India - Second Bombay High Offshore Development Project

Document of FILE COPY The World Bank u r FOR OFFICIAL USE ONLY Report No. 3101-IN INDIA SECOND BOMBAY HIGH OFFSHORE DEVELOPMENT PROJECT STAFF APPRAISAL REPORT November 5, 1980 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 (as of October 24, 1980) Currency Unit = Rupee (Rs) Rs 1 = Paise 100 US$1 = Rs 7.676644 1/ Rs 1 = US$0.1303 1/ Rs 1 million = US$130,265 1/ MEASURES AND EQUIVALENT 1 Metric Ton (mt) = 1,000 Kilograms (kg) 1 Metric Ton (mt) = 2,204 Pounds (lb) 1 Meter (m) = 3.28 Feet 1 Kilometer (km)3 = 0.62 Miles 1 Cubic Meter (m ) = 35.3 Cubic Feet (cft) 1 Barrel (Bbl) = 0.159 Cubic Meter 1 Metric Ton of Oil (39 3API) = 7.60 Barrels 1 Normal Cubic Meter (Nm ) = 33.42 Standard Cubic Feet of Natural Gas 1 Kilocalorie (kcal) = 3.97 British Thermal Units (BTU) kWh = kilowatt-hour Bbl/d = Barrels per Day Nm /d = Normal Cubic Meters per Day TCE = Metric Tons of Coal Equivalent PRINCIPAL ABBREVIATIONS AND ACRONYMS USED BOP - Bombay Offshore Project CFP - Compagnie Francaise des Petroles (TOTAL) EIL - Engineers India Limited GOI - Government of India IOC - Indian Oil Corporation LPG - Liquefied Petroleum Gas MDL - Mazagon Docks Ltd. MSV - Multi-purpose Supply Vessel OIDB - Oil Industry Development Board OIL - Oil India Ltd. ONGC - Oil and Natural Gas Commission SBM - Single Buoy Mooring WGEP - Working Group on Energy Policy FISCAL YEAR April 1 - March 31 1/ Conversions in this report have been made at US$1 to Rs 8.4 which represents the projected exchange rate over the disbursement period.  FOR OFFICIAL USE ONLY INDIA SECOND BOMBAY HIGH OFFSHORE DEVELOPMENT PROJECT STAFF APPRAISAL REPORT Table of Contents Page No. I. THE ENERGY SECTOR ............ . .. ............................................ 1 Background ............................................. i ............1 Energy Consumption .......... . . * . . .. . . . . . . .. . . . . ...... .o.o... 2 Energy Resources ..o..o .... .. .. ........... ... ..... .... . 5 Energy Prospects .o... ....... .. . . . .. . . . .. . . ........ ...... .... 6 II. THE OIL AND GAS SUBSECTOR ....... o................ ......* 8 Institutional Aspects ................................... o...... ........ 8 Exploration and Development ... ....... ................... 9 Consumption ..o .... .............. ...o... ..... o.. . 10 Oil Production and Supply ........... . o. o..o.o.o......... ...... ..... 11 Supply/Demand Outlook .o.o..o. .. ....... . .. .ooo . .... . ....*..... 12 Pricing Policies ....... ... o..... oooo................................ 13 Role of the Bank ......... .. ................... . .. . 14 III. THE PROGRAMI AND THE PROJECT . 15 Introduction o .... ...................................... ...... 15 The Five-Year Program .... ....o. . . . . . . . . . . . . . ... ... ... . 15 Main Characteristics of the Bombay High Field ............ 16 The Bombay High Development Program .. ............ 17 The Project ... .............. - !. 18 Engineering and Construction .............. 20 Execution . ...... oo ... ................ 21 Implementation Schedule .. ... . . . . . . . . . . . . ... . ....... . 21 Estimated Cost ............ o................... .... ............ 21 Items Proposed for Bank Financing . ....... . . . .. 23 Financing Plan .......... 24 Procurement and Disbursement .......... 24 Ecology and Safety o.o....o .. .. 25 IV. JUSTIFICATION .... ..... o ... ......o .... 26 Future Demand/Supply of Petroleum in India . 26 Optimal Development Plan . .................. 26 Economic Rate of Return ........ ...... . 27 Project Risks ................. 28 This report is based on the findings of an appraisal mission, consisting of Messrs. M. Heitner, J. Wall and G. Yuksel, that visited India in June 1980, and a postappraisal mission in September 1980. Mr. D. Hennenfent (Consultant) assisted in the financial evaluation of ONGC. 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.  Table of Contents (Continued) Page No. V. THE OIL AND NATURAL GAS COMMISSION (ONGC) .... ................. 28 General ..... 28 Organization and Management ............. .. ............... 29 Staffing and Training ..................... . 30 Management Information System ............ .. .............. 30 Accounts and Audit .................. 30 Insurance ................................................ 31 VI. FINANCIAL ASPECTS ............................................. 31 Introduction ....... ............... ....................... 31 Past Performance ...... .............. ..................... 31 Prices ................................................... 32 Financial Prospects ................. .. ................... 33 Financing Plan ....... ............ .. ...................... 34 VII. AGREEMENTS TO BE REACHED AND RECOMMENDATION .... ............... 35 ANNEXES 2.1 Consumption of Oil Products 2.2 Crude Oil Supply 3.1 ONGC's Investment Program 3.2 Reserve Estimates and Production Projections 3.3 Details of Engineering Evaluation 3.4 Implementation Schedule 3.5 Cost Estimate 3.6 Phasing of Expenditures 3.7 Estimated Schedule of Disbursements 4.1 Economic Rate of Return - Project 4.2 Economic Rate of Return - Bombay High 5.1 Organization Chart - ONGC 5.2 Organization Chart - Bombay Offshore Project 6.1 Financial Tables 6.2 Assumptions Underlying the Financial Projections 6.3 DCF Rate of Return 7.1 Documents available in Project File MAPS IBRD - 15207 and IBRD - 15183  I. THE ENERGY SECTOR Background 1.01 Commercial primary energy (coal, oil, gas, hydro and nuclear) accounts for about 46% of total supply in India, with the balance (54%) coming from noncommercial energy (mainly firewood, agricultural and animal wastes). Coal and hydroelectricity have an important role in meeting commercial energy requirements and currently account for approximately 70% of total demand; the consumption of petroleum is relatively low in comparison with other developing countries and accounts for less than 20% of total demand for commercial energy. Over the past ten years total energy consumption in India has been growing at an annual rate of about 4%. Consumption of commercial energy has been growing faster than that of noncommercial energy (about 5% p.a.), thus resulting in a steady decline in the share of noncommercial energy in total energy consumption. 1.02 Despite the low rate of petroleum consumption, the extensive develop- ment of domestic energy resources such as coal and hydroelectricity, and the recent development of offshore petroleum resources, the country has not attained energy self-sufficiency and remains dependent on imported oil to meet its primary energy requirements. Moreover, in recent years there has been a growing demand for petroleum products resulting from inefficiencies in coal production and in power plant utilization. The impact of the increase in world oil prices after 1973 on India's balance of payments is evident from the following: while oil imports grew by 17% (3 million tons) from 1972/73 to 1979/80, the cost of imports rose by some 2,200% from $265 million in 1972/73 to about US$1.5 billion in 1975/76, US$4.0 billion in 1979/80, and an estimated US$6 billion in 1980/81, equivalent to more than 60% of India's estimated export earnings. Domestic energy resources such as coal and hydro- electricity are large enough to supply most of India's future commercial energy requirements, particularly for industry and power generation. However, known oil and gas resources would not be sufficient to meet the demand for oil in sectors where further substitution by other fuels is not possible (transportation and residential). Therefore, the exploration for new, and development of existing, petroleum reserves is one of India-s most pressing priorities. 1.03 Although the potential for oil and gas is significant, India is largely unexplored, and known oil and gas reserves do not yield a production large enough to meet India's needs. In 1979/80 over 36% of total consumption was met from local production while the remainder (16.2 million tons of crude oil and 4.5 million of refined products) had to be imported. Current projections indicate that 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 production and to meet anticipated growth in demand.  - 2 - 1.04 It is against this background that India is now making a concerted effort to attract foreign oil exploration companies to help explore for oil both onshore and offshore, an initiative which has generated considerable interest within the international petroleum industry (para. 2.09). The success of these efforts, together with an active exploration program by ONGC, over the next three to four years will be a key factor in determining whether indigenous crude oil supplies can be increased sufficiently above current forecasts to meet the anticipated growth in demand during the present decade. Energy Consumption 1.05 In 1975/76 (the last year for which overall consumption figures are available), energy consumption in India was 254.5 million tons of coal equivalent. The breakdown by energy source can be summarized as follows: Energy Consumption in India (million tons of coal equivalent a/) Average Growth Rate Fiscal Year 1961 1970 1976 1961-76 (%) Commercial Energy Coal b/ 40.4 51.4 71.0 3.8 Oil b/ 9.3 20.8 24.7 6.7 Electricity 5.6 16.1 21.8 9.5 Subtotal 55.3 88.3 117.5 5.2 Noncommercial Energy Firewood 67.7 80.2 90.5 1.9 Agricultural waste 18.4 21.8 24.6 1.9 Animal dung 16.4 19.4 21.9 2.0 Subtotal 102.5 121.4 137.0 1.9 Total 157.8 209.7 254.5 3.6 Source: Working Group on Energy Policy (see para. 1.17). a/ The followFng conversion factors were used: 1 ton of coal equivalent (or 7 x 10 kilocalories), is equivalent to 0.72 ton of crude oil, 3,030 kilowatt-hours, 1.47 tons of firewood, 1.66 tons of vegetable waste and 3.3 tons of animal dung. b/ Excludes quantities used for power generation.  - 3 - 1.06 Trends in energy consumption during the period 1961-1976 can be summarized as follows: Sectoral Breakdown and Growth of Commercial Energy Consumption (Percent) Average Annual Growth Rate 1961 1976 1961-76 Households 13.4 11.8 4.3 Agriculture 1.5 4.1 12.5 Industry 44.1 57.0 7.0 Transportation 38.2 23.1 1.7 Other 2.8 4.0 7.8 Total 100.0 100.0 5.2 Source: Working Group on Energy Policy (see para. 1.17). The household sector accounts for a relatively small share of commercial energy consumption (6% of coal, 20% of petroleum and 9% of electricity). However, consumption of noncommercial energy in this sector is high, partic- ularly in the rural areas where electricity and kerosene are mostly used for lighting. Although the substitution of commercial energy for noncommercial energy will continue, noncommercial energy should remain a significant source of supply for households well into the next century. Measures are urgently needed to maintain and even increase production of noncommercial sources (particularly firewood), improve the efficiency of cooking stoves and explore alternative sources of energy. 1.07 Energy needs in agriculture are mainly for land preparation, water lifting and transportation; as such they are met mostly by animal power or by the use of liquid fuels (mainly diesel) and electricity. Commercial energy consumption in agriculture has been growing rapidly since 1970/71 (about 20% p.a. for oil products and 7.2% p.a. for electricity), reflecting the efforts made to modernize the agricultural sector. However part of this growth may also be attributed to low electricity tariffs which may have encouraged the use of inefficient equipment and to the increased use of tractors for trans- portation because of the relatively low price of diesel oil compared to gasoline. This trend towards commercial energy in agriculture will continue unless efforts are made to improve the efficiency of irrigation pumps and tractors, and pricing policies/regulations are introduced to encourage energy efficiency and conservation. 1.08 The industrial sector is by far the largest user of coal and elec- tricity. In 1978/79 the industrial sector accounted for 73% of coal consump- tion (excluding power generation) and for 64% of electricity consumption.  - 4 - In contrast to most developed and developing countries the share of industry in total oil consumption is very low and has been declining (6% of total oil consumption in 1978/79 compared to 11% in 1970/71) as a result of a deliberate policy to substitute domestic coal for oil wherever feasible. Over the past twenty years the energy intensity of the industrial sector has increased from 1.86 to 2.40 million tons of coal equivalent per billion rupees of value added. This was due primarily to the increased use of electricity. In the future it is expected that the growth of energy consumption in industry will slow as a result of better capacity utilization, GOI policies to encourage decentralized industrial development and use of appropriate techno- logies. The future industrial demand for energy is difficult to predict since the sector has been affected by recurrent shortages and recent trends therefore may not be representative. In addition, part of the industrial plant was built when energy was relatively cheap, and less attention was paid to energy efficiency. It is believed that there is a considerable potential for energy savings in the industrial sector by improving the efficiency of existing plant and equipment, by improving the design and location of future plants, and by introducing energy efficiency standards. 1.09 The transport sector 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 of the substitution of diesel-electrics for steam locomotives (in 1978/79 oil accounted for 66% of the commercial energy consumed in the sector compared to 25% in 1960/61; the share of electricity remains small). Current projections in the transport sector indicate continuing decline in coal usage, as railways continue to shift to more efficient diesel, and a growing demand for petroleum products and electricity. The transport sector represents an area where significant energy savings, especially in petroleum products, could be achieved over time if measures were taken to encourage the use of railways for long distance freight and passenger hauls, to improve the efficiency of road vehicles (mainly trucks), and to optimize the location of industrial plants. 1.10 In 1978/79 the power sector used about 44 million tons of coal equivalent of primary energy of which 47% came from hydroelectric and nuclear plants, 47% from coal and 6% from oil. Over the past ten years the share of coal in thermal generation 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 43% and 50%. It is expected that by 1987/88 the consump- tion of oil in the power sector 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 7.2% p.a. between 1970/71 and 1978/79, a rate significantly lower than previously. However, the growth in demand of electricity has accelerated recently to reach 11% in 1976/77 and 16% in 1978/79. As the power shortages which developed during the 1970s demon- strated, the growth of demand for electricity has been and will continue to be supply constrained.  -5- Energy Resources 1.11 Coal constitutes the main domestic source of commercial energy in India. Coal reserves to a depth of 600 m and of seam thickness of more than 1.2 m are currently estimated at 85.4 billion tons, of which 17.9 billion tons are of the coking variety and 67.5 billion tons of the noncoking variety. The Geological Survey of India has recently estimated that an additional 26.1 billion tons of coal deposits exist at depths below 600 m. According to current demand forecasts, India's coal resources should be sufficient to meet the expected demand for about 100 to 140 years. 1.12 From 1953/54 to 1970/71 the share of coal in commercial primary energy supply has declined from 80% to about 60%, while production increased from 34 million tons to about 65 million tons. Since 1970/71 the share of coal has remained constant as production has been growing at an average annual rate of 5.5% (to 104 million metric tons in 1979/80). Despite the production increases, shortages developed in 1977/78--reaching an estimated 8 million tons in 1979/80. The main reasons for the shortfalls are poor capacity utilization due to a reduced and erratic power supply, shortages of explosives, floods, labor problems, and bottlenecks in the transportation and distribution systems. 1.13 India's hydroelectric potential is estimated to be 100,000 MW, of which two thirds is estimated to be economically exploitable. About 11,000 MW is already developed (one third of the total installed generating capacity), 4,700 MW is scheduled for commissioning by 1984, and a further 23,000 MW is under study for development. Some 70% of the total hydroelectric potential is in the north and northeast. India also has sufficient reserves of uranium (34,000 tons equivalent of U 0 of which 15,000 tons is considered economic- ally exploitable at current nternational prices) and thorium to meet the foreseeable requirements of its nuclear power program. 1.14 India's remaining ultimately recoverable reserves of oil and gas are currently estimated at 6.5 billion tons of oil equivalent as shown below: Remaining Ultimately Recoverable Reserves (million tons of oil equivalent) Oil Gas Total Onshore 500 1,800 2,300 Offshore 1,000 3,200 4,200 Total 1,500 5,000 6,500 Source: ONGC. These estimates are derived from a geological survey carried out by a joint Soviet/Indian team. Of these, proven recoverable reserves are about 360 million tons of oil equivalent, of which 294 million tons are oil and 66 million tons are gas. Over 60% of the recoverable oil reserves are offshore.  - 6 - 1.15 Domestic oil production has increased from 0.5 million tons in 1961 to 12.5 million tons in 1979 and currently meets about 40% of India's internal requirements. Gas production is currently estimated at about 2 million tons of oil equivalent, of which about half is used as fuel or feedstock, and about half is flared mainly because there is no market to use it within reasonable distance. 1.16 Renewable energy represents a large, but declining, share of India-s energy supplies. Wood, charcoal, dung, and vegetable wastes made up an esti- mated 44% of total energy consumption in 1975/76. The remainder is provided by hydroelectric power. Renewable energy (especially traditional fuels) will continue to play an important though decreasing role in rural energy supplies, particularly if the growth in rural consumption of oil products is to be contained. The main constraint to the development of renewable energy appears to be institutional, reflecting the large size and wide distribution of India's rural population. A sizeable education program would therefore be required to inform rural populations of new technologies. Energy Prospects 1.17 Several studies of India-s future energy demand and supply alter- natives have been carried out by various agencies and committees. 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, which was based on existing data, it does conclude 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 resources 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 reductior being in the demand for power generation 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. WGEP's estimates indicate that the import cost of oil by the year 2000 could be as high as US$27 billion (in 1980 dollars, based on oil prices of US$32/Bbl).  - 7 - 1.18 The Working Group on Energy Policy has studied two demand/supply scenarios: (i) a Reference Level Forecast (RLF) which is based on the continuation of past trends and which assumes that no deliberate measures will be taken to promote energy conservation and inter-fuel substitution beyond what is currently done; and (ii) an Optimal Level Forecast (OLF) which assumes that further steps will be taken to promote energy conservation, to improve energy efficiency and to encourage the development of alternative energy resources. The two demand/supply scenarious are summarized below: 1979/80 1987/88 2000/2001 Actual RLF OLF RLF OLF Coal (million tons) a/ 68.8 131.5 129.0 308.0 266.0 Oil (million tons) a/ b/ 21.7 33.4 30.4 74.2 54.8 Electricity (billion kWh) 84.4 191.2 173.6 471.0 395.6 a/ Excluding quantities used for power generation. b/ Excluding nonenergy use (fertilizers, etc.). The policy measures it recommends to achieve the Optimal Level Forecast are: (i) improvement in the efficiency of energy utilization; (ii) introduction of fuel-efficient technologies; (iii) reduction of transportation demand through an 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 elasticity of energy to GDP would decline from 1.8 today to 0.90 by 1992. The energy savings measures outlined above--supported by detailed implementation plans and an appropriate pricing policy--would substantially reduce waste and improve energy availability in the medium and the long run. In its recommendations, the Working Group has also emphasized the need to plan and update development programs in the energy sector on a continuous basis and has suggested to GOI that consideration be given to the creation of a Ministry of Energy in charge of the whole energy sector.l/ Such recommendations are worthy of support, in particular when it comes to the identification of least-cost alternatives in meeting India's future energy requirements and the implementation of effec- tive demand management policies. 1.19 However, equally bold policies are needed to tackle the current bottlenecks in the area of energy production. In the short term there is an urgent need to improve capacity utilization in the coal and power sectors. But persistence of capacity underutilization in these sectors over the years points to the fact that the problems are deep-rooted and will take time to overcome. In the longer term, the Government will have to allocate significant resources for the development of its commercial energy resources particularly with regard to coal (to provide for a fourfold increase in 1/ At present, responsibilities for the energy sector are divided between the Ministry of Petroleum, Chemicals and Fertilizers, and the Ministry of Energy and Coal (in charge of electric power and coal).  - 8 - production during the next twenty years), and power (the Optimal Level Forecast projects an almost fivefold increase in overall demand for electricity during the next twenty years). Despite the relatively small share of oil in overall energy consumption (para. 1.05), its significant impact on the balance of payments will compel India to divert increased resources to accelerate the development of India's indigenous oil and gas reserves, as well as to increase petroleum exploration. This is reviewed in more detail in the next chapter. II. THE OIL AND GAS SUBSECTOR Institutional Aspects 2.01 The major institutions in the subsector are the Oil and Natural Gas Commission (ONGC) (a public sector undertaking), Oil India Limited (OIL) (presently owned fifty-fifty by GOI and Burmah Oil, but in the process of being fully nationalized) and the Indian Oil Corporation (IOC) (a public sector undertaking). Both ONGC and OIL are engaged in exploration for and development of hydrocarbon resources. IOC handles all of India's crude oil imports, and distributes imported oil products in addition to those produced by its own refineries. With the exception of the small Assam Oil Company (Burmah Oil) refinery, all refineries are now in the public sector. 2.02 ONGC is by far the largest undertaking in the area of oil explora- tion and development. Initially part of the Geological Survey of India, it became an independent statutory commission in 1959. ONGC made discoveries onshore in the 1960s (Assam and Gujarat) and moved offshore in the mid-1970s to discover the giant field of Bombay High; it is currently active in explora- tion both onshore and offshore. ONGC is the principal entity through which GOI intends to explore for and develop hydrocarbon resources. ONGC's organi- zation is reviewed in Chapter V. 2.03 Oil India Limited's activities are restricted to a small producing area in Assam, and a small onshore/offshore concession (the Mahanadi basin). 2.04 The Ministry of Petroleum, Chemicals and Fertilizers is in charge of policy making in the petroleum sector. It monitors activities in the oil and gas sector closely and, inter alia, has to vet all the programs and budgets suggested by ONGC. The Oil Industry Development Board (OIDB), a public body created in 1974, provides financing to oil undertakings for high priority projects. Its only source of revenues is a cess levied on domestic oil and gas production. As of March 31, 1980, it had lent to ONGC Rs 1.8 billion (equivalent to 60% of its total loans extended until that time). Map IBRD 15207 indicates the main features of India's oil and gas sector.  -9- Exploration and Development 2.05 The onshore 2sedimentary basins of India occupy an area of approxi- mately 1.4 2million km . The offshore sedimentary basins have an a ea of 250,000 km to a water depth of 100 m, and an additional 70,000 km to a water depth of 200 m. So far, commercial production has been established in only two sedimentary basins: the Assam-Arakan basin occupying parts of Assam and extending to Nagaland, Meghalya, Tripura, Manipur and Mizoram in the eastern part of the country, and the Cambay basin in Gujarat with its extension, the Bombay Offshore. As mentioned in para. 1.14, India-s prognostic 1/ recoverable hydrocarbon reserves were recently estimated at 6.5 billion tons, of which approximately two-thirds lie offshore. Proven and probable reserves of oil initially in place in existing deposits were estimated at 1.6 billion tons as of January 1978, of which 0.9 billion tons are offshore. 2.06 In view of the continuing rise in oil prices, GOI has requested ONGC to accelerate the development of its offshore fields. ONGC's program is reviewed in paras. 3.02-3.04. Unless it discovers oil, OIL is not expected to engage in development work at a significant level. 2.07 With the exception of Oil India and ChemoComplex (Hungary) which drilled a well onshore in 1978, and of Natomas (US), Reading & Bates (US) and Assamera (Canada) which obtained three exploration licenses offshore in the early 1970s, ONGC has conducted all the exploration in India in the past few years. Onshore, ONGC accelerated its exploration effort in 1978/79. As of March 1979 thirty-two land rigs were in operation for exploration and development drilling and some seventy-five wells were drilled in 1978/79. Current plans call for about one hundred wells per year by 1982/83. While most of the onshore operations have so far been confined to relatively shallow drilling, ONGC is now in the process of launching a deep drilling program which would require the acquisition of new, more sophisticated rigs of greater capacity (up to 6,000 m). ONGC recently signed a protocol with the USSR for exploration in two areas (Tripura and West Bengal). Three wells to at least 16,000 ft (5,300 m) are expected to be drilled in each block. At present ONGC has five active rigs offshore. During 1978 and 1979 offshore explora- tion increased to approximately twenty-five exploratory wells drilled, resulting in several commercial discoveries in the Bombay High area. In early 1980, significant oil and gas shows were encountered in the Bay of Bengal (Godavari Basin) and near the Andaman Islands. These discoveries which should be appraised in the near future may open up new promising areas for explora- tion. ONGC has also developed a large program of geophysical and geochemical investigations in most of the prospective offshore areas, but more particu- larly offshore Kerala, Godavari and the Andaman Islands. 1/ Prognostic estimates of reserves should be considered with caution, as they are based on a large number of assumptions. They should only be considered as a broad indication of the total oil resources in the country.  - 10 - 2.08 On a more modest scale, OIL drilled nineteen wells in 1978, of which two were deep wells, and planned to drill twenty-eight wells in 1979. In the next five years OIL is planning to drill 122 wells in the northeast. In 1978, OIL received an offshore concession; one well was drilled in early 1980, and a second is expected to be drilled shortly. 2.09 Given the size of the prospective areas onshore and offshore, it would be unrealistic to expect ONGC and OIL to carry the exploration burden alone, particularly at a time when, the need is immediate to identify new domestic oil and gas supplies. GOI has recently indicated its interest in securing the participation of international oil companies in the country's exploration activities and is in the process of prequalifying interested oil companies. The response so far has been encouraging as about thirty-five companies, which could be considered serious candidates, have approached ONGC. The implications of this new policy (India had not recently encouraged foreign exploration) are far reaching and a large amount of preparation is now required to select the location and size of blocks, to determine the type of contract that would be most suitable, and to effectively negotiate with oil companies. 2.10 While the participation of foreign oil companies would accelerate exploration, it is unlikely that the first wells could be drilled until 1982/83 after the necessary geophysical surveys have been carried out and the results interpreted. It is therefore imperative that both ONGC and OIL continue their effort begun in 1978/79. ONGC's investment plan for the next five years indicates that exploration expenditures will increase from US$130 million in 1981 to about US$265 million in 1985. Total exploration expenditures (excluding the purchase of rigs) would total US$1 billion of which about 40% would be offshore. Exploration expenditures would account for about 20% of ONGC's total capital expenditures. This allocation of ONGC's resources appears adequate in light of the involvement of foreign oil companies, which are more likely to be interested in offshore exploration, and in light of ONGC's absorptive capacity. Consumption 2.11 Consumption of oil products in past years appears in Annex 2.1, and can be summarized as follows (in million tons):  - 11 - Growth (%) 1960/61 1970/71 1979/80 a/ 1970/71-1979/80 Light Distillates LPG - 0.18 0.40 9.3 Gasoline 0.86 1.45 1.48 0.2 Naphtha - 0.90 2.53 12.2 Other 0.12 0.16 0.15 - 0.7 Subtotal 0.98 2.69 4.56 6.0 Middle Distillates Kerosene 2.02 3.28 3.86 1.8 Jet Fuel 0.20 0.69 1.14 5.7 Diesel Oil 1.94 4.93 10.99 9.3 Other 0.13 0.14 0.22 5.2 Subtotal 4.29 9.04 16.21 6.7 Heavy Ends Fuel Oil 1.92 4.66 6.85 4.4 Bitumen 0.43 0.78 1.07 3.6 Other 0.36 0.73 0.95 3.0 Subtotal 2.71 6.17 8.87 4.1 Total Consumption 7.98 17.90 29.64 5.8 a/ Provisional. Source: Ministry of Petroleum, Chemicals and Fertilizers. 2.12 The salient feature of the demand for oil products in India is the relative importance of middle distillates which accounted for 65% of all petroleum products used for energy in 1979/80. Middle distillates consumption has been growing rapidly--particularly diesel oil, reflecting the rapid growth of road transport, modernization of agriculture and conversion to diesel- electric railways. Kerosene consumption, which had been growing at a rate of about 5% p.a. until 1970/71, has remained almost constant because of signifi- cant price increases in the mid-1970s. Current forecasts indicate that the share of middle distillates in total consumption will continue to remain high, and therefore it is likely that additional hydro-cracking capacity in the refineries will be required. Oil Production and Supply 2.13 Supply of crude oil in past years and a corresponding forecast appear at Annex 2.2 and can be summarized as follows:  - 12 - Million Tons of Crude Oil Equivalent a/ Year 1960/61 1970/71 1979/80 1984/85 Domestic Crude Oil 0.45 6.82 11.77 22.25 Imported Crude Oil 5.71 11.68 16.22 16.30 Imported Products (Crude Equivalent) 2.22 1.08 4.77 9.57 Total Supply 8.38 19.58 32.76 48.12 Index of Self-Reliance (%) 5.4 34.8 35.9 46.2 a/ One ton of products is equivalent to 1.0638 tons of crude oil. Source: Ministry of Petroleum, Chemicals and Fertilizers and Bank Staff Estimates. As the above table indicates, while the demand for oil has been growing steadily, the production of domestic crude has been increasing at a greater pace. The bulk of the increased production in the 1970s is attributable to Bombay High: from negligible amounts in 1970/71 to 4.2 million tons in 1979/80, or 36% of total domestic production. Although the index of self- reliance could reach 46% in 1984/85, unless new discoveries are made it would decline again in subsequent years. 2.14 The installed refining capacity of India is approximately 30 million tons, but an additional 7 million tons of capacity is expected to come on stream during 1981. The relatively high level of product imports reflects the current shortage of refining capacity. India's refineries are becoming more sophisticated with each addition to capacity: they are able to use a wider range of crude oil feedstocks and can tailor the product mix more closely to local demand. Plans for new refineries and expansions of existing ones are now under consideration. Supply/Demand Outlook 2.15 Known oil fields are expected to be capable of producing the follow- ing quantities in 1984/85:  - 13 - Sustainable Oil Production in 1984/85 (million tons) Offshore (all ONGC) Bombay High 12.0 North Bassein R-12 {2.0 B-37/38 _ Subtotal 14.0 Onshore ONGC 6.5 OIL, Assam Oil Company 2.5 Subtotal 9.0 Total 23.0 This compares with a future demand for crude oil estimated by the Working Group at approximately 35.4 million tons in 1982/83, and 44.6 million tons (Reference Level Forecast) or 41.0 million tons (Optimal Level Forecast) in 1987/88. Considering past trends, these forecasts appear to be on the low side and a forecast of some 45 million tons by 1984/85 does not seem unreal- istic (Annex 2.2) if the demand is to be met in full (there have been serious shortages, particularly in the late 1970s). In any event, unless new and important discoveries are made, India will have to resort to growing imports of oil. Pricing Policies 2.16 India has consistently followed a policy of maintaining retail prices of oil products at international levels, with a cross-subsidy from gasoline towards kerosene (on social grounds) and naphtha (for fertilizers). This policy of rapidly increasing prices explains in part the fact that gasoline consumption has remained virtually unchanged over the past ten years, and the very slow growth in kerosene consumption (1.8% per annum). Most of the growth in consumption has been for diesel oil, jet fuel and fuel oil, where demand is less sensitive to price. Prices, last increased in June 1980, are as follows for the main products:  - 14 - Retail Prices as of June 1980 US$ per US Gallon Rs/Liter b/ India b/ Turkey France USA cif Refinery Price a/ Gasoline 5.10 2.30 2.45 3.12 1.29 1.15 Kerosene 1.54 0.69 1.33 - 1.25 1.00 Diesel Oil 2.28 1.03 1.33 2.19 1.17 0.97 Fuel Oil 2.129 0.96 0.94 1.45 0.70 0.72 a/ Based on crude oil at US$32/barrel, factored by recent ratios of crude oil prices to product prices in the Far East. b/ Prices in New Delhi, about average for India. Crude oil and its products constitute substantial sources of revenues to GOI and State Governments. In 1978/79 GOI received through excise duties, customs duties, corporate income taxes, dividends, cess and royalties altogether Rs 17.3 billion (US$2.1 billion). In addition State Governments levied a sales tax, but overall proceeds are not known. 2.17 Domestic crude oil is sold by the producer at Government-regulated prices which are substantially below international levels. Such low transfer prices (para. 6.04) do not act as a disincentive to invest in oil exploration or development, as the major producers are in the public sector and operating decisions are based upon the international price of oil. Role of the Bank 2.18 Most of the Bank's energy lending to India so far has been in the power sector. In 1977, the Bank made a loan of US$150 million (Loan 1473-IN) towards Phase III of the Bombay High Offshore Development. When the loan was made, the Oil and Natural Gas Commission was relatively inexperienced in offshore programs and lacked experienced technical staff to handle such projects. ONGC, by attracting competent personnel, by introducing appro- priate training programs, and with the support of Bank advice on technical and managerial matters, is implementing the project successfully (ONGC's performance is reviewed in para. 3.09). 2.19 With ONGC becoming increasingly involved in offshore operations, the Bank can continue to play an important institution-building role, by providing advice as needed and by ensuring that development projects are subjected to thorough feasibility studies and are carried out using the highest standards of the industry. 2.20 ONGC is about to embark on the development 3of the major South Bassein gas field capable of producing 18 million Nm /d of free (i.e. nonassociated) gas over twenty years to supply new fertilizer plants and petrochemical plants. While consumption of gas is today insignificant  - 15 - in the overall energy picture, gas will play an increasingly important role in meeting India's future energy and feedstock needs. The Bank is cooperat- ing with GOI and ONGC to ensure that the development of the South Bassein gas field is carried out in an optimal fashion, and that GOI and ONGC prepare the basis for a longer term gas resource strategy in order to maximize the benefits of this new source of energy to the economy. 2.21 Another area where the Bank can now assist GOI and ONGC relates to oil exploration. Until recently, GOI's policy regarding foreign oil companies had been hesitant, and not encouraging to the oil industry. The Government has recently announced a major policy change in this regard, and intends to enter into oil exploration agreements with foreign oil companies. The Bank is now providing assistance in this respect, in particular regarding (i) Government approach to negotiations with foreign oil companies; (ii) contractual matters (model contracts); and (iii) monitoring (probably by ONGC) of the oil companies exploration and development activities after permits have been awarded. 2.22 In view of the considerable impact on the economy of increasing oil prices, an important priority remains the acceleration of production from existing fields, essentially Bombay High. This is the purpose of the proposed Project. By giving financial support to this priority Project, the Bank will strengthen its existing relationship with ONGC, help GOI meet the substantial foreign exchange requirements entailed by offshore development projects, and, most importantly, help alleviate the substantial drain on foreign exchange reserves by reducing the need to import oil at ever increasing prices. III. THE PROGRAM AND THE PROJECT Introduction 3.01 ONGC prepares annually a five-year rolling plan which sets out investment strategies for exploration and development, onshore and offshore. The plan is reviewed, and modified as necessary, by the Ministry of Petroleum, Chemicals and Fertilizers. The Five-Year Program 3.02 The 1981-85 plan was reviewed by the Ministry of Petroleum, Chemicals, and Fertilizers in June 1980. It calls for investments amounting to Rs 39.9 billion (US$4.7 billion) over the next five years, as follows:  - 16 - Investment Plan 1981-1985 Rs million US$ million Offshore Exploration 3,167 377 Development 19,571 2,330 Joint Items 3,398 404 Subtotal 26,136 3,111 Onshore Exploration 5,417 645 Development 1,646 196 Joint Items 6,658 793 Subtotal 13,721 1,634 Total 39,857 4,745 3.03 The above plan represents a significant overall increase in ONGC's investments since, in the previous five-year period (1976-80), total invest- ments were Rs 11,724 million (US$ 1,396 million). The bulk of the increase can be attributed to development activities offshore and to increased explora- tion programs. In this regard it reflects the high priority given to an acceleration of domestic oil production and exploration activities. At the same time, it reflects ONGC's internal implementation constraints, partic- ularly in its offshore operations, and the current worldwide difficulties in obtaining offshore drilling rigs. The plan is reviewed at Annex 3.1 of this report. 3.04 Of the Rs 19.6 billion allocated for offshore development, Rs 13.6 billion would be directed to the continuation of the Bombay High field development. The Bombay High field constitutes the largest oil field discovered in India. Main Characteristics of the Bombay High Field 3.05 The Bombay High field is located some 160 km west-northwest of Bombay in the Arabian Sea at a water depth of 80 m. It is on the largest structure identified during a seismic survey conducted in 1966. The discovery well was drilled in 1974. Map 15183 shows the location of the field. 3.06 The sedimentary series of the area is formed by a thick shale sequence of Tertiary to recent age, with substantial limestone intervals and minor sand development. Each limestone or sand section is a potential reservoir interval, and some show significant hydrocarbon impregnation. In the Bombay High field, the L-III limestone unit of the Miocene is the main reservoir.  - 17 - 3.07 The Bombay High structure is defined by 3,000 km of seismic lines, and data from some forty wells are available. Since the inception of oil production in May 1976, extensive reservoir and production data were collected and analyzed by Compagnie Francaise des Petroles (CFP), which has been ONGC's reservoir consultant on Bombay High since 1977. The latest estimate of the L-III reserves is given below: Oil in Place Gas in Place (million tons) (billion Nm ) Proven plus probable 896 91.4 Possible 344 2.6 Total 1,240 94.0 The reserves of Bombay High, and the production forecasts are examined in Annex 3.2. 3.08 Of the 896 million tons of proven plus probable reserves of oil in place, 11% or some 98.6 million tons are estimated to be recoverable by primary production over twenty years. Water injection for pressure main- tenance would increase the expected oil recovery over the same period to 19% or 170.2 million tons 1/. Slightly more than half of the proven plus probable reserves of the L-III reservoir (453 million tons) are located in the as-yet- undeveloped central and southern areas of the Bombay High field. The Bombay High Development Program 3.09 The Bombay High field development program prepared by ONGC calls for the development of the field in five phases. Phases I and II, completed in late 1977, consist of the construction of production facilities, such as production platforms, interconnecting subsea pipelines, the installation of a single buoy mooring (SBM) system and the drilling of development wells required to reach a production capacity of 80,000 Bbl/d (4 million tons/year). Phase III was approved by the Government in May 1977 and consists of the drilling of twenty-four development wells and the construction of six well platforms to reach a production of 140,000 Bbl/d (7 million tons/year) as well as the construction of two processing platforms, two pipelines, each 200 km long, for oil and gas transport to the shore, shore facilities at Uran for the pipelines landfall and at Nhava Sheva for the supply base. The Bank made a US$150 million loan in FY 1977 (Loan 1473-IN) for Phase III. A two-year delay was caused by a major shift in priorities (development of the North Bassein field was postponed on account of lower than anticipated reserves), changes in production targets, and delays in construction (major facilities, to be commissioned before the 1980 monsoon, could not be completed as scheduled, mostly because of delays in equipment delivery and construction). The Project will be substantially completed, 1/ Since production began, and until March 31, 1980, Bombay ligh has produced 9.9 million tons of crude oil and 559 million Nm of gas.  - 18 - and all the facilities commissioned, by the end of 1980. ONGC's performance has been satisfactory, particularly if one takes into account the fact that it had virtually no experience in offshore projects only five years ago. 3.10 Phase IV consists of the drilling of forty-four production wells, the construction of ten wellhead platforms (two in the northern and eight in the southern area) and one major processing platform with separate living quarters platform, the installation of the required subsea pipelines, the expansion of the crude stabilization and storage facilities at Uran, and the extension of the telemetry and telecontrol facilities to reach a production potential of 240,000 Bbl/d (12 million tons/year) by mid-1982. Phase V consists of the installation of water injection facilities required in order to maintain optimum production rates and to increase ultimate oil recovery. Currently only an "advance action" program for Phase V consisting of five production platforms together with twenty development wells has been finalized pending results of engineering studies now in progress. 3.11 The entire program up to and including Phase V (advance action) is estimated to cost US$1,658 million, of which US$204 million is for Phases I and II, US$631 million for Phase III, US$647 million for Phase IV and US$176 million for Phase V (advance action). No definite cost estimates are yet available for the entire Phase V. The Project 3.12 The project comprises Phases IV and V (advance action) of ONGC's Bombay High development program. The main objective of the project is: to complete the development of the southern and central areas of the Bombay High field in order to achieve a plateau production potential of 240,000 Bbl/d (12 million tons/year) by mid-1982. 3.13 The detailed project description appears at Annex 3.3, and can be summarized as follows: (a) Development Drilling. Sixty-four directional development wells, each approximately 1,400 m deep, will be drilled in the Bombay High field and completed in the L-III reservoir, using jack-up drilling rigs. Eight of the development wells will be drilled in the northern area, and the remaining fifty-six in the central and southern areas. About sixty of the wells will be directionally drilled with a horizontal drift from the surface location of 1,400 m to ensure the development of the field according to a 2 km x 2 km five-spot pattern.  - 19 - (b) Well Platforms. Fifteen well platforms will be constructed and installed in the Bombay High field. Two of the platforms will be located in the northern area of the field and thirteen in the central and southern areas. These will be simple four-leg steel structures with decks to carry wellhead assemblies, wellhead panels, flowlines and manifolds. (c) Processing Platform - Bombay High South (BHS). One three-deck, eight-leg processing platform with 180,000 Bbl/d capacity, similar in design and function to the existing Bombay High North (BHN) platform, will be constructed and installed in 80 m of water near the existing SA platform in the central atea. The processing platform will have facilities for the separation of oil, water and gas, oily water treating, main oil pumps, gas handling and compression, telecommunications, telemetry and telecontrol. It will be connected by bridges to SA, the living quarters platforms, and at a later date, to a water injection platform. (d) Living Quarters Platform. For safety reasons and following the practice adopted in the North Sea, personnel working in the BHS complex will be accommodated in a separate living quarters platform to be installed near, and bridge- connected to, BHS. The living quarters platform will be a four-leg, two-deck structure with facilities to accommodate 124 workers. (e) Subsea Pipelines. Approximately 133 km of subsea flow lines varying in diameter from 8" to 20" will be installed to connect the well platforms to the processing platform BHS, and the processing platform to the existing oil and gas trunk lines from Bombay High to Uran. (f) Expansion of Shore Facilities. One 60,000 m cone roof tank and one 90,000 Bbl/d train of crude stabilization facilities, along with necessary utilities, will be added to those under construction at Uran. (g) Extension of Telemetry and Telecontrol. Telemetry and telecontrol facilities which were introduced in the produc- tion facilities as part of the Phase III development program will be extended to cover the additional wells and platforms included in the project.  - 20 - (h) Engineering, Technical Services and Reservoir Consultancy. Consultants to prepare engineering designs and bid documents, supervise construction and assist ONGC in overall project management. CFP has been contracted until April 1981 to assist ONGC in monitoring reservoir performance and in designing and implementing the water injection program. Engineering and Construction 3.14 CFP (France) has been engaged by ONGC since 1977 to carry out reservoir engineering studies of the Bombay High reservoir, with a view to optimizing its future production. Phases IV and V of the development of Bombay High result from the conceptual studies carried out by CFP, which were independently confirmed by ONGC's reservoir specialists. 3.15 Detailed engineering, design, and tendering for the well platforms are being carried out by Engineers India Limited (EIL). EIL initially used a foreign consultant (Crest, US) as back-up for similar platforms, but now has gained sufficient experience in this type of work, which can be substantiated by the successful completion of several platforms without external assistance. As all the well platforms have the same basic design, this arrangement is satisfactory. 3.16 With regard to the major Bombay High South processing platform and the living quarters platform, EIL has already contracted Fluor (US) as back-up designer. 3.17 With regard to the Uran terminal, EIL is the main consultant, with Kellogg (US) as back-up for the LPG plant. Peter Frankel and Partners (UK) are the consulting engineers for the Nhava Sheva supply base. The extension of the telemetry and control facilities will be carried out under the advice of the Electronics Commission, Radar and Communications Project (a public sector enterprise), which has performed satisfactorily for ONGC in the past. These arrangements are satisfactory. During negotiations, assurances were obtained that ONGC will continue to use consultants, whose experience and terms and conditions of employment are satisfactory to the Bank to assist in designs engineering, preparation of bidding documents and supervision of construction of BHS and the living quarters platform. 3.18 With the exception of six well platforms to be constructed by Mazagon Docks Ltd (MDL), all other contracts for offshore facilities (platforms, subsea pipeline construction and laying and platforms erection) are expected to be awarded to reputable foreign contractors and manufacturers. MDL, a public sector entity, started the assembly of simple well platforms in 1979 under the supervision of EIL and foreign consultants. Several platforms built by MDL have already been commissioned, and are now producing satisfactorily. In the future MDL is expected to supply three to four platforms a year.  - 21 - Execution 3.19 The ONGC unit in charge of offshore operations is called the Bombay Offshore Project (BOP) (BOP's organization is described in para. 5.05). The Offshore Operations Division and the Engineering and Construction Division of the BOP will be responsible for project implementation and supervision with the assistance of outside consultants, as described above, and ONGC's support- ing services. The Operations Division, which will supervise and coordinate development drilling, is qualified and sufficiently staffed to supervise drilling contractors and manage the operations of the ONGC-owned offshore drilling units. The staff of the Engineering and Construction Division is competent and adequate to meet the workload generated by the project. By appointing "project managers" for each activity (platforms, pipelines, etc.), BOP has been able to cope with a continuously increasing workload and is expected to perform satisfactorily. Implementation Schedule 3.20 The project would be constructed over a period of approximately two years, with the major portion of the offshore facilities being com- missioned in May 1982 before the onset of the monsoon (Annex 3.4 shows the proposed implementation schedule). All the well platforms will be completed before November 1982, enabling ONGC to produce approximately 100,000 Bbl/d from the southern area wells. The construction schedule is prepared on the basis of ONGC's experience in Phase III of the Bombay High Development Project. It is tight, but achievable. 1/ Estimated Cost 3.21 The total project cost is estimated at US$823.2 million, including contingencies and the customs duties on equipment and materials to be imported for the expansion of the Uran facilities (offshore facilities are exempted from customs duty). The foreign exchange component is estimated at US$722.1 million, or 88% of total cost. The detailed cost estimate appears in Annex 3.5 and can be summarized as follows: 1/ By early 1981, contracts totalling approximately US$350 million would be awarded.  - 22 - Cost Estimate - Phases IV and V (advance action) Cost in Cost in Million Rupees Million US Dollars Local Foreign Total Local Foreign Total Fifteen Well Platforms 364.0 1,623.3 1,987.3 43.3 193.3 236.6 Subsea Pipelines - 231.0 231.0 - 27.5 27.5 Development Drilling 66.0 720.1 786.1 7.9 85.7 93.6 BHS Complex - 1,932.0 1,932.0 - 230.0 230.0 Terminal Facilities 140.0 63.0 203.0 16.7 7.5 24.2 Telemetry & Telecontrol 20.0 42.0 62.0 2.4 5.0 7.4 Engineering/Reservoir Studies 59.0 660.5 719.5 6.9 78.6 85.5 Customs Duties & Taxes 20.0 - 20.0 2.4 - 2.4 Subtotal 669.0 5,271.9 5,940.9 79.6 627.6 707.2 Contingencies: Physical a/ 66.9 507.2 574.1 8.0 60.3 68.3 Price b/ 113.6 286.2 399.8 13.5 34.2 47.7 Total 849.5 6,065.3 6,914.8 101.1 722.1 823.2 a/ At 10% except for reservoir studies (lump-sum). h/ At the rate of 10