resemble those of a 1/ The offshore margin of a continent is subdivided into the Continental Shelf (coastline to approximately 200 m isobath) and the Continental Slope and Rise (from edge of shelf to deep ocean abyssal plan, at depths usually of, 3000 m or more). In this report the term outer shelf refers to the offshore area from about 165 m water depth to the very upper part of the slope at 300 m water depth. The term inner shelf refers to the offshore area in less than 165 m water depth. This subdivision is convenient since it indicates different offshore drilling conditions and equipment required, as well as somewhat different types of petroleum prospects.  - 20 - number of highly productive basins worldwide, particularly the Niger Delta in Nigeria. The oil and gas discoveries already made in Krishna-Godavari confirm that hydrocarbons have been generated and hence confirm the prospectivity of the area as a possible future major source of oil and gas. By analogy with comparable deltaic areas it can be expected that the structure and stratigraphy will be complex, and while petroleum reserves may be large, individual oil and gas fields may be small. Reservoirs in this type of basin tend to be discontinuous, and large structures are often located in the deep water, high cost outer shelf areas. Inner shelf prospects, although smaller, are lower-cost and also present interesting possibilities. Furthermore, in the Krishna-Godavari basin, the onshore prospects, in block faulted structures, are also very interesting even though of an entirely different nature. Bank staff in discussions with ONGC have stressed the importance, in this complex geologic environment, of obtaining an integrated interpretation of the entire onshore-inner shelf-outer shelf area through continuous and comprehensive seismic coverage and the selection of well locations on the basis of an economic appraisal of each prospect. While more intensive exploration of the area presents significant challenges, the Krishna-Godavari basin is the only basin in India where exploration efforts to date provide sufficient evidence that an accelerated exploration effort could be successful and result in major additions to national petroleum reserves. Exploration Activity in the Krishna-Godavari Basin 3.02 ONGC's onshore exploration activities in the Krishna Godavari basin routinely began in 1959 with surface geologic surveys, reconnaissance geophysical surveys, and shallow core drilling; these activities continued into the early 1970s. With the availability of modern seismic surveys, a more rigorous exploration effort began in 1974 onshore and in 1978 offshore. These surveys indicated a highly prospective sedimentary section, much more so than originally thought. 3.03 The initial drilling began in 1978 onshore at the Narasapur-l location (see map IBRD 16186R). The Narasapur-1 well suffered a blowout at a depth of 4,043 m in the Mesozoic (Cretaceous) section so it was not tested at that level, but the well did test several gas shows at shallower depths which did not prove productive and the well was abandoned. Subsequently the Razole- 1 and Narasapur-2 wells were spudded 13 km and 1.5 km northeast of Narasapur-l respectively. The Razole-1 reached its objective at 4,501 m and is being prepared for testing. Gas zones were encountered in Lower Cretaceous sandstones between 4,269 and 4,386 m (11 m net) and in fractured and weathered basalt between 3,365 and 3,620 m (230 m gross). The Narasapur-2 also suffered a blowout at about 3,401 m but ONGC will continue drilling down to 4,100 meters by side-tracking. The thicknesses and characteristics of the several reservoirs encountered are not yet known, thus firm estimates of the size of these finds cannot be given. However, if the present geological interpretation is confirmed, a very significant discovery could result. 3.04 Offshore, drilling commenced in 1979. The first offshore well, the G-l-l well, tested oil and gas in Miocene sandstone reservoirs, at a gross interval of 60 m combined. The oil producing interval tested 580 Bbl/d, and the gas interval tested at 0.4 MMCMD of gas together with 210 Bbl/d of condensate. Following completion of G-1-1, five wells have been drilled. Two of them were prematurely abandoned at shallow depths due to wave height,  - 21 - strong currents and possibly sea bottom slumpage; the other two, one of which was located 3.5 km northwest of the C-1 discovery, were dry holes. The fifth well was drilled in early 1982 in the G-3 structure on the inner shelf and was also completed as a dry hole at a depth of 4,010 m. With present information, the recoverable reserves from the G-1 prospect are estimated at about 60 million Bbl. This accumulation does not appear commercial in view of the water depth at which it was encountered (263 m), unless additional productive area or reservoir thickness can be demonstrated. One and perhaps two more wells need be drilled to make this determination. 3.05 The results of seismic surveys and drilling to date are encouraging because they confirm that hydrocarbons in significant quantities have been generated in both onshore and offshore sequences, that good reservoirs are present in the basin, and that there are numerous large structures. As expected, the offshore structure and stratigraphy is complex and an adequate test of the petroleum potential will require an extensive exploration program. In addition to the structures tested so far, there are nine prospects onshore and five on the outer shelf which remain to be drilled. On the inner shelf, a recently completed seismic survey identified many prospects. Therefore, a sufficient inventory of prospects is virtually certain to exist to support a substantial drilling program in the basin, particularly if it is recognized that some of the prospects will require more than one exploratory well for proper evaluation (Annex 3.1 provides a detailed description of past exploration activity and geology of the basin). The Project a. Objectives 3.06 The Project consists of the 1982/83 - 1985/86 slice of ONGC-s exploration program in the Project area (para 3.07). The principal objective of the Project is to establish the commercial potential of this area, lbth onshore and offshore, and to test the most promising oil and gas plays- - Specifically the onshore component aims at: (i) improving the definition of known deep prospects and identifying and detailing new prospects by seismic methods; and (ii) accelerating the drilling program to evaluate the prospects currently identified. The offshore component aims at: (i) integrating the geology of the onshore and offshore and identifying prospects in the inner shelf by means of a seismic survey in the previously unexplored shallow water area; (ii) accelerating the drilling program on the many prospects (yet to be precisely defined) on the inner shelf and on the identified prospects on the outer shelf; and (iii) improving on the definition of offshore prospects through an additional conventional infill seismic survey. Another objective of the Project is to strengthen ONGC-s capability in the design of exploration programs, the drilling of deep high-pressure gas zones, and drilling in the deep water, outer shelf environment. Properly implemented, this Project should enable ONGC to substantially evaluate the petroleum prospects of the Krishna-Godavari basin. 1/ A play is an oil industry term describing a group of fields and/or prospects with common geological characteristics.  - 22 - b. Description 3.07 The Project has been defined following extensive discussions between Bank staff, GOI and ONGC officials. The scope and area of the Project reflect the encouraging results of past exploration efforts, ONGC's implementWion capability, the state of the art in offshore drilling and development- and the importance of maximizing the cost effectiveness of the exploration investments. The geographic area to be explored has been limited to ibout half of the Krishna-Godavari basin and covers approximately 17,000 km (see Map IBRD 16186R) thereby restricting the Project area to include only that part where ONGC has already made significant exploration investments (in excess of US$70 million to date) resulting in discoveries. Nearby areas ( offshore and onshore) have been subsequently included in the second offering of exploration acreage (para. 2.15) to foreign oil companies. 3.08 The Project will comprise the following items: a. Onshore Seismic Surveys: Approximately 1,000 line-km of high resolution seismic lines with the objective of improving the quality of data acquisition, recording and processing and thus obtain a better definition of deep structures; if successful, the shooting and processing parameters derived in this work will be used to improve results of future surveys. Completion of the remaining 727 line-km out of a total of 2,400 line-km of conventional seismic surveys designed to identify other prospects. Drilling: Twelve wells will be drilled of which five wells will be targeted on the deep, high gas pressure prospects to an average depth of 4,500 m; four wells are planned to explore the Upper Cretaceous section with an average depth of 4,000 m; and three wells will be drilled to shallower objectives at an average depth of 3,250 m. b. Offshore Seismic Surveys: Approximately 3,500 line-km of seismic coverage of the very shallow water area, and up to 4,000 line-km of conventional infill seismic in the remaining offshore area of the Project; Drilling: Eleven exploratory wells on anticipated inner shelf prospects to an average depth of 4,000 m and five exploratory wells on outer shelf prospects to an average depth of 3,500 m. c. Technical Assistance External technical assistance to ONGC for supervision of drilling, testing and completion of wells in the harsh outer shelf environment, as well as 1/ Although the technology now exists to drill structures at water depths beyond 200 m, the technology to develop fields at such water depths is still in its infancy. Therefore, despite the fact that many structures have been located at water depths exceeding 200 m, the exploratory drilling effort in these areas has been sharply reduced.  - 23 - in the deep, high-pressure, onshore area. Additional technical assistance, which is desirable but not essential is also being considered. This will be further discussed with ONGC during project implementation. Such assistance may cover: (i) quality control of geophysical data acquisition and processing; and (ii) additional insights into the geology and controls on the accumulation of oil and gas in the Krishna-Godavari basin from a senior geologist experienced in deltaic basins elsewhere. 3.09 Petroleum exploration programs, by their nature, are subject to modifications as new information becomes available. Therefore, the components of the Project could, with justification, be significantly altered during the implementation period, particularly the detailed scope and location of seismic surveys, as well as well locations and drilling programs. Furthermore, as explained above, some of the prospects have not yet been sufficiently defined to permit a judicious choice of drilling locations. Therefore, the initial program in the Project area agreed upon between ONGC and the Bank during negotiations will need to be continuously adjusted as the Project proceeds, and therefore, will be revised from time to time. It will be submitted for review and comments by the Bank on an annual basis starting in April 1983, and whenever it is significantly revised; this will include a detailed review of drilling locations and their justification as well as drilling/testing programs. During negotiations, assurances were received that ONGC will not proceed with implementation of the program, or any of its revisions, without giving the Bank a reasonable opportunity to comment on it. The above arrangements are considered satisfactory, and have evolved out of the extensive dialogue the Bank has already had with ONGC on the definition of the Project. Execution 3.10 Until recently, the Krishna-Godavari exploration program was carried out by two distinct units of ONGC, one in charge of the offshore, and the other of the onshore activities. This situation was unsatisfactory, as both the onshore and the offshore portions are part of the same basin, and results in one area can have an impact on the program in the other. Furthermore, both units had offices in Madras, which functioned independently. Following discussions with Bank staff, ONGC reorganized the operations into a single Madras Division headed by a General Manager to oversee both the onshore and offshore activities in the southeast part of India, including the Krishna- Godavari basin. The Bombay Offshore Project (BOP), which is in charge of all offshore activities in India, will oversee the Madras Division. As a result, all the activities in the Krishna-Godavari basin will be under the responsibility of one unit of ONGC. 3.11 The Madras Division of BOP will be in charge of the execution of the Project, with the support, as required, of ONGC central services based at headquarters (Dehra Dun) and of BOP based in Bombay. With regard to specific arrangements for the execution of the Project, these can be summarized as follows:  - 24 - Onshore Seismic: The high resolution seismic will be carried out by a foreign contractor, while the conventional seismic by two ONGC crews. Drilling: The five deep, high gas pressure wells will be drilled by foreign contractors. The two ONGC rigs will be redeployed to drill the four deep wells with the Upper Cretaceous as objective and the three wells on shallower prospects. ONGC will obtain technical assistance to help supervise the drilling of the initial five deep wells. During negotiations, ONGC confirmed that it will conclude this technical assistance agreement before the first of such wells penetrate a high gas pressure zone. Offshore Seismic: The shallow water survey, and the infill seismic, will be carried out by foreign contractors. Drilling: Eight of the inner shelf wells are planned to be drilled by an anchored drillship owned and operated by a foreign contractor. Three are planned to be drilled by a dynamically positioned (D-P) drillship, during bad weather windows when drilling in the outer shelf will be suspended. The outer shelf wells will be drilled by the dynamically positioned drillship owned and operated by a foreign contractor. ONGC has already contracted Cor'pagnie Francaise des Petroles (CFP, France), a maior oil company, to assist in the supervision of the drilling in the outer shelf; in order to further reduce the risks associated with drilling in this environment: (i) a detailed bottom survey including bathymetry and sea-bed sampling will be carried out prior to drilling each location; and (ii) to the extent possible, wells will be located 250 m shoreward of the shelf slope break. The above arrangements are satisfactory. During negotiations, assurances were also obtained that ONGC will continue to employ consultants whose qualifications, experience and terms of reference are satisfactory to the Bank for the initial wells to be drilled on the outer shelf. The onshore drilling technical assistance, which would normally involve a six-day work week but on occasion require a seven-day work week, is estimated to cost about US$20,000 per man-month inclusive of fees, overhead, travel and subsistence expenses (but excluding Indian income taxes). Other specialized technical consultancy (e.g., geophysical analyses, reservoir evaluation, geochemical studies, etc.), that ONGC may decide to call upon if needed, would cost from US$15,000 to US$20,000 per man-month. The technical assistance and consultancy (excluding offshore outer-shelf drilling) may involve about 150 man-months. The offshore drilling technical assistance with CFP initially covers eighteen months for three wells (one inner-shelf and two outer shelf including the well currently drilling) drilled by the D-P vessel. The assistance involves two teams, each  - 25 - with five experts (four on board the drillship and one onshore) rotating every four weeks. The CFP personnel are on call twenty-four hours each day every day of the week. The estimated average cost (including overheads, travel and subsistence) of the CFP technical assistance is about US$23,500 per man- month.1/ Implementation Schedule 3.12 Onshore, the two ONGC seismic crews are expected to complete their activities by April 1983 and data processing and interpretation should be completed by the end of 1983. The special seismic onshore program, to be carried out by a foreign contractor is expected to begin in October 1982 and be completed, including processing and interpretation, in January 1984. Onshore drilling by the two ONGC rigs will continue throughout the Project period, while the foreign contractors are expected to commence drilling in early 1983 and complete their activities approximately two years later. 3.13 Offshore, the shallow water seismic program, is expected to be carried out in the favorable weather seasons in 1982-1984. The dynamically positioned drillship started drilling in July 1982 on the G-13-1 location, while the anchored drillship is expected to begin drilling in November 1982. Both drillships will remain in the Project area until at least late 1985. The implementation schedule appears in Annex 3.2. Estimated Cost 3.14 The cost of the Project is estimated at US$633.8 million, including contingencies and custom duties. The foreign exchange component is estimated at US$398.9 million, or about 63% of total cost. The detailed cost estimate appears in Annex 3.3; supporting assumptions appear in Annex 3.4. The cost estimate can be summarized as follows: 1/ ONGC is currently finalizing a French commercial loan to finance 85% of the CFP contract.  - 26 - Cost Estimate In Million Rupees In Million US Dollars Local Foreign Total Local Foreign Total Onshore Seismic (contractor and ONGC) 36.6 27.8 64.4 4.1 3.1 7.2 Drilling (12 wells) 362.6 527.3 889.9 40.3 58.6 98.9 Technical assistance 14.6 24.3 38.9 1.6 2.7 4.3 Subtotal 413.8 579.4 993.2 46.0 64.4 110.4 Offshore Seismic (shallow and conv. infill) 33.5 135.7 169.2 3.7 15.1 18.8 Drilling (16 wells) 569.2 1,865.6 2,434.8 63.2 207.3 270.5 Technical assistance 36.0 59.4 95.4 4.0 6.6 10.6 Subtotal 638.7 2,060.7 2,699.4 70.9 229.0 299.9 Duties and Taxes 631.5 - 631.5 70.2 - 70.2 Total base cost 1,684.0 2,640.1 4,324.1 187.1 293.4 480.5 Contingencies Physical a/ 231.9 600.8 832.7 25.8 66.7 92.5 Price b/ 198.2 327.3 525.5 22.0 36.4 58.4 Subtotal 430.1 928.1 1,358.2 47.8 103.1 150.9 Front-End Fee 22.1 22.1 2.4 2.4 Total Project Cost 2,114.1 3,590.3 5,704.4 234.9 398.9 633.8 a/ At 15% for offshore seismic and 25% for drilling. b/ Local at 8.0% in 1983/84, 7.5% in 1984/85 and 7.0% in 1985/86. Foreign at 8.0% in 1983, 7.5% in 1984, 7.0% in 1985 and 6.0% in 1986. The cost estimate is expressed in mid-1982 prices and is based on bids received recently by ONGC, ONGC's costing system and contracts in effect. 3.15 The annual phasing of expenditures appears in Annex 3.5, and can be summarized as follows:  - 27 - US$ Million Fiscal Year ending March 31 1983 1984 1985 1986 Total 111.2 239.2 225J7 57.7 633.8 Items Proposed for Bank Financing 3.16 The specific items selected for Bank financing were agreed between ONGC as well as the Bank with the view of ensuring both a high technical quality for the most critical items of the Project and the most effective implementation arrangement. The items include: (i) the specialized onshore high-resolution seismic and shallow water seismic surveys as well as the conventional infill seismic survey to be carried out by foreign contractors; (ii) those highly specialized technical well services, drilling materials and supplies, and equipment and materials for completion of successful onshore wells (deep and high pressure), which ONGC will import, after ICB or after soliciting bids from the few qualified suppliers; and (iii) the foreign drilling contracts (i.e., rig-hire charges) covering the most difficult drilling conditions, such as the deep, high-pressure onshore wells and the outer shelf wells. The aggregate foreign exchange requirements of all these items, including the front-end fee which the Government requested the Bank to finance, amounts to US$165.5 million. A Bank loan for this amount is proposed and the allocation of the Bank funds is shown below:  - 28 - Allocation of Bank Funds a/ Amount Allocated % of Expenditure Items (In US$ million) to be Financed 1. Seismic surveys: high 23.0 100% of foreign resolution onshore, shallow expenditures water, and infill offshore surveys 2. Technical well services for 9 22.0 -do- onshore and 13 offshore wells (logging, core analysis, mud logging and engineering, diving, testing, completion) 3. Drilling materials and supplies 38.0 100% of foreign for 5 deep onshore, 9 inner expenditures and shelf and 4 outer shelf 100% of local wells (casings, drill bits, expenditures wellheads, cement, chemicals ex-factory and drilling mud) 4. Materials and equipment for 3.0 completion of 6 onslhuLe W -L _ -do- 5. Rig-hire charges for 5 deep 28.0 onshore wells drilled by 100% of foreign foreign contractors expenditures 6. Rig-hire charges for D-P 33.0 vessel covering 8 offshore 25% of foreign wells expenditures 7. Front-End fee 2.4 amount due 8. Unallocated 16.1 Total 165.5 a/ On the basis of the program agreed in June 1982. b/ It is assumed that six onshore wells will be successful and will thus be completed for future production. Financing Plan 3.17 The proposed Bank loan of US$165.5 million would represent about 26% of the total Project cost, and about 41% of the foreign exchange cost of the  - 29 - Proiect, including contingencies. The balance (US$468.3 million) of "he capital cost not covered by the Bank leoar_ which would use up only about 570 o f ONGCCs Internal cashl generation during 1982/83-1985/86, can be assu.me ' financed mostK forom this source. Nonetlheless, as has been the case in t'h past, the Gover-fneol will help arra-nge the balance of the financ"al require-nents fo.- the P'_rojecL i-f needed. This is not expecLed to cause any special difficulties, in view of past experience of ONGC and GOI in securing financing for approved ONGC projects. The puoposad Project represents al,out 5% of MNCCs overall nvestmnt program of abo;ut Rs 115 billion `US$12.8 billlion3 over 1982/83 - 1985/86. T'he financing plan for this overall investment progranm is det-ailed in para. 6.09, and can be su:-marized as fol lows: ONGC"s Overall Financilng Plan 1982/83 - 19S5/86 Rs Mi ili i on US$ Million Percent investment Prograir. 115,506 12,834 100 Financed byv ONGC internal Sources 82,720 9,191 72 Borrowinas 32,639 39627 28 Of which IBRD: a1 (4,186) (454) (4) Equity Contribu-tions and grants 147 16 - 115,507 12,834 100 a/ Disbursements from the Second Bombay High Offshore Development (T oan 1925-IN), the proposed loan for the Krishna-Godavari Exploration Project, and a loanr for Lhe South Bassein Gas Development (para. 2.25) presently under consideration. The aggregpte Bank disbursements for the 1989f83 - 1985/86 investment program is projected tG be abGut US$454 million, or approximately 4% of ONGC