Report No. 1569a-IN FILE C3 PtYAppraisal of Bombay HighOffshore Development Project IndiaJune 10, 1977

Regional Projects DepartmentSouth Asia Regional Office

FOR OFFICIAL USE ONLY

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Document of the World Bank

This document has a restricted distribution and may be used by recipientsonly in the performance of their official duties. Its contents may nototherwise be disclosed without World Bank authorization.

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CURRENCY EQUIVALENTS

Except where otherwise indicated, all figures arequoted in Indian Rupees (Rs)

Rs 1.0 = US$0.111Rs 9.0 = US$1.00Rs 1,000,000 = US$111,111

WEIGHTS AND MEASURES

1 Metric Ton (mt) = 1,000 Kilograms (kg)1 Metric Ton (mt) = 2,204 Pounds1 Kilometer (km) = 0.62 Miles1 Ton of oil equivalent

(Toe) = 10 million Kilocalories1 American barrei (b) = 0.15899 Cubic meter

1 Cubic meter (m ) -= 6.289 Barrels1 Cubic foot (cf) = 0.02832 Cubic meter

All conversions from tons to barrels are based on a crudeoil of average specific gravity of 0.84, or 37 degrees API

PRINCIPAL ABBREVIATIONS AND ACRONYMS USED

GOI - Government of IndiaONGC - Oil and Natural Gas CommissionMPC - Ministry of Petroleum and ChemicalsMOF - Ministry of FinanceBHDP - Bombay High Development ProgramHPCL - Hindustan Petroleum Co. Ltd.FCI - Fertilizer Corporation of IndiaOIDB - Oil Industry Development BoardAOC - Assam Oil CompanyOIL - Oil India Ltd.LPG - Liquefied Petroleum GasBH - Bombay HighBN - Bassein North

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INDIAN FISCAL YEAR

April 1 - March 31

-FOR OFFICIAL USE ONLY

INDIA

APPRAISAL OF BOMBAY HIGH OFFSHORE DEVELOPMENT PROJECT

Table of Contents

Page No.

SUMMARY AND CONCLUSIONS ........ . . . . ................. ......... . . . i-iii

I. INTRODUCTION ............................................ t .............. 1

II. BACKGROUND ..................................................... ... 0... 2

A. General ..... ..................... .... 2B. Past and Projected Demand and Supply

of Commercial Energy . ............. .. ......... . . 2

III. THE OIL AND GAS SECTOR .................................. 5

A. Historical Development ............ ................. 5B. Recent Developments ................................ 7

C. Longer-Term Perspectives ........................... 8D. The Role of the Bank ............................... 9

IV. THE PROGRAM AND THE PROJECT ............................. 9

A. Main Characteristics of the Bombay HighArea .......................................................... 9

B. The Development Program ................... *...* .... 10C. Status of Development .............................. 11D. The Project ........................................ 11E. Status of Engineering .......................... 12F. Cost Estimates ...... ............................... 13

G. Items Proposed for Bank Financing .................. 15H. Financing Plan ..................................... 16I. Project Execution, Supervision and Reporting ....... 16J. Procurement and Disbursement ............ ........... 18K. Right-of-Way and Land Acquisition ............. 18L. Operations and Training ........................ .. 18X. Ecology and Safety .19N. Project Risks. . 190. Further Expansion of the Bombay High Offshore Area 20

T his document has a restricted distribution and may be use by recipients only in the perforrnuie of their ofhciol duties. Its contents may not otherwise be disck3ed without World Bank authorization.|

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Page No.

V. JUSTIFICATION .................................. . 00 .......... 20

A. General ............................... o......... ...o ....... .... o . 20B. Sector Objectives ... o ........ .... .. . .. ..... 21C. Justification of the Bombay High Offshore

Development Program ... ........................ 22D. Economic Justification ........................... 24

VI. THE OIL AND NATURAL GAS COMMISSION ..................... 26

A. General .. ...................... ... .... . . 26B. Organization and Management .. .......o .......... 26C. Operations .... ........ o. oo ...... o ............ 28Do Insurance .. .................... ..... . ...... oo. 29E. Finances ............. oo .... .... .... 29F. Audit ......... o...... ooo ........................ 29G. Prices . .. ...... o..o .............oo 30

VII. FINANCIAL ASPECTS ...o ...... .o... .. .... .... . ... .. o. . ..... 30

A. Introduction. .......... o....o ........o ....... 30B. Present Financial Position ......no.... ............. 31C. Financing Plan.. ........... . .. . . . . 32D. Future Finances ................... oo..o .......... 34

VIII. RECOMMENDATIONS ... o ..... o..oo ..... o.................... 35

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LIST OF ANNEXES

1. Bank Group Projects in the Energy Sector2. Glossary of Technical Terms3. Past Commercial Energy Production and Consumption4. Energy Demand Projections5. Development of Energy Resources of India6. Past Petroleum Production and Consumption7. Development of Hydrocarbon Resources in India8. Evaluation of Bombay High and Bassein Reserves9. Details of Engineering Evaluation10. Capital Cost Estimate11. Procurement and Construction Schedule12. Projected Program Disbursements13. Estimated Schedule of Disbursements14. Environmental Impact15. ONGC - Organization Chart as of December 31, 197616. Bombay High Offshore Development Project - Organization Chart17. Particulars of the Insurance Coverage Maintained by ONGC

for Bombay High Development Project as of January 197718. Notes and Assumptions to Financial Statements and Projections19. Consolidated Financial Statements for the Period

1973/74 - 1981/82 - Income Statements20. Consolidated Financial Statements for the Period

1973/74 - 1981/82 - Balance Sheets21. Consolidated Financial Statements for the Period

1973/74 - 1981/82 - Sources and Applications of Funds22. Financial Viability of the Bombay High Offshore Development Project23. Assumptions Used in the Economic Evaluation24. Utilization of the Crude Oil, Natural Gas and Natural Gas

Liquids

MAP S

IBRD 12774 Oil and Natural Gas Sector - Production and Exploration

IBRD 12775 Bombay High Offshore Area.

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INDIA

APPRAISAL OF BOMBAY HIGH OFFSHORE DEVELOPMENT PROJECT

SUMMARY AND CONCLUSIONS

i. In 1975 India's total internal demand for commercial energy wasestimated at 93.2 million tons of oil equivalent, of which petroleum accountedfor about 24%. Per capita consumption was about 11% of the world average.Despite maximum economic use of its domestic energy resources (coal, hydro-power and more recently petroleum and natural gas), India has not achievedenergy self-sufficiency and has to import about 62% of its petroleum require-ments. Following the increase in world oil prices of 1973/74 and subsequentyears, the cost of petroleum imports rose from US$265 million in FY73 to aboutUS$1.6 billion in FY76 when they accounted for about 25% of total imports.Energy demand projections show that, despite conservation and development ofalternative sources of energy (mainly coal), demand for petroleum will con-tinue to grow in the future. Total requirements are estimated at about 50million tons in 1985 and 67.5 million tons in 1990 compared to 22.3 milliontons in 1975.

ii. Current production of crude oil and natural gas is about 8.9 mil-lion tons and 2,300 million cubic meters, respectively, and comes mainly fromonshore fields in Gujarat and Assam. Total onshore reserves are estimated atabout 230 million tons of oil, sufficient to meet about 10 years of cur-rent requirements. India's onshore potential has been partially explored butno exploration of the Continental Shelf took place before 1973 since it wasthought that offshore oil would not be economical at pre-1973 prices. In1973/74 the GOI decided to step up oil exploration offshore and entrustedthis responsibility to the Oil and Natural Gas Commission (ONGC), a statutorybody created in 1959, which had been exploring for and developing hydrocarbonresources onshore. In 1974 ONGC drilled its first offshore exploratory wellin the Bombay High structure, located 160 km offshore Bombay, and struck oil.Subsequent drilling led to the discovery of the North and South Bassein fieldslocated some 100 km west of Bombay. As of March 1977, proven recoverableoffshore reserves are estimated at about 280 million tons of oil equivalent,of which 90% is crude oil and 10% natural gas. The Bombay High and BasseinNorth fields should yield up to 13 million tons of oil equivalent at maximumproduction. ONGC is competent to undertake the development of these twofields and has hired Compagnie Francaise des Petroles (CFP) to assist theirown staff in reservoir engineering studies. Bombay High and Bassein Northproduction will be substituted for crude oil imports and is expected to bringabout net savings of US$16 billion over the next 20 years.

iii. ONGC has already carried out the first two phases of development ofBombay High. Commercial production started in May 1976 and reached twomillion tons per year in March 1977. The project for which the Bank assist-ance is requested consists of Phase III of the development program, which wasapproved by the government in May 1977. It includes drilling of about 20

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development wells and the construction of about five well platforms, threeprocessing platforms, two subsea lines to shore, subtransmission lines andonshore facilities. Design of the pipeline is completed and the contractfor pipes has been awarded. Tender documents for construction of the pipelineand of the first processing platform have been issued; those for the BombayHigh and North Bassein platforms should be issued shortly.

iv. The project cost is estimated at US$571 million of which 73% (US$417million) is foreign exchange. The cost estimates are based on ONGC's histori-cal costs for drilling and well platforms, and consultants' estimates formajor infrastructure. Physical and price contingencies of about 15% and 8%,respectively, have been applied.

v. A Bank loan of US$150 million to the Government of India is proposedfor a 20-year term including three years of grace; it would cover 26% of thetotal cost of the project. The balance will be financed from ONGC's ownresources, Government equity and loans, bilateral aid, loans from the OilIndustry Development Board, and commercial borrowing. The Government hasagreed to relend the proceeds of the Bank loan to ONGC for a period of notmore than 20 years including three years of grace at an interest rate of10-1/4% per annum. The Government has also undertaken to cover promptly allof ONGC's financing requirements, including its working capital requirements.

vi. ONGC, with the assistance of consultants, will be responsiblefor carrying out the project and is competent to do so. ONGC has agreed tohire management consultants to assist in the establishment of adequate projectmanagement procedures and a management information system prior to December31, 1977. Construction of the project is expected to start in the fall of 1977and be completed in 1979. This schedule is tight but manageable.

vii. The proposed Bank loan will finance the foreign exchange cost ofthe construction of the two subsea pipelines and of the construction andequipment of two well platforms, two processing platforms and the gas process-ing plant. Procurement of the Bank-financed items will be according to inter-national competitive bidding. ONGC's procurement procedures, which are satis-factory, will be used for all other items.

viii. The project presents ecological risks inherent to offshore petroleumdevelopment, but ONGC has taken steps to ensure that design and constructionwill be of appropriate standards. A preliminary study of the environmentalimpact of the project has been carried out and will be supplemented by anin-depth study to be financed by UNDP. Adequate protection against sea andair pollution is included in the project.

ix. ONGC is a large organization with a staff of more than 23,000.Its methods of operation are generally adequate. ONGC is implementing acomprehensive training program for offshore operations. In the course of

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project preparation a number of institutional issues were identified anddiscussed with ONGC and the GOI. Satisfactory steps have been taken toresolve these issues, particularly in planning and budgeting and staffingof the offshore project organization.

x. ONGC's financial situation has been satisfactory in the past, andthe GOI has taken the necessary steps to raise the price of crude oil toONGC when required. Financial projections show that ONGC will generatesufficient funds to repay its debt and contribute toward the cost of futureoil and gas development. Since the GOI has decided to finance the developmentof Bombay High by equity and borrowings in equal ratios, ONGC's debt/equityratio will remain satisfactory and will leave a margin for further borrowings.

xi. The GOI has set the price of offshore crude oil at US$5/barrel.At this price the development of Bombay High should yield a discounted cashflow (DCF) return to ONGC of about 19.8%, which is satisfactory. The GOIhas agreed that it will carry out from time to time a review of the price ofthe oil and gas produced by ONGC to determine the price levels needed toenable ONGC, under conditions of efficient operation, to meet its operat-ing expenses and earn a return on invested capital sufficient to cover itsdebt service requirements, maintain adequate working capital and finance asubstantial portion of its proposed capital expansion. ONGC has agreed thatit will prepare and furnish each year to the GOI an economic and financialevaluation of the project and of any subsequent major development which willindicate the level of price required for ONGC to earn a DCF return of atleast 15% and which will also provide information on ONGC's future financialperformance. In the light of ONGC's past and projected performance, it isexpected that ONGC's financial viability will be reflected in rates of returnon invested capital of 10 to 14%, a capacity to self-finance 30 to 50% of itsdevelopment expenditures and an annual debt service coverage of 2 to 2.5times. It is expected that prices which would ensure a DCF return of 15%would bring about at least-such results.

xii. The development of Bombay High will increase India's domesticenergy resources and drastically reduce its dependence on imports. Oiland gas will be used in domestic refineries, fertilizer and other indus-trial plants. The Bombay High development program would yield an economicreturn of 165% if sunk costs are excluded; this return would be 66% if sunkcosts are included. The return is less sensitive to variations in programcosts than to delays in production. A delay of one year would reduce thereturn (including sunk costs) to 50%, which would still be very satisfactory.

xiii. Subject to the recommendations in Chapter VIII of this report,the project is suitable for a Bank loan of US$150, million to the Goveramentof India for a 20-year term including three years grace.

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I. INTRODUCTION

1.01 The increases in the world oil prices in 1973/74 and in subsequentyears have led a number of countries to reassess their energy supply policiesand to look more intensively for domestic sources which could be substitutedfor imports. In India, which imports 62% of its petroleum requirements, theimpact of the oil crisis on the balance of payments was very severe. The costof petroleum imports rose from US$265 million in 1973 to US$1.6 billion in1976, when they accounted for about 25% of total imports. Since India'spetroleum consumption is low and limited to sectors where other sources ofenergy cannot economically be substituted for petroleum, there is little scopefor reducing petroleum imports by developing alternative sources of energy.The Government decided, therefore, to concentrate on developing indigenouspetroleum resources, particularly offshore where potential oil-bearing struc-tures were known to exist but had not been explored since they were not deemedcommercial at pre-1973 prices. The Government entrusted the responsibilityfor offshore exploration to the Oil and Natural Gas Commission, a statutorybody created in 1959, which had been exploring for and developing hydrocarbonresources onshore. In 1974 the Commission drilled its first exploratory wellin the Bombay High structure, located 160 km offshore Bombay, and struck oil.Subsequent drilling led to the discovery of the North and South Bassein fields100 km west of Bombay. The development of Bombay High proceeded rapidly;commercial production started in May 1976 and rose to about two million tonsper year by March 1977. As of March 1977 proven recoverable reserves areestimated at about 250 million tons of oil and 30,000 million cubic meters ofgas, which could yield up to 13 million tons of oil per year and 1,500 mil-lion cubic meters of gas per year, at peak production.

1.02 In February 1976, the GOI requested the Bank to provide guidancein a study of the utilization of natural gas and natural gas liquids to beproduced at Bombay High. A Bank mission visited India to assist in,the pre-paration of terms of reference for this study, and at ONGC's request extendedits assistance to the preparation of terms of reference for a feasibilitystudy of facilities required to produce, transport and process the oil and gasproduction of Bombay High. In 1976 the GOI requested Bank financing for thedevelopment of the Bombay High (BH) and Bassein North (BN) fields.

1.03 The proposed project will be the first project in the Indian oil andgas sector in which the Bank is involved. 1/ It includes the drilling ofdevelopment wells and the construction of production, processing, transportand storage facilities required to utilize the oil and gas production of theBH and BN fields. The total cost of the project is estimated at US$571million, of which 73% is foreign exchange. A Bank loan of US$150 million isrecommended to finance the foreign exchange cost of the construction of twosubsea pipelines, and the construction and equipment of two processing plat-forms, two well platforms and a gas processing plant. 2/ The Borrower willbe the Government of India which will relend the proceeds of the loan tothe Oil and Natural Gas Commission.

1/ Annex 1 provides a list of Bank Group-financed projects in the energysector.

2/ Annex 2 provides a glossary of technical terms used in this report.

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1.04 The present report is based on the conclusions of a preappraisalmission in October-November 1976 and of an appraisal mission in January-February 1977 consisting of Messrs. P. Bourcier (Economist), J. Chang(Financial Analyst), L. Forget (Lawyer), H. Schober (Engineer) and R. Williams(Financial Consultant, U.S.). The estimation of the hydrocarbon reserves isbased on two reports by DeGolyer and MacNaughton (Consultants, U.S.), whichwere commissioned by the Bank.

II. BACKGROUND

A. General

2.01 A striking feature of energy consumption in India is the very largeshare of non-commercial energy in total energy supply. In FY71, the totalshare of non-commercial fuels (animal and vegetable wastes, firewood, char-coal, etc.) was estimated 1/ at 58% of total final consumption, the remainderbeing divided among coal (16.5%), electricity (15.7%) and oil (9.8%). Tenta-tive projections by various institutions and individuals in India and othercountries indicate that, while demand for non-commercial energy will decreasein relative terms in the future, it will continue to increase at about thesame annual rate as the population.

B. Past and Projected Demand and Supply of Commercial Energy

2.02 In 1975, per capita consumption of commercial primary energy inIndia was .157 tons of oil equivalent (Toe), or 11% of the world average.Over the past ten years total demand for commercial primary energy grewfrom 51.8 million Toe (MToe) to 93.2 MToe at an average rate of 6% per annum(Annex 3). Energy elasticity to GNP, over the same period, was 1.85, com-pared to an average of 1.4 for developing countries in the same income group.The main consuming sectors are the mining, manufacturing and transport sec-tors, which together account for about 78% of total demand. The remainder isdivided among residential and commercial (12.5%), agriculture (4.5%) andothers (5%). Since 1965 the sectoral distribution of energy demand has notchanged substantially. Demand projections by the GOI Fuel Policy Committee 2/indicate that demand for commercial primary energy should grow at a somewhatfaster pace (8%) in the future to reach about 300 MToe by 1990 (Annex 4).On the basis of these projections (which take into account the effect of the

1/ P.D. Henderson. India: The Energy Sector. 1974.

2/ Fuel Policy Committee Report, 1974.

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increase in world oil prices in 1973/74), per capita consumption should reach.350 Toe by 1990, which would be equivalent to the per capita consumption ofBrazil in the early 1970's.

2.03 India's energy policy is predicated on the maximum economic use ofdomestic resources, mainly coal and hydropower and, since the late 1950's, pet-roleum and natural gas.

(i) Coal

2.04 India's total coal reserves are estimated at 83,000 million metrictons (Mmt) which should be sufficient to cover the needs of India for thenext 50 years under current assumptions of economic growth. Most coal seamsare concentrated in the northern and north-eastern parts of the country.The coal sector is largely nationalized. Current coal production is about100 Mmt and is expected to increase substantially in the future to reach about135 Mmt by the end of 1978, and about 350 Mmt by 1990. The total investmentrequired to bring about this level of production is estimated at US$7 billion,spread over a period of 15 years. Most of the coal is used in power genera-tionr (35%), steel industry (20%), other industry (15%) and railways (10%).

(ii) Hydropower and Nuclear Fuels

2.05 India's hydroelectric power potential has been estimated at 41,000Megawatts (MW) based on a 60% load factor, of which 8,000 MW will have beendeveloped at the end of the Fifth Plan period (March 1979). The currentshare of hydroelectric generation in total generation is 40% and is expectedto decrease to about 35% by 1990. India's resources of nuclear fuels consistmainly of uranium and thorium, the former being used for the generation ofelectric power. On the basis of current reserves, uranium supplies would meetthe demand for only a limited time, depending on the rate at which nuclearfacilities are built. Currently nuclear power generation accounts for only 2%of total generation but is expected to reach about 10% by 1990.

(iii) Hydrocarbons

2.06 India has a large prospective area onshore (1.7 million sq. km)which has only been partly explored. Its offshore prospective area (.3 mil-lion sq. km) is currently under active exploration. By the end of 1974 atotal of about 330 Mmt of hydrocarbon reserves had been discovered onshore,of which 70% were crude oil and 30% gas. Cumulative production to date isabout 100 MToe. In 1974 and 1976 the Bombay High and Bassein fields werediscovered. Proven reserves to date are estimated to be about 280 MToeof which 90% are crude oil and 10% gas. Other hydrocarbon-bearing structuresin the same area are still under evaluation (Annex 5 and para. 4.01). Crudeoil production in FY77 was 8.9 Mmt of which about .5 Mmt was offshore; itcovered about 38% of total in ernal demand (Annex y); natural gas productionis about 2,300 million m (Mm ), of which 1,300 Mm are used in fertilizer and

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other industries; the remainder is used on the fields or is flared becausethere is no accessible market. Onshore production is concentrated in twoStates: Assam in the northeast and Gujarat in the northwest. Petroleum ismainly used in transportation (49%), the residential sector (28%) and industry(11%) .

2.07 Despite the preferential use of coal, the share of oil and naturalgas in total commercial energy supply grew steadily from 21% in 1965 to about32% in 1973. It has remained constant since, as a result of the increase inthe domestic price of refined products and of the steps taken to increase coalproduction and to substitute coal for liquid fuels, wherever feasible.Domestic production of petroleum has not kept pace with requirements, andIndia's petroleum imports grew from 9.3 Mmt in 1965 to 15.4 Mmt in 1975 at acost of US$1.6 billion, equivalent to 24.5% and 34.5% of total merchandiseimports and exports, respectively. It is projected 1/ that the share ofpetroleum products will be contained to about 20 to 30% of total primaryenergy requirements, which appears reasonable. On this basis petroleum demandin India (for fuel and non-energy use) should reach about 50 Mmt by 1985. Atthat time, the combined production of existing onshore fields and of BH and BNshould peak at about 26.5 Mmt, thus covering about 53% of total requirementscompared to 38% at present. Unless other fields are discovered and broughtinto production, India's imports requirements would then be about 23.5 Mmt ata cost of US$2.3 billion at present oil prices.

(iv) Non-conventional energy prospects in India

2.08 Recently the Indian Government has shown considerable interest indeveloping the use of bio-gas (methane produced from organic waste) as a sourceof energy in rural areas. Even large-scale development would have little effecton the demand for commercial energy since it would substitute principally fornon-commercial fuels. The potential for the use of solar water heaters fordomestic and small-scale commercial use exists but has not yet been developed.In the future solar energy may substitute for commercial fuels to some extent,but is more likely to meet an energy demand which would otherwise remain un-fulfilled. Investigations of the geothermal potential are being carried onin the Himalayan foothills, but the scope for large-scale geothermal develop-ment in India is limited by unsuitable geological conditions in most of thesub-continent, and its overall effect on the energy situation is likely to bemarginal at best.

1/ From Report of the Fuel Policy Committee, 1974, and Second India Studies:Energy (K. Parikh - 1976).

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III. THE OIL AND GAS SECTOR

A. Historical Development

3.01 According to the GOI's Industrial Policy Resolutions of 1948 and1956, the development of the oil and gas sector is the responsibility of theCentral Government, and private firms are given a secondary role except whentheir intervention is deemed to be in the national interest. Over time,India's policies regarding the development of the oil and gas sector havechanged from an almost total reliance on foreign oil companies after Inde-pendence to a strong emphasis on self-reliance until 1973/74. Recently,India has followed a policy of compromise between national autonomy andcooperation with foreign oil companies. (Annex 7 provides a historical over-view of India's policies regarding the development of the oil and gas sector.)

3.02 Today the oil and gas sector consists mainly of public and semi-public enterprises under the Ministry of Petroleum and Chemicals. Over thepast 30 years, the relative importance of these enterprises has varied accord-ing to the resources that were available to them or to the role that theycould play in India's petroleum supplies.

(i) Refining and Marketing

3.03 In 1948 India was almost totally dependent on imports of refinedproducts. However, the GOI soon realized that future economic growth wouldlead to ever-increasing demand for petroleum and that the reliance on importsof refined products would be costly. The GOI therefore approved the con-struction of domestic refineries, owned, supplied and operated by foreign com-panies. This decision was a departure from the Industrial Policy Resolution(1948); however it was expected that it would save foreign exchange 1/, pro-vide expertise in the petroleum field and encourage oil companies to explorefor oil in India. This policy was followed until the early 1960's when theGOI realized that existing supply contracts with foreign companies preventedIndia from taking full advantage of the overall decrease in oil prices thatwas taking place at that time. The GOI then decided to take over the pro-curement of part of its crude oil requirements, to limit the expansion ofprivate refineries and to create sufficient public refining capacity to usewhatever crude oil it could obtain at lower cost. This led to the construc-tion of several public refineries, with the assistance of Eastern Europeancountries, which were integrated into the Indian Oil Corporation in 1964.By 1970 public refineries accounted for about 60% of the total crude oilthroughput.

3.04 Following the increase in world oil prices of 1973/74, the GOIdecided to limit domestic consumption of petroleum to the minimum compati-ble with the projected economic growth. Among other things, this policy

1/ Several studies indicate that from 1955 to 1960 India saved someUS$150 million by refining imported crude oil rather than import-ing petroleum products.

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included drastic increases in the prices of refined products and a plan tomaximize the production of middle distillates (kerosene, diesel and gas oil)which are in short supply. At the same time the GOI entered into a seriesof negotiations to acquire part or all the assets of foreign companies.These negotiations have been completed successfully and the GOI now ownsmore than 85% of total refining capacity and has controlling interest in theremainder.

(ii) Exploration and Development

3.05 Oil was first discovered in India by the Assam Oil Company (AOC) inthe 1880's. AOC produces very small quantities of oil from a virtually de-pleted field in Assam. It is not active in exploration, and the GOI is cur-rently negotiating its takeover.

3.06 The first major steps towards the exploration for and developmentof hydrocarbon resources in India were taken in the early 1950's when theGOI entered into joint ventures with Standard Vacuum Oil Company and withBurmah Oil. The former, known as the Indo-Stanvac Project, was terminated in1960 without positive results. The latter was successful in discovering oilin the north-east and led to the creation of Oil India Ltd. (OIL), in whichthe GOI had a participation of 33% initially which was increased to 50% in1960. OIL's production started in 1959 and reached 3 Mmt in 1970; it has re-mained constant since.

3.07 In the late 1950's, the GOI decided to increase exploration.This decision was based upon the conclusions of Indian geologists, con-firmed by a panel of international experts, that India's prospective areawas under-explored and that the potential for oil discovery was good. In1959 the GOI created the Oil and Natural Gas Commission (ONGC), which wasgiven the task of exploring for and developing petroleum resources in India,outside the areas being prospected by OIL. ONGC started operations with theassistance of experts from the USSR, and soon after (January 1961) discoveredoil and gas in Gujarat. ONGC's production started in 1961, reached 1.1 Mmtin 1965, 3 Mmt in 1970 and 5.7 Mmt in 1976. ONGC-'s initial success was notfollowed by the discovery of any significant oil and/or gas reserves onshore.The increase in world oil prices, however, led the GOI to intensify itssearch for domestic oil and to promote exploration offshore. This effortwas successful and resulted in the discovery of Bombay High in 1974 and ofBassein North and South in 1976.

3.08 ONGC has become India's main organization for the exploration forpetroleum and natural gas. It has exclusive rights to undertake and/orsupervise these activities onshore (except in the areas allocated to OIL) andoffshore. ONGC is a large organization with considerable experience in on-shore operations. Until recently ONGC's experience offshore was limited tosome shallow-water fields in Gujarat.

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B. Recent Developments

3.09 The increase in the world oil prices of 1973/74 led to a drasticincrease in the cost of petroleum imports and introduced the need for areappraisal of earlier programs for exploration and development and forlong-term supply of petroleum. The Report of the Fuel Policy Committee (1974)analyzes the consequences of higher petroleum prices and makes the followingpolicy recommendations:

(i) steps should be taken to reduce the cost of production ofpetroleum products;

(ii) steps should be taken to improve the long-term securityof supply; and

(iii) imports of petroleum should be reduced by substitutingother fuels (coal) for petroleum and by increasing theindigenous production of crude oil.

To achieve these objectives, the Fuel Policy Committee recommended inter aliaan optimization of the refining pattern to meet the projected product demandmix at least cost, the negotiation of long-term supply agreements with OPECcountries and the possibility of developing oil resources in the Middle East,and an intensification of exploration in India, particularly offshore wherethe most promising prospects were located.

3.10 The policy followed by the GOI since 1974, which is analyzed indetail in World Bank Report 1172-IN 1/ and summarized below, is generallyin line with the Fuel Policy Committee's recommendations. The GOI has takensteps to increase petroleum product prices and rationalize refinery operationsand expansion. It has also negotiated supply contracts with Iraq and Iran, andONGC has entered into joint venture and service contracts in Iraq, Iran andTanzania; The contract with Iran should provide about .7 Mmt per annum ofparticipation crude oil. Other foreign ventures may be considered in thefuture. The most dramatic steps, however, were taken in exploration for anddevelopment of domestic hydrocarbon resources and particularly in the explora-tion and development of the offshore potential. ONGC's exploration programonshore was expanded considerably. Offshore, first priority was given to thedevelopment of the Bombay High and Bassein North fields which mark a turningpoint in India's oil industry. In addition, the GOI decided to open tenoffshore areas to foreign exploration under production-sharing contracts.Three contracts, in which ONGC has a working interest, were signed withReading and Bates (U.S.), Natomas (U.S.) and Asamera (Canada) to explorein the Kutch Basin, the Bay of Bengal and the Cauvery Basin, respectively.The first exploratory wells were sunk in 1975 and 1976 but no commercialdiscovery has yet been made.

1/ India, The Oil and Gas Sector. May 11, 1976.

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3.11 This increase in domestic exploration and development activities,which will be carried out almost entirely by ONGC, is reflected in the suc-cessive increases in the Plan allocation to the oil and gas sector. Therevised Fifth Plan target for exploration, development and refining duringthe Plan period is Rs. 16,913 million (US$1,879 million), or 4.3% of totalPlan outlay. ONGC's allocation, which was originally Rs. 6,940 million(US$771 million), is currently estimated at Rs. 10,561 million (US$1,173million), equivalent to 62% of the sector's total expenditures excludingpetrochemicals. But even this amount, which is greatly increased over thedraft Fifth Plan, both in real and relative terms, is likely to be exceeded.From a total FY75 Plan outlay of over Rs. 800 million, ONGC's Plan expendi-tures rose to over Rs. 1,800 million and Rs. 2,800 million in FY76 and FY77,respectively.

3.12 ONGC's current Five-Year Plan provides for the expansion of itsonshore activities to reach a production of about 33.3 Mmt over the FifthPlan period compared to 19.4 Mmt in the previous one. This will be achievedmainly by introducing secondary recovery wherever feasible. In addition,survey work, exploratory and development drilling will be intensified.Modern digital equipment and computer facilities are being introduced, andby March 1979, the number of drilling rigs will be increased by 19. Drill-ing targets for FY78 are 294,000 meters compared to 191,000 in FY75. Thetotal cost of the onshore program through FY79 is estimated at aboutRs. 3,600 million (US$400 million).

3.13 Offshore, the emphasis will be on the completion of the developmentof Bombay High and of North Bassein. The cost of this program, includingprice contingencies, is estimated at US$1,774 million. The program, which isdescribed in Chapter IV, will be implemented by ONGC with the assistance ofoutside consultants and contractors. The proposed project for which a Bankloan of US$150 million is recommended consists of Phase III of the offshoredevelopment program.

C. Longer-Term Perspectives

3.14 India has a large prospective offshore area which needs to beexplored and developed as soon as possible to offset future increases inthe cost of petroleum imports. However, the time frame in which this poten-tial can be developed depends largely on the resources which are allocatedto the oil and gas sector and on ONGC's capability to manage a much largerexploration and development program in the future. The GOI is aware of thisand has taken steps to secure a reliable resource base for the oil and gassector. Crude oil prices have been set at a level which will ensure that ONGCwill generate sufficient resources internally to finance a reasonable share ofthe Bombay High and North Bassein development. In addition the GOI has givenhigh priority to the financing of the offshore program from Central Budgetresources and from the Oil Industry Development Board, created in 1974 toassist in the financing of oil and gas projects, and is also mobilizingalternative sources of financing (bilateral aid and commercial bank loans)(para. 7.07).

D. The Role of the Bank

3.15 The discovery and development of Bombay High has presented theGOI and the Commission with technical and managerial challenges to whichthey have responded in a pragmatic way. However, further developments willrequire further improvement in ONGC's managerial and technical capabilities,particularly in long-term planning and budgeting. The Bank has been involvedin the preparation of the Bombay High Development Project (BHDP) and, cancontinue to assist ONGC by providing advice on project evaluation methodscurrently used in the oil industry. ONGC is instituting managerial andfinancial improvements in offshore operations, and Bank involvement in theproposed project can also be useful in this regard.

IV. THE PROGRAM AND THE PROJECT

A. Main Characteristics of the Bombay High Area

4.01 The Bombay High and Bassein fields are located some 160 km and100 km, respectively, offshore Bombay. They are part of a number of struc-tures which were identified during a seismic survey in 1966 and which arecurrently under-exploration. The Bombay High field was discovered in 1974and the Bassein field in 1976. -Map 12775 shows the location of thesefields.

4.02 Total proven recoverable reserves of oil are currently estimated atabout 250 Mmt, using primary and secondary recovery techniques (depletion, gaslift and water injection). In addition it is estimated that the Bombay Highand Bassein North fields could yield an additional 85 Mmt of oil when probablereserves currently under evaluation have been confirmed. For the purposeof this report, only proven reserves have been considered. Reserves esti-mates are based on studies made by ONGC, the Indian Institute of PetroleumExploration and foreign consultants (Geoman, U.S., and Compagnie Francaisedes Petroles, France) and on an independent evaluation carried out by DeGolyerand MacNaughton (consultants, U.S.) at the request of the Bank. The resultsof these studies are summarized in Annex 8.

4.03 According to these studies, Bombay High maximum production shouldreach about 225,000 barrels per day (b/d) of crude oil and about 3.4 Mm3 /dayof associated gas by 1982. These projections are based on a production ex-perience of about 12 months and are considered reasonable. The maximumproduction of Bassein North is currently estimated at about 40,000 b/d whichis considered conservative. Continuous review of reservoir behavior will be

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required during the life of the field, to optimize development and hydrocar-bons recovery. ONGC geologists have extensive experience in reservoir engi-neering but are not familiar with this type of reservoir (limestone forma-tion). ONGC has entered into a four-year contract with Compagnie Francaise''des Petroles (CFP), whereby CFP will assist ONGC staff'in the interpretatiorn' 'of seismic data, in mathematical reservoir modelling and in production optimi-zation using primary and enhanced recovery techniques. ONGC has agreed tosubmit to the Bank an updated development plan of the Bombay High and NorthBassein fields by the end of each calendar year starting in 1977.

B. The Development Program

4.04 On the basis of existing reserves studies ONGC, the potential'usersand their consultants have prepared plans for the development and utilizationof the crude oil and natural gas to be produced in the Bombay High area untt1982. '"

4.05 ONGC's development program was approved by the Commission in January1977, at a meeting attended by the Secretary (Economic Affairs),. Ministry- ofFinance and the Secretary (Petroleum), Ministry of Petroleum and chemicals.These plans call for development in five phases. Phases I and II; ..' ch ea.Xalmost completed, consist of the construction of the production,f'acilitie X(wells, well and production platforms) required to reach a productlon.'cap''- ity of 80,000 b/d (4 Mmt/year) by the end of 1977 and of the constructionffof0temporary tanker transport facilities to bring crude oil to shore. Duing -Phase I and II all the associated gas will be flared offshore. Phase IIf-wasapproved by the Government in May 1977 and consists of the drilling of a 20 development wells and the construction of about five well platforms to-6~, t, 2_,reach a production of 140,000 bld by the end of 1978, as wellt as the. const -tion of three processing platforms, permanent pipeline transport faciilties~and shore facilities. Phase IV and V will consist of the constructione ofadditional facilities to reach a production of 265,000 b/d by 1982, ining the drilling of about 60 to 70 development wells and about.30: waterin-jection wells and the construction of the corresponding well platforms- andX iprocessing facilities. The entire program is expected to extend into ithe,iearly 1980's at a total cost estimated at US$1,774 million, of vhich DS204'million will be for Phase I and II, US$571 million for Phase III I/:a 'iI

US$999 million for Phases IV and V.

4.06 The crude oil and natural gas produced at Bombay High and Bassein lWNorth will be substituted for imported crude oil supplies to domestic 're'-2 + ';.2.';^fineries and used in fertilizer and other industrial plants. Because of-,'`.-

1/ The cost of Phase III as approved by the Government is US$593.3 million,but it includes interest during construction which is not included in:',the Bank's estimates.

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the characteristics of the Bombay High crude oil (high wax content, highpour point), some modifications are required at existing refineries. TheTrombay refineries, which are the first concerned, have already completedmost of the revamping and other refineries are expected to carry out thenecessary adjustments during the execution of Phase III. Current plans areto use the associated gas in the Trombay fertilizer complex of the Fertil-izer Corporation of India (FCI). The decision to convert some units tonatural gas at FCI's Trombay plant has already been taken and further gasutilization studies are being carried out with the assistance of Stone andWebster (Consultants, U.S.). Liquefied Petroleum Gas (LPG) will be used inthe residential and commercial market.

C. Status of Development

4.07 The first phase was completed in March 1977, three months behindschedule because of unexpected problems in the driving of piles for oneplatform. It consisted of the drilling of ten development wells and of-theconstruction of three well platforms and one, production platform in thenorthern part of the Bombay High field to achieve a production of 40,000 b/d.It also included the construction of two Single Buoy Moorings to anchor astorage tanker and a shuttle tanker. This temporary transportation systempermitted commercial production to start in May 1976, but had to be inter-rupted during the monsoon. The second phase, which is essentially identicalto the first, is virtually completed and total production from Bombay Highwill reach 80,000 b/d by the end of 1977 as planned. During Phase I and IImost of the exploratory and development drilling was carried out by contrac-tors under the supervision of ONGC Offshore Operations Division (para. 4.19).Construction of the well platforms and of two production platforms was carriedout by McDermott (Contractors, U.S.) under the supervision cf ONGC's OffshoreConstruction Division (para. 4.19).

D. The Project

4.08 The project comprises Phase III of ONGC's development program andincludes the facilities listed below. Annex 9 gives a detailed descriptionof the project facilities and of the operations for which they are required.

(i) Development drilling. About 16 production wells willbe drilled at Bombay High North and 4 at Bassein alongwith the necessary well platforms. Four deviated wellsdraining an area of about 6 sq. km. will be drilledfrom each platform. These will be connected bysubsea gathering lines to the main processing plat-forms.

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(ii) Processing platforms. A total of three processing platformswill be installed, two in the northern part of the BombayHigh field and one at Bassein North. The BH platforms willhave a combined capacity of 160,000 b/d and the capacity ofthe BN platform will be 60,000 b/d.

(iii) Subsea pipelines. Two 209 km subsea pipelines, 30" and 26"in diameter, will be laid to transport oil and gas, respec-tively.

(iv) Onshore terminal. The two subsea pipelines will terminateat Uran (in the Bay of Trombay), where a terminal will bebuilt, including a crude oil stabilization unit, a gasprocessing plant and storage facilities, from which thecrude oil will be pumped to the Trombay refineries. Ex-isting pipelines between Butcher Island and Trombay willbe used to load the crude aboard tankers for shipment tocoastal refineries or for export.

(v) Supply lines. Four different supply lines, 8" to 30" indiameter, will cross the Bay of Trombay to connect the Uranterminial to the various users.

(vi) Supply base. Berthing facilities for supply vessels,repair shops, warehouses, administrative buildings andoffices will be built at Nhava Sheva, a site recentlyacquired by ONGC.

(vii) Telecommunications and control. A telemetric communica-tion and control system will be installed to cover theentire Bombay High program.

(viii) Engineering and technical services. Consultants have beenor will be engaged to prepare detailed engineering designs,supervise construction and assist ONGC in overall projectmanagement.

E. Status of Engineering

4.09 The Phase III facilities are based on a feasibility study preparedin 1976 by Pipe Line Technologists (PLT), Consultants, UK. This study definedthe main parameters of the pipelines, processing platforms and onshore facil-ities. In addition ONGC retained Engineers India Limited (EIL) in collabora-tion with Crest Engineering (U.S.) to carry out additional studies on theBombay High North and Bassein North processing platforms. These consultingorganizations were subsequently assigned to engineer, design and assist inthe supervision of the construction of the pipelines and interim platform(para. 4.20) (PLT) and of the Bassein North and Bombay High processing plat-forms (EIL/ Crest).

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4.10 PLT have completed design and procurement documents for the two sub-sea pipelines, the land and harbor supply pipelines and the interim processingplatform at Bombay High North. Contracts for pipe and related materialshave been awarded. Bids have been received for the interim platform andare being evaluated. The pipe construction bid documents have been issuedand contract awards are scheduled for the latter part of July 1977.

4.11 EIL/Crest are designing the Bassein North process platform and arescheduled to have bid documents ready for issue by July 1977. They will thendesign and prepare bid documents for the Bombay High North platform for whichbid invitations are scheduled to be issued during August 1977.

4.12 Engineering consultants for the onshore terminal at Uran have beenselected. It is expected that the crude oil stabilization, oil storage andpumping portion of the work will be assigned to Humphreys and Glasgow (Con-sultants, U.K.) after the GOI has approved the contract. A consulting firmmust still be selected for the gas processing plant, but there is no immediateurgency in starting this work.

4.13 Peter Fraenkel and Partners (Consultants, U.K.) have been givenengineering and design responsibility for the Nhava Sheva supply base. Tele-communication and control facilities have been assigned to Burmah Oil Engi-neering and the Defense Ministry. All engineering consultants engaged byONGC are experienced and qualified for the tasks assigned to them. ONGChas agreed that they will continue to use consultants whose qualifications,experience and terms and conditions of employment are satisfactory to theBank, until the completion of the Project.

F. Cost Estimates

4.14 The Project cost is estimated at US$571.0 million, including con-tingencies and customs duties (from which part of the offshore facilities areexempted). The foreign exchange component is estimated at US$417.0 millionor 73%. Annex 10 gives details of the cost estimates which are summarizedbelow. Annex 12 indicates the phasing of expenditures over the period 1977-1981.

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SUMMARY OF PROJECT COSTS

(Rs million) (US$ million)Local Foreign Total Local Foreign Total %

Development drilling

Wells 110.0 332.0 442.0 12.0 37.0 49.0 8.6Well Platforms 80.0 250.0 330.0 9.0 28.0 37.0 6.5

Subtotal 190.0 582.0 772.0 21.0 65.0 86.0 15.1

Infrastructure

Land 40.0 - 40.0 4.5 - 4.5 0.8Pipelines 159.0 1,345.0 1,504.0 18.0 149.0 167.0 29.2Processing Plat-forms 22.5 742.5 765.0 2.5 82.5 85.0 14.9Uran Oil Terminal 153.0 4.5 157.5 17.0 .5 17.5 3.1Gas ProcessingPlant 67.0 45.0 112.0 7.0 5.0 12.0 2.1Oil StabilizationPlant 90.0 9.0 999.0 10.0 1.0 11.0 1.9Nhava Sheva SupplyBase 138.0 - 138.0 15.0 - 15.0 2.6Telecom and

Control 72.0 36.0 108.0 8.0 4.0 12.0 2.1Custom Duty 108.0 - 108.0 12.0 - 12.0 2.1Engineering;Technical Ser-

vices and ProjectSupervision 80.0 250.0 330.0 9.0 28.0 37.0 6.5

Subtotal 929.5 2,432.0 3,361.5 103.0 270.0 373.0 65.3

Total Base Cost 1.119.5 3.014.0 4,133.5 124.0 335.0 459.0 80.4

Physical Contin-gencies (15.3%) 171.5 461.0 632.5 19.0 51.0 70.0 12.3

Price Contin-gencies (8.0%) 103.0 278.0 381.0 11.0 31.0 42.0 7.3

TOTAL 1,394.0 3,753.0 5,147.0 154.0 417.0 571.0 100.0

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Development drilling costs were derived from ONGC's historical costs andreflect conditions likely to prevail in the next two years. However, anoverall physical contingency of 15% was applied to the cost of wells andwell platforms to account for non-productive wells. The costs of infra-structure are based on PLT cost estimates and reflect conditions in early1977. Physical contingencies of 57 and 25%, 1/ respectively, were appliedon the cost of materials and construction for the main offshore facilities(pipelines and platforms). For the shore facilities and telecommunicationssystem, which have not yet been designed in detail, an overall physicalcontingency of 20% was applied. Price contingencies amount to 8% of theproject cost (including physical contingencies) and are based on an annualrate of escalation of 7% for material and equipment and of 9% for civilworks.

4.15 The cost of consultants' services was estimated on the basisof actual contracts and of prevailing rates in India and abroad. 2/ Totalmanpower requirements are estimated to be 11,000 man-months of which about70% will be foreign. The average cost per man-month is estimated atUS$3,600 and US$1,800 for foreign and local consultants, respectively.

G. Items Proposed for Bank Financing

4.16 The proposed Bank Loan of US$150.0 million would finance the for-eign exchange cost of the construction of the two subsea pipelines and theequipment and installation of the Bassein North and Bombay High North pro-cessing platforms, two well platforms and the gas processing plant. Thesecontracts are suitable for international competitive bidding and are likelyto attract a large number of suppliers and contractors. The proposed Bankloan would finance about 26% of the total cost, and about 36% of the foreignexchange cost of the project, including contingencies.

1/ The high physical contingencies reflect the difficulty of offshore

construction which depends on unpredictable weather conditions.

2/ These costs do not include the cost of CFP's services which will extendbeyond the scope of the proposed project and will not be limited toBombay High.

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H. Financing Plan

4.17 ONGC's total financial requirements from FY78 to FY80 for BombayHigh and Bassein North development expenditures, are currently estimated at

Rs 8,438 million (US$937.6 million), of which Rs 5,147 million (US$571 mil-lion) is for the project and Rs 3,291 million (US$366.6 million) is forPhases IV and V. ONGC's financial projections show that Rs 3,486 million(US$387.3 million) will be financed from internal cash generation. The

balance will be financed, in equal ratios, by equity contributions fromthe GOI and loans from the GOI and the Oil Industry Development Board, asindicated below:

Summary Finance Plan, FY78-80Rs million US$ million %

Total requirements:of whichThe Project 5,147 571.0 61.0Phases IV and V 3,291 366.6 39.0

Total 8,438 937.6 100.0

Financed by:internal cash generation 3,486 387.3 41.4GOI equity /1 2,476 275.2 29.3loans /2 2,476 275.1 29.3

Total 8,438 937.6 100.0

/1 Including an estimated US$50 million of bilateral aid (e.g.,Japan, France, U.K., Germany).

/2 Including the proceeds of the Bank loan (US$150 million)loans from OIDB (US$70.3 million), the GOI (US$4.8 mil-lion) and commercial banks (US$50 million).

4.18 The GOI has agreed that it would relend the proceeds of the Bankloan to ONGC at an interest rate of 10-1/4% per annum for a period not exceed-ing 20 years including three years of grace. The GOI has further agreed thatit would provide sufficient funds to meet ONGC's financial requirements forthe project and other investments.

I. Project Execution, Supervision and Reporting

Execution

4.19 The Offshore Operations and Construction Divisions will be respon-sible for project implementation and supervision with the assistance of out-side consultants (para. 4.w9-4.13) and of ONGC's advisory services. The

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Operations Division, which will supervise and coordinate development drilling,is qualified and sufficiently staffed to supervise drilling contractors. Thestaff of the Construction Division is competent and is currently being in-creased to meet the additional work load generated by the project. ONGChas already transferred experienced personnel from its onshore operationsto the project staff and has appointed an offshore project manager who willalso be responsible for the entire Construction Division. Experienced sub-project managers have been appointed for the pipelines, platforms and crudeoil stabilization plant. The selection of subproject managers for telecom-munications and for the gas processing plant is underway. These arrangementsare satisfactory. However, there is a need to improve the ConstructionDivision's capability in project scheduling and in overall project management.ONGC has agreed to hire management consultants to assist in the establishmentof adequate project management procedures and of an appropriate managementinformation system prior to December 31, 1977.

Construction Schedule

4.20 The project should be constructed over a period of two years withmost of the offshore facilities being completed by mid-1978 (Annex 11 showsthe proposed construction schedule). Because of the impossibility of under-taking any major construction offshore during the monsoon (June to October),ONGC has decided to complete the two subsea pipelines, the Bassein Northplatform, the critical facilities of the onshore terminal and the supply lineby May 1978. The Bombay High North platform will be completed only at the endof 1978 or early in 1979. However, in order to ensure that the two pipelinescan be used during the 1978 monsoon to transport oil and gas (the latter wouldcontinue to be flared otherwise), ONGC has decided that an interim platformwill be installed at Bombay High by May 1978. This platform, will be builtadjacent to the location of, and will be subsequently connected to, the BombayHigh North platform. Although the construction schedule is tight, it isachievable and the fact that there is a temporary worldwide lull in offshoreconstruction activity should help ONGC achieve its objectives.

Supervision and Reporting

4.21 ONGC is competent to supervise the execution of the project with theassistance of management consultants (para. 4.19) and of the consultantsreferred to in paras 4.09 to 4.13. ONGC's internal reporting procedureswill be improved under the provision of para. 6.08. ONGC has agreed to sendcopies of quarterly progress reports to the Bank.

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J. Procurement and Disbursement

4.22 International competitive bidding procedures, in accordance withBank guidelines, will be followed for the Bank-financed items. No localsuppliers or contractors are expected to bid on these terms; however, for thepurpose of bid evaluation, a preference of 15% or the custom duty, whicheveris less, will be applied to any local bid. Bid invitation and evaluation willbe the responsibility of ONGC with assistance from consultants as required.ONGC's normal procurement procedure for foreign supplies requires worldwidebidding similar to the Bank's ICB. It is expected that this procedure will beapplied for all imported equipment and services not financed by the proceedsof the Bank loan. ONGC has indicated that, in order to save time, it wastheir intention to call for lump sum bids for the Bassein North and BombayHigh North platforms; since this procedure will not restrict competition, itis acceptable to the Bank. Bid invitations for critical items with limitedavailability, which are essential to efficient execution of the project andestimated to cost less than US$2 million, may be sent directly to the quali-fied available suppliers, provided that the Bank's prior approval is obtainedfor these items and the list of suppliers and that the aggregate amountprocured under this procedure does not exceed US$7.5 million.

4.23 Disbursement will cover 100% of the foreign cost of Bank financed

contracts. Disbursement of the Bank loan is expected to be completed inthree years. (Annex 13 gives the estimated schedule of disbursement ofthe Bank loan.) The closing date of the proposed loan would be December 31,1980.

K. Right-of-Way and Land Acquisition

4.24 No right-of-way problem is expected offshore, since ONGC's proposedpipeline route does not cross any shipping channel. Onshore, ONGC is in theprocess of acquiring the land required for the Uran terminal and the supplybase. Negotiations are at an advanced stage and no difficulties are expected.The onshore supply lines have to be routed so as to minimize right-of-wayproblems and negotiations with the Port Authority and other State Governmentagencies are progressing satisfactorily. Obtaining formal title may taketime but is not expected to delay project execution. ONGC has agreed totake all actions necessary to acquire as and when needed the land and rights-of-way required for construction of the project facilities.

L. Operations and Training

4.25 ONGC's staff is adequately trained to carry on its present off-shore operations, but operating and maintaining the new and more complexfacilities of the Bombay High project will require additional operationaland supervisory staff training. (See Annex 9 for a description of ONGC'soperations and facilities.) ONGC's management recognizes the need for

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this training and has budgeted the equivalent of US$700,000 to fund a train-ing program. A detailed program is being formulated. It will comprise localand on-the-job training, training abroad at equipment manufacturers' plantsand foreign installations, and various special training related to offshoreoperations, safety, pollution control and related subjects. As part of itsprogram, ONGC plans to accept offers of offshore training by the British andNorwegian governments. These arrangements are satisfactory.

M. Ecology and Safety

4.26 Pipelines properly protected, maintained and operated pose noserious environmental hazards. Accordingly, all necessary precautions willbe taken during design and construction of the oil and gas pipelines tominimize the chances of overpressurization, corrosion and third-partydamage. The offshore and terminal facilities will not cause noticeableatmospheric pollution, and effluents, essentially oily water and humanwaste, will be adequately treated before disposal. ONGC is procuring avessel outfitted for offshore fire-fighting and oil spill clean-up. Inaddition the GOI is activating a National Coast Guard service, which willbe assigned responsibility to assist in offshore oil emergencies. Allmanned platforms will be equipped for fire-fighting and will be providedwith proper emergency escape and survival systems (Annex 14). In addition,ONGC plans to adopt the North Sea safety regulations during construction,and has commissioned an in depth study of the environmental and safetyaspects of the project. The study will be financed by UNDP.

N. Project Risks

4.27 The risks normally associated with hydrocarbon development projectsare compounded for offshore ventures by weather conditions. However, overthe years the industry has developed techniques and technologies which, ifthey do not eliminate risks, reduce them to an acceptable level. The tech-nical solutions selected by ONGC have been proved reliable, ONGC's con-sultants have considerable experience in the design and construction ofoffshore and onshore facilities, and experienced contractors will be selectedfor project implementation. ONGC's staff is qualified and experienced in allthe facets of oil and gas production, processing and utilization and, there-fore, the risk of errors in design and/or operation is minimal. Weatherconditions, however, are not predictable and may cause delays despite theprecautions taken to avoid major construction work offshore during the monsoon.

4.28 9'ere is a risk that the fields will not live up to ONGC's expecta-tions. It is impossible to fully predict the behavior of a reservoir, andfields have been known to "dry up" much sooner than expected. ONGC has beencareful and conservative in its approach to the evaluation of the fields and

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has used experienced consultants to assess both the reserves and the produc-tion mechanisms. All estimates are consistent and show that the fieldsshould eventually produce more than was anticipated originally. During theearly years of production, ONGC staff and CFP will monitor the behavior ofthe reservoirs and provide sufficiently advanced warning of any problems forONGC to take remedial actions.

0. Further Expansion of the Bombay High Area

4.29 The two main structures, Bombay High and Bassein North, are underintensive development. Another structure, Bassein South, has been identified,and is a gas field. Other structures at the periphery of BH are still underexploration; several wells have been drilled which have indicated the pres-ence of hydrocarbons but not of commercial quantity. There are several un-explored structures in the area which, on the basis of seismic data, appearto be as promising as the two Bassein fields. It is likely that the total oiland gas recovery from this area will exceed what is currently planned for BHand BN. For this reason the pipeline and platforms have been designed for ahigher ultimate capacity so as to avoid costly capacity expansion if more oiland/or gas is discovered. This is standard practice in offshore development,and the impact on the project cost is minimal as the costs of the pipeline andof the platforms are not very sensitive to size.

4.30 The Bassein South field will not be developed in the near futuresince there is no immediate outlet for the gas. Several alternatives arebeing considered for the future utilization of this gas, the most likelybeing to use the gas in the Trombay area or in Gujarat.

V. JUSTIFICATION-

A. General

5.01 The discovery and development of Bombay High and Bassein representsa significant step towards India's self-sufficiency in petroleum. Untilrecently, it was expected that the share of onshore production in totalpetroleum requirements would decrease in relative terms, although productionwould continue to increase at about 4% per annum. The development of offshorefields will reverse this trend and total domestic production from onshore andoffshore fields is now expected to reach about 50% and 36% of total internalrequirements in 1985 and 1990, respectively, thus saving India about US$16.0billion over the next 20 years.

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B. Sector Objectives

5.02 ONGC is, and will continue to be, the main oil exploration anddevelopment agency in India, either on its own, as in the case of BombayHigh, or in association with foreign oil companies which are currentlyoperating under production-sharing contracts. In spite of its lack ofexperience offshore, ONG has managed the development of a giant field 1/very efficiently . The Commission has used outside consultants and contrac-tors to assist their staff in the design of the program and in the construc-tion of the first stage, while training their staff in offshore developmenttechniques. Faced with the single largest development program in the historyof India's oil and gas sector, the Government has taken steps to make foreignexchange available in time and to eliminate bureaucratic procedures, whichmight have delayed the program. India's offshore potential remains, how-ever, largely unexplored, and Bombay High is only the first step in a longprocess which could eventually lead to self-sufficiency in oil. It iscurrently estimated that about US$1.5 to 2 billion would have to be invested,in exploration alone, over the next 10 years to fully evaluate India's poten-tial. Part of the resources required may be provided by foreign oil companiesunder production-sharing contracts. However, the GOI and ONGC will have toallocate a substantial part of the income generated by Bombay High to financetheir own share of exploration and to develop any new resources that may bediscovered, if the current offshore momentum is to be maintained in thefuture.

5.03 For the first time, the Bank has been directly involved in the oiland gas sector. Its initial involvement, in the preparation of terms ofreference for the utilization of natural gas, was extended to the preparationof terms of reference for the initial feasibility studies of Phase III of thedevelopment program and the review of consultants' proposals. During thepreparation of the Project, the GOI, ONGC and the Bank have identified anddiscussed a number of institutional issues which have been or are in theprocess of being resolved satisfactorily, i.e., long-term planning and budget-ing (paras. 6.06 and 6.07), ONGC's management information system (para. 6.08)and the need for external consultants in project management (para. 4.19) andreservoir engineering (para. 4.03). But these are only the first steps in thestrengthening of ONGC's managerial and operational capabilities, which isrequired to manage the much larger and complex exploration and developmentprogram that lies ahead. The role of the Bank should therefore be viewed in asomewhat broader perspective, which is to assist ONGC in building up anorganization which will help India become self-sufficient in petroleum in the

1/ By industry standards, a giant field is a field that would yield morethan 500 million barrels (about 70 million tons) of recoverable oilreserves.

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minimum possible time at least cost. One of the areas in which the Bank hasbeen and will continue to be of immediate assistance is in providing adviceon how the methods used by oil companies to evaluate the feasibility of oildevelopment projects (para. 5.05) can be used in ONGC's context.

C. Justification of the Bombay High Offshore Development Program

5.05 Oil companies have developed financial analysis procedures toassist management in deciding which projects should be developed and in whichorder, and how limited capital funds can be allocated in the most efficientway. To do this two levels of analysis are required. First, each projectmust yield a discounted cash flow (DCF) rate of return and payout time whichsatisfy the profitability and cash flow objectives of the enterprise. Second,since there are several ways in which a field can be produced, the rate of re-turn on incremental capital outlays for different alternatives must be eval-uated. While these procedures were originally developed for privateoil companies, they also apply to national oil companies such as ONGC.

5.06 The evaluation of the Bombay High Offshore Development Program(BHDP), including Phases Ito V, has been carried out on the basis of theproduction schedule-derived from the De Golyer and MacNaughton studies (para.4.02) and under two different price assumptions (US$13 per barrel, whichis the present international price and US$5 per barrel which is the priceset by the GOI for offshore crude oil). The results of the analysis arein Annex 22 and are summarized below. The purpose of this evaluation isto determine the impact of the entire program, as opposed to the Project,on the economy of India (US$13/barrel, excluding income tax) and on ONGC'scurrent and future financial viability (US$5/barrel, including income tax).

t

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Summary Evaluation of the Bombay High Offshore Development Program

US$13/barrel US$5/barrelexcluding income tax including income tax

DCF return (%) 66.2 19.8

Maximum negativeCash Flow (Rs million) 3,238 6,129

Pay out time fromApril 1, 1977 (years) 1.7 4.8

Net Present Value(Rs million) at discountrates of:

- 10% 60,138

- 20% 30,258

- 40% 9,720

5.07 At US$13/barrel, excluding income tax, the development of BombayHigh and North Bassein would yield a DCF return of 66.2%. The Net PresentValue (NPV) of the savings generated by the Program at the opportunity costof capital (estimated at 10%) would be Rs 60,138 million (US$6,682 million)over the life of the fields, reflecting a discounted production cost perbarrel of about US$3.15 per barrel.

5.08 At US$5/barrel, the Program would yield a DCF return after taxesof 19.8% to ONGC. This return is comparable to what international oil com-panies normally require for their domestic operations and is consideredsatisfactory. The following table summarizes the breakdown of the cost ofoil per barrel calculated on the basis of annual depreciation:

Breakdown of the cost of oil per barrelUS$/barrel %

Exploration .33 5.5Production Cost /1 1.76 29.5Taxes 2.24 37.5Net profit 1.64 27.5

Total 5.97 100.0of which income derivedfrom natural gas and LPG .97

/1 Includes operating cost, depreciation and financial charges.

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This shows that the current price of US$5/per barrel to ONGC is adequate tocover production and exploration costs, and generate a reasonable profitafter tax. Each discovery should, however, be considered as a separateproject and it would therefore be appropriate for the GOI to reconsider theprice paid to ONGC for oil and natural gas so that, within the limits set byinternational prices, prices are set at a level which would permit an effi-ciently operated ONGC to earn an acceptable DCF return and to finance areasonable portion of its exploration and development. Since ONGC's marketfor crude oil and natural gas is a captive market and since ONGC does notincur any political risk in its domestic operations, a DCF rate of returnof 15% over the life of the project would be considered satisfactory.

D. Economic Justification

Market

5.09 The production of Bombay High and Bassein North will consist ofcrude oil and associated gas. After treatment, the latter will yield leangas, consisting mainly of methane and liquefied petroleum gas (LPG) consistingof butane, propane and heavier fractions. The estimated production schedulefor these products is given in Annex 24. The three products -- crude oil,associated gas and LPG -- have different markets which have been investigatedseparately. Bombay High and North Bassein crude oil will be substituted forimports, lean gas will be used as feedstock in the fertilizer industry andLPG will be used initially in the residential and commercial sector. Thecost of the facilities required to utilize these products is estimated atUS$32.3 million of which US$10 million would be required to carry out minormodifications to existing refineries, US$18 million would be required forthe conversion of the Trombay fertilizer plant and US$4.3 million for LPGstorage and distribution facilities (Annex 24).

Cost/Benefit Analysis

5.10 Several production schedules for the Bombay High Field, involvingdifferent drilling and investment programs, were investigated by De Golyerand MacNaughton in their studies. Two cases were selected on technicalgrounds and a cost/benefit analysis was carried out to compare their eco-nomic merits. Details of the analysis are given in Annex 23 and summarizedbelow.

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Summary Evaluation of Bombay High Development Program

Case I Case II

Life of the field (years) 31.0 31.0

Total oil recovered(million tons) 170.0 158.0

% of oil in place 21.0 19.5

Peak production(000 barrels per day) 225.0 280.0

Duration of plateauproduction (years) 8.0 2.0

Rate of return (%) 93.2 91.4

Net present value /1(US million) at discountrates of:

10% 4,787 4,585

20% 2,527 2,456

40% 866 845

/L Over 15 years.

ONGC current development plans are based on the first case which maximizeoil recovery and avoid the construction of peak facilities which would beused for a short period of time.

5.11 Annex 23 provides the assumptions used in the economic evaluationof the development program. On the basis of present international pricesfor crude oil (US$13/barrel) and-of the prices at which ONGC will sellnatural gas and LPG (US$55,000 m and US$90/T) the program would yield aneconomic return of 165% if sunk costs are excluded. If sunk costs are in-cluded the economic return would be 66%. Since sunk costs are essentiallyexploration and early development drilling expenditures, the latter pro-vides a better appreciation of the economic feasibility of the entire pro-gram. The economic return is not very sensitive to variations in the pro-gram costs; an increase in the program cost of 20% would bring the economic

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return to 56%. It is more sensitive to delays in production; a delay of oneyear in the production schedule would bring the return to about 50%, which,however, would still be satisfactory. No attempt has been made to calculatean incremental return for the project since the facilities included in PhaseIII cannot be dissociated from those already constructed under Phases I andII and those planned for Phases IV and V.

VI. THE OIL AND NATURAL GAS COMMISSION

A. General

6.01 The Oil and Natural Gas Commission is a Government owned statutorybody created in 1959 by an Act of Parliament to "plan, promote and imple-ment the development of petroleum resources and the production and sale ofpetroleum products produced by it." ONGC's statutes provide that it is acorporate body with power to acquire, hold and dispose of property and tocontract. ONGC has authority to borrow. The Commission consists of aChairman, and not less than two and no more than eight Members appointed bythe Government for a period of five years.

6.02 At present, the Commission consists of the Chairman, four full-timeMembers (Finance, Materials, Production and Exploration) and of two part-timeMembers representing the Ministry of Finance and the Ministry of Petroleum.All decisions of the Commission must be approved by the majority of the mem-bers. ONGC owns Hydrocarbons India Ltd., a subsidiary which is in chargeof the Commission's ventures abroad (Iran, Iraq and Tanzania).

B. Organization and Management

6.03 The Commission acts very much as a Board of Directors and isresponsible for setting ONGC's policies. Its development plan has to beapproved by the Planning Commission and its annual budget for current andcapital expenditures has to be approved by the Ministry of Petroleum and theMinistry of Finance before it is sanctioned by Parliament. Over time, theCommission, which was originally part of the Geological Survey of India,has evolved into a full fledged oil company which is still governed by thefinancial practices of an advisory commission. However, since the discov-ery of Bombay High, the GOI and the Commission have taken actions to ensurethat these practices would not be an obstacle to efficient project implemen-tation. Recent decisions regarding the approval of ONGC's expendituresand the financing of the Bombay High Offshore Development Program reflecttheir intention to introduce more adequate practices into ONGC's financialmanagement (paras 6.07 and 7.07).

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6.04 The administrative and financial functions (planning, procurementand stores, accounting, personnel, computer activities, etc.) are centralizedin the corporate headquarters at Dehra Dun, along with the main research anddevelopment and training facilities. Operational staff is divided among threeRegional Offices (Central, Western and Eastern Regions) and the Bombay HighDevelopment Project (BHDP), whose headquarters are in Bombay. Prior to 1974most of the operational decisions were taken centrally from Dehra Dun and theRegional Managers had little, if any, authority. Over the past three yearsthe decision-making process has been decentralized to the regions, which nowhave operational responsibility and the authority to commit funds within theirapproved budget. As of January 1977 ONGC's total staff was 23,000 of which1,500 were engineers and technicians. Annex 15 shows ONGC's current organiza-tion. ONGC's onshore staff is large compared to its current production. Man-agement is conscious of this fact and is implementing a policy whereby onlykey personnel are replaced.

6.05 BHDP was created in FY74 to deal with exploration and developmentin the Bombay High area. Over the past three years, its staff grew from 20 to600, and consists mostly of engineers and technicians. Because of the size ofthe Bombay High Development Program, its economic importance to India and theneed for rapid decisions, ONGC's senior management and, more particularly, theChairman, the Member (Finance) and the Member (Offshore) have been directlyinvolved in BHDP management. At present, most of the decisions concerning theProgram are referred directly to the Chairman. While this procedure has hadthe advantage of speeding up decisions in the early stages of the program, itis not adequate for the purpose of the project, which will require that alarge number of decisions be taken at the field level. ONGC's senior manage-ment is conscious of this problem and has decided to appoint a managing direc-tor for the offshore development program. This manager will be assisted bytwo directors (finance and material) and would be responsible for the imple-mentation of the program, while ONGC's headquarters would be responsiblefor long term financial planning and overall offshore development policies.In addition ONGC has already taken steps to improve its planning, budgetingand reporting procedures (paras. 6.06 to 6.08) and to train additional staff(para. 4.25).

Planning and Budgeting

6.06 ONGC's current five-year plan covers the period FY75-FY79, andcoincides with India's Five-Year Plan. The original targets of the Com-mission's plan have been revised several times to take into account thedevelopment of Bombay High and North Bassein. These modifications have beendone piecemeal and do not fully integrate the financial, technical and eco-nomic implications of the Program. The dynamic nature of the oil industry, inwhich a new discovery may justify a complete reassessment of priorities, callsfor a flexible planning framework in which the relative merits of potentialprojects can be continuously evaluated. The Ccmmission is conscious of thisand has created a Perspective Planning Section in Dehra Dun to review itscurrent five-year plan and more generally be responsible for long-term plan-ning. The main functions of this section are to analyze the data produced

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by ONGC's technical and financial departments and to continuously updateONGC's five-year plan in the light of new developments. It is the Commis-sion's intention to periodically review the staffing of this section andto introduce more sophisticated project evaluation techniques.

6.07 In October of each year, the Commission submits separate budgetsfor its onshore and offshore operations for approval by the Government. Eachbudget includes ONGC's projected capital and current expenditures for the fol-lowing fiscal year and revised estimates for the current year. If ONGC's re-sources are not sufficient to cover its future financial requirements, theannual budget also includes a request for support from the Central Budgetwhich has to be approved by Parliament. Central Budget resources are nor-mally allocated either as GOI contribution to equity (exploration expendi-tures) or as loans (development expenditures). Within the approved budgetthe Commission has to obtain Government approval for the implementation ofany scheme which involves a capital expenditure in excess of Rs. 50 million(US$5.6 million). To expedite procurement decisions, the GOI has created aCommittee consisting of two representatives of the Ministry of Petroleum,a representative of the Ministry of Finance and of three Members of the Com-mission (Finance, Materials and Offshore) for the approval of expendituresunder Phase III of the development program. Since Phase III has beenapproved by the Government, this Committee can decide on the expendituresanction on the basis of bid evaluation without requiring any further proj-ect justification.

Performance Monitoring

6.08 The Commission's management information system is weak, due partlyto the dispersion of onshore activities and to communication problems withheadquarters and partly to the lack of adequate reporting procedures. Duringnegotiations, ONGC agreed to establish an adequate management informationsystem prior to December 31, 1977, with the assistance of the managementconsultants referred to in para. 4.19.

C. Operations

6.09 The Commission is primarily involved in exploration, develop-ment, transportation and treatment of hydrocarbons. It is not currentlyinvolved in down-stream activities (refining, processing, utilization anddistribution). As a result of the project the Commission's operations willbe widened offshore but are not expected to undergo any substantial changein scope.

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D. Insurance

6.10 ONGC has adequate insurance coverage with several insurance com-panies in India which are re-insured in the International Market (Annex 17).Insurance of offshore equipment follows the international practice, wherebydesigns are certified by independent agencies. ONGC's insurance coverage issatisfactory.

E. Finances

6.11 ONGC's accounting system provides for a segregation of projectactivities. The Commission's financial organization is adequate and account-ing practices are effective. However current procedures and formats are stillmanually compiled and could be improved by better use of ONGC's existingcomputing facilities. This will be reviewed in the formulation of the Manage-ment Information System (para. 6.08). ONGC's main source of revenue is itssales of crude oil and natural gas to domestic refineries and industries at aprice fixed by the Government. The Commission pays royalties to the State inwhich it operates and pays income tax to the Government at a rate of 57.75%.According to the statutes, ONGC should pay dividends to the Government, butis exempted from doing so when it declares a loss or borrows from the OIDBand/or the GOI. So far ONGC has not declared any dividend payment. Over thepast three years the Commission has made an operational surplus but has hadto borrow from OIDB and the GOI to finance an increasing part of its offshoredevelopment program (para. 7.04). Current financial projections show thatthis situation will continue in the future.

F. Audit

6.12 Each project unit has a Finance and Accounts Section reporting tothe Project Manager and to the Member (Finance) at ONGC's headquarters.Internal audit is satisfactory. ONGC's accounts are audited by the Comptrollerand Auditor General which is acceptable to the Bank. While ONGC's accountsare generally available, at the latest, four months after the close of theaccounting exercise, ONGCGs rules and regulations provide that auditedaccounts cannot be made public before they have been approved by Parliament.ONGC has agreed that the Commission's audited accounts will be submitted tothe Bank not later than twelve months after the end of the fiscal year.Provisional accounts will be available for review by Bank supervision missionsnot later than four months after the end of the fiscal year.

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G. Prices

6.13 Crude oil and natural gas prices are controlled by the GOI. Crudeoil and natural gas prices are revised every three years upon the recommenda-tions of the Oil Pricing Committee. Until i373/74 prices to producers ofdomestic crude oil were based on import parity. After the increase inworld prices, the GOI decided to abandon this principle and to set crude oilprices at a much lower level than international prices. The current price fordomestic crude oil produced onshore is US$3.58 per barrel (i.e. 27.5% of theinternational price). On the basis of this price, ONGC's operating surpluswas Rs. 520 million in FY75 and Rs. 240 million in FY76.

6.14 The prices of offshore crude oil and natural gas have been set at

US$5/barrel and US$551000 m , respectively. These prices have been deter-mined on the basis of ONGC's anticipated cash flow for the development ofBombay High and are considered adequate to ensure the financial viabilityof the project (para. 5.08).

VII. FINANCIAL ASPECTS

A. Introduction

7.01 Prior to the development of Bombay High, ONGC's operations werelimited to the production of onshore fields in Assam and Gujarat. The pros-pects arising out of India's first offshore discovery, and possible subse-

quent ones, open up a new era for ONGC. Crude oil production will almosttriple in the next five years and operations will be on a much larger scale,particularly offshore, thus requiring much larger capital expenditures result-ing in increased cash flows. It is therefore, in the light of ONGC's futuredevelopment, rather than its past performance, that one should analyze itsfinancial situation. ONGC, which was originally set up as an advisory body,has begun an evolutionary process which should turn it into a large nationaloil company. The Government, while retaining all the necessary controls overONGC's investment programs and development policies (para. 6.03), has in prac-tice created a framework in which ONGC can operate in a financially responsi-ble and reasonably autonomous way. The Government has set prices of crudeoil and natural gas to ONGC at a level which enables the Commission to meetits operational requirements, service its debt and self-finance a reasonableshare of its development. In addition, the Government has provided fundsto meet ONGC's requirements which could not be met from internal cash gene-ration; in this respect, exploration expenditures have been financed by equityand development expenditures from loans. These policies are sound and theGOI has indicated that they will be continued in the future. ONGC managementwill be more involved in the making of the financial policy of the enterprise,and its financial performance, as reflected in its accounts, can be comparedwith that of other oil companies.

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B. Present Financial Position

7.02 Income Statements, Balance Sheets, and Sources and Applicationsof Funds Statements for ONGC's overall operations (onshore and offshore)for the period FY74 through FY82 are given in Annexes 19 to 21. A sum-mary of ONGC's estimated financial position as of March 31, 1977 is givenbelow:

Rs US$ _

---- millions----

Net Fixed Assets 3,208 356 62

Work in Progress 948 106 18

Investments 471 52 9

Current Assets 1,322

Less: Current Liabilities 780 542 60 11

Total Net Assets 5,169 574 100

Represented by

Equity 3,432 381 66

Long-term debt 1,737 193 34

7.03 As of March 31, 1977, ONGC had a satisfactory financial position.Investments of US$52 million represent ONGC's contribution to HydrocarbonIndia Ltd., its subsidiary (para 6.02). ONGC's debt/equity ratio of 34/66was satisfactory and left a margin for further borrowing. ONGC's long-termdebt relates to loans from GOI and the Oil Industry Development Board; thelatter derives its funds from an excise tax of Rs 60 (US$7) per metric ton ofcrude oil. Loans from 0IDB to ONGC have generally been made at 4.5% per yearfor 15 years with a two year grace period; GOI loans are currently made at10-1/4% per year for 10 years including 4 years of grace.

7.04 Operating results for recent years relate mainly to onshore oper-ations since the development of Bombay High has only been in its initialdrilling stage and production from the project has been minimal. ONGC hasderived all its revenues from the production and sale of crude oil and naturalgas. From FY74 to FY77 crude oil production increased from 4 Mmt to 5.7 Mmtat a rate of 12.5% p.a. This and the 1974 increase in the price of on-shorecrude oil from US$1.48/barrel to US$3.58/barrel have enabled ONGC to increaseits revenues from Rs 816 million (US$90.6 million) in FY74 to an estimated

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Rs 1,450 million (US$161 million) in FY77. However, owing to several changesin depreciation and depletion accounting policy, ONGC's net income has beenerratic, with rates of return on invested capital varying between 2% and 28%(para 7.05). During the four year period ONGC's cash generation has beensatisfactory; ONGC was able to finance about 49% of its capital investmentrequirements, including those of Bombay High, after meeting debt service andadditional working capital; 29% has been financed by loans (GOI and OIDB)and 22% from GOI equity contributions.

7.05 Until recently, ONGC's depreciation policy provided for all devel-opment drilling expenditures to be charged against income in the year theyoccur. The purpose was to increase operating expenses and thereby reduceONGC's tax liability and increase internal cash generation. However, thispractice introduced wide variations in ONGC's operating income and rate ofreturn which make historical analysis and inter-industry comparisons diffi-cult. This practice has now been discontinued and while ONGC will stilluse high depreciation rates for tax purposes, they have introduced deprecia-tion rates related to the economic-life of the assets for the purpose offinancial reporting. These arrangements are satisfactory. ONGC have indi-cated that they intend to introduce replacement accounting procedures on atrial basis when the offshore operation is firmly established.

C. Financing Plan

7.06 ONGC's overall capital investment requirements for the periodFY78 through FY82, along with the sources from which they would be met, aresummarized below; detailed Sources and Applications of Funds Statements aregiven in Annex 21.

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Rs US$ %------millions----

Requirements

Exploration and Development Program

Onshore - Exploration 1,814 201Development 3,632 5,446 403 604 35

Offshore - Exploration 1,918 213Development 7,902 9,820 878 1,091 64

Other 60 7 1

Total Requirements 15,326 1,702 100

Sources

Internal Cash Generation 10,937 1,215

Less: Debt Service 3,173 352Working Capital 270 7,494 30 833 49

Other Sources

Borrowings 4,363 485 28Equity 3,469 384 23

15,326 1,702 100

7.07 Over the period FY78 through FY82 ONGC's capital investment isestimated at US$1.7 billion of which US$1.0 billion would be foreign exchange.The financing plan is based on the Government decisions made in May 1977 re-garding the implementation of Phase III. It assumes that the GOI will financea share of the exploration program from equity, as it has done in the past.After taking into account ONGC's internal cash generation, the remaining gapof Rs 7,832 million (US$869 million) will be met by equity and borrowingsin about equal ratios. In addition to the proceeds of the Bank loan whichwill be relent to ONGC, it is expected that the GOI will mobilize aboutUS$50 million from bilateral aid (Japan, France, U.K., Germany) and willraise a loan of about US$50 million from commercial banks.

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D. Future Finances

7.08 Forecast Income Statements and Balance Sheets for FY78 throughFY82 are given in Annexes 19 and 20 with explanatory notes in Annex 18. Onthe basis of present prices (paras. 6.13 and 6.14), net income after taxes isexpected to grow at a satisfactory rate; annual rates of return on averageinvested capital (after income tax) are expected to average about 12% -

after completion of the project - and ONGC would be able to provide about57% of its required capital investment from internal cash generation. Thedebt/equity ratio would leave an adequate margin for further borrowing; annualdebt service coverage would be satisfactory. Salient features from the fore-cast financial statements are as follows:

Years ending March 31 FY78 FY79 FY80 FY81 FY82

Crude oil production (Mmt) 7.3 10.2 13.3 16.5 18.5Revenues - Rs millions 1,941 2,991 3,979 5,351 6,082Operating Income after Taxes 168 564 1,030 1,986 1,766Operating ratio - % 91 81 74 63 71Rate of return on average investedcapital - % /1 2.5 5.8 8.4 14.1 11.7

Rate of return on average netfixed assets - % 4.7 9.3 11.4 18.8 15.5

Debt/Equity ratio 42/58 42/58 41/59 34/66 29/71Debt service coverage (times) 2.7 3.4 3.8 4.5 4.0

/1 Defined as the ratio of net income before interest and after taxes (ex-cluding subsidiary) to the average, long-term debt and equity, includ-ing retained earnings but excluding work in progress and investment insubsidiary.

These forecasts are based on ONGC's production estimates. They do not takeinto account any further discovery onshore and offshore or any increase inthe price of crude oil to reflect inflation and/or changes in internationalprices.

7.09 These projections show that ONGC's performance will be satisfac-tory in the future, and that the policies followed by the GOI towards thefinancing of the project are sound and will enable ONGC to remain finan-cially viable. In this context the producer price set by the GOI for crudeoil and natural gas will be the main parameter affecting ONGC's profitabilityand cash flow objectives, for the project and subsequent major developments.

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The GOI has agreed that it will from time to time carry out a review of theprices of crude oil and natural gas to ONGC, which will determine the level ofprice required to enable ONGC to meet its operating expenses and earn a returnon its invested capital sufficient to cover its debt service requirements,maintain adequate working capital and finance a substantial portion of itsproposed capital expansion. ONGC has agreed that it will prepare and furnisheach year to the GOI an economic and financial evaluation of the project andof any subsequent major development, which will indicate the level of pricewhich would be required for ONGC to earn a DCF return of at least 15%, for theproject and any subsequent major development. In the light of ONGC's past andprojected performance, it is understood that ONGC's financial viability shouldbe reflected in a capability to finance about 30 to 50% of the cost of newdevelopment projects from internally generated funds, in rates of return oninvested capital of 10% to 14% and in an annual debt service coverage of 2 to2.5 times. It is expected that prices which would ensure a DCF return of 15%after taxes to ONGC, for the project and subsequent developments, would bringabout at least such results.

VIII. RECOMMENDATIONS

8.01 During negotiations the following issues were raised with ONGC andsatisfactory assurances were obtained:

(a) ONGC would submit to the Bank an updated development planof the Bombay High and North Bassein fields, by the endof each calendar year starting in 1977 (para 4.03);

(b) ONGC will employ qualified and experienced consultantsfor the design and supervision of construction of theproject (para 4.13), and ONGC will employ qualifiedmanagement consultants (para 4.19);

(c) ONGC would submit to the Bank copies of quarterly progressreports in a format acceptable to the Bank (para 4.21);

(d) ONGC would establish a satisfactory management informationsystem for the Bombay High Development Project by December 31,1977 (para 6.08);

(e) ONGC would submit audited accounts to the Bank not later thantwelve months after the end of each fiscal year (para 6.12);

(f) ONGC would prepare and furnish each year to the GOI an eco-nomic and financial evaluation of the project and of any sub-sequent development, which will indicate the level of pricewhich would be required for ONGC to earn a DCF return ofat least 15%, for the project and any subsequent majordevelopment (para 7.09).

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8.02 Assurances were obtained from GOI during negotiations that:

(a) GOI would cover ONGC's financing requirements includingworking capital (para 4.18); and

(b) GOI would carry out from time to time a review of theprices of crude oil and natural gas to ONGC, which willdetermine on the level of price required for ONGC tocontinue to be financially viable (para 7.09).

8.03 With the above assurances and agreements, the Project would besuitable for a loan of US$150 million to GOI for a term of 20 years includ-ing three years of grace.

ANNEX 1

INDIA

BOMBAY HIGH OFFSHORE DEVELOPMENT PROJECT

BANK GROUP PROJECTS IN THE ENhGY SECTOR

AmountDate of Loan/Credit (net of cancellation)Agreement Number Description (US$ million)

April 18, 1950 Ln. 23-IN Bokaro-Konar Power (DVC I) 16.7

Jan. 23, 1973 Ln. 72-IN Damodar Power (DVC II) 10.5

Nov. 19, 1954 Ln. 106-IN Trombay Power 13.8

May 28, 1957 Ln. 164-IN Trombay Extension 9.7

July 22, 1958 Ln. 203-IN Third DVC Power 22.0

April 7, 1959 Ln. 223-IN Koyna Power 18.7

Aug. 8, 1961 Ln. 292-IN Private Sector Coal Production 28.8

Dec. 22, 1961 Ln. 307-IN Indian Iron and Steel Co. 18.6(coal mining)

Feb. 13, 1962 Cr. 19-IN Fourth DVC Power 16.5

Aug. 7, 1962 Cr. 24-IN Second Koyna Power 17.5

May 23, 1963 Cr. 37-IN Kothagudem Power 20.0

June 8, 1965 Ln. 416-IN Power Transmission 50.0

June 8, 1965 Ln. 417-IN Second Kothagudem Power 1I.0

June 28, 1966 Cr. 89-IN Beas Equipment 22.7

April 28, 1971 Cr. 242-IN Second Power Transmission 75.0

March 27, 1973 Cr. 377-IN Third Power Transmission 85.o

July 8, 1975 Cr. 572-IN Rural Electrification 57.0

Jan. 13, 1976 Cr. 604-IN Fourth Power Transmission 150.0

April 1, 1977 Cr. 685-IN Singrauli Thermal Power 150.0

796.5

June 1977

ANNEX 2

INDIA

BOMBAY HIGH OFFSHORE DEVELOPMENT PROJECT

Glossary of Technical Terms

1. Development drilling. Extension of a drilling program once a strikehas been established and proved to be capable of economic production.

2. Deviated well. A well drilled at an oblique angle. A deviated wellstarts vertically and is deflected gradually to enter the producinghorizon at a calculated distance away from the main vertical well.

3. Directional drilling. A technique adopted to exploit as much of anoil and/or gas field from a single platform by drilling deviatedwells.

4. Associated gas. Gas combined with oil. It provides the drive mechan-

ism needed to force oil to the surface through a well. On reachingthe surface, water is removed and the gas is split into wet and drycomponents to be transported separately.

5. Dry gas (lean gas). Gas containing a high proportion of methane andethane.

6. Dry hole. A well which is not expected to produce hydrocarbons incommercial quantities.

7. Exploration. All operations preceeding commercial exploitation.(Surveys, exploratory and delineation drilling).

8. Delineation well. An exploration well drilled to appraise the valueof an oil and/or gas discovery.

9. Gas reinjection. A secondary recovery technique of recyling surplusgas to maintain reservoir pressure.

10. Gas separation. Process of removing dissolved gas from oil.

11. Gathering lines. The flowlines in a subsea production system whichgather oil from individual wells.

12. Lay Barge. A barge developed to lay subsea pipelines.

13. Liquefied petroleum gas (LPG). Gas consisting mainly of Butaneand Propane.

INDIA

BOMBAY HIGH OFFSHORE DEVELOPMENT PROJECT

PAST COMERCIAL ENERGY PRODUCTION AND CONSUMPTION- ~~~~(000 ~Toe)7

Average rate ofJ. PRODUCTION 1965 1270 1271 1972 1973 1974 1975 growth p.a. (%)

Coal and lignite a 35,750 39,400 38,440 40,350 41,230 44,700 50,410 3,49Crude oil 4nd natural gas

liquids 3,020 6,810 7,185 7,370 7,200 7,490 8,250 10.57Natural gasJ2 660 1,280 1,355 1,405 1,505 1,725 2,080 12.16Hydro and nuclear power ai 5,000 10,000 11 200 10 900 11 600 11 200 13.300 10.27

Total 4443 77,490 5,8 6025 61,35 65 74,040 5.23

+ 8,ports 1 8,890 12,495 14,61o 15,695 17,120 18,445 19,995 8.44I Exports (950) (970) (460) (300) (525) (440) (240) (12.88)

- Bunker (565) (600) (635) (525) (575) (610) (575) -

II. TOTAL APPARENT CONSUMPTION 51,805 68,415 71,695 74,895 77,555 82,[10 93,220 6.05of which %

Solid fuels 69.0 57.6 53.6 53.9 53.2 54.2 54.1Liquid fuels 20.0 25.9 28.9 29.6 29.9 30.1 29.4Gas 1.3 1.9 1.9 1.9 1.9 2.1 2.2Electricity 9.7 14.6 15.6 14.6 15.0 13.6 14.3Total 100.0 100.0 100.0 100.0 100.0 100.0 100.0

III. IMPORT DEPENDEN(C Lk(%) 14.3 16.0 18.9 20.0 20.7 21.1 20.5 3.74

June 1977

Sources

G World Energy SuppL esMinistry of Petrolet Indian Petroleum and Petrochemical Statistics

J3 Computed on the basi.f of 1,000 kwh equivalent to 0.4 ToeRatio of net import t i.otal apparent consumption

ANNEX 4

BOMBAY HIGH OFFSHORE DEVELOPNENT PROJECT

ENERGY DEMAND PROJECTIONS

(000 Toe)

19B3/84 1990/91 2000/01Case a Case b Case a Case b Case a Case b

Coa l 105,800 115,800 178,400 193,200 315,700 342,100Oil /2 50,750 41,350 82,350 60,400 154,150 103,100Natural Gas /3 n.a n.a n.a n.a n.a n.aHydel 4 16,650 16,650 25,800 25,800 42,900 42,900Nuclear /5 3,800 3&800 15,900 15 900 40 000 4GW00

Total 177,000 177,600 302,450 295,300 5572750 528,100

Average 177,300 299,375 540,425Distribution %

Solid Fuels 59.7 65.2 59.0 65.4 57.1 64.8Liquid Fuels 28.7 23.2 27.1 20.5 27.9 19.5z ectricity 11.5 11.6 13.8 14.1 15.0 15.7

Total 100.0 100.0 100.0 100.0 100.0 100.0

Case a: assumes that current oil prices will continue to increase, and thatlimited fuel substitution wll take place.

Case b: assumes a decrease of oil prices in relative terms and prcmotion ofsubstitution of coal for oil.

Source: Report of the Fuel Policy Committee 1974.Second India Studies - Energy (K. Parikh, 1976).Mission's estimate.

/L Include minor quantities for export.

/2 include non-energy consumption and refinery losses.

/3 not available: most of the natural gas will be used as fertilizerfeedstock.

/ Based on specific consumption of 0.32-0.3-0.26 Toe per kwh in 1983, 1990and 2000 respectively, and an average load factor of 30%.

/5 Same assumption as above for specific consumptions, load factor of 70%.

June 1977

ANNEX 5Page 1 of 7

INDIA

BOMBAY HIGH OFFSHORE DEVELOPMENT PROJECT

Development of Energy Resources of India 1/

1. The energy resources of a country are not immutably or preciselygiven. They can be assessed only at a particular time in relation to whatis known or believed about how they can be developed and put to use and aboutthe expected cost and benefits that will result from their exploitation.

2. In the present state of knowledge, India's energy resources can bedivided into three main headings: commercial energy which would includecoal, hydrocarbons (oil and natural gas), hydro-power and nuclear fuels; non-commercial energy which consists mainly of forest resources and animal andvegetable wastes; and prospective energy resources including solar energy,geothermal and tidal energy and wind power for which no commercial technologyis yet available in India or elsewhere..

A. Commercial Energy

(i) Coal

3. Recent estimates by the Geological Survey of India indicate thattotal reserves (proved and others) could be as high as 83,000 million metrictons (Mmt) equivalent to about 23,000 million tons of oil equivalent (MToe)of which about 25% would be coking coal of various quality and 75% non-cokingand lignite (Table 1). Various studies have estimated that the reserves ofcoking and non-coking coal could satisfy the projected coal demand of thesteel industry for about 40-50 years and of other sectors for about 50-75years under current assumptions of economic growth.

4. Coal basins in India are geographically concentrated within thearea located in the eastern and north-eastern part of the country. The fourmajor fields (Ramiganj, Tharia, North Karanpura and Singrauli) account formore than 60% of the total production of coking and non-coking coal. Thereare no significant coal fields in the north-western, western and southernregion. Therefore long haulages are necessary if coal is to be suppliedto these regions. Over the past 20 years a deliberate attempt has beenmade, with some success, to develop coal production in other areas to reducetransport costs. Most of the coal mined in India has a high ash content.

1/ In this annex we have relied on information supplied by P.D. Hendersonin his book: India: the Energy Sector and on study of the energy sec-tor by Kirit Parikh of the Ford Foundation in India.

ANNEX 5Page 2 of 7

As better quality coal was mined and had to be replaced by lower grade, theaverage ash content of Indian coal has increased from about 14% to over 20%.

5. After eight years of semi-stagnation up to 1973/74, coal productionincreased by 13.7% in 1974/75 from 78.2 to 88.9 Mmt. This momentum was main-tained in 1975/76, the first six months showing an increase of 11.5% over thesame period in the previous year and it now appears that the target of 135 Mmtproduction for the current five-year plan could be achieved. Most of the re-cent increase in production was achieved by improving the efficiency of ex-isting mines and of rail transport. The Government has now finalized a pro-spective plan which aims at raising coal output to 184 Mmt by 1985/86 - 41%of the increase being required for power generation, 18% for steel making andanother 41% for other sectors.

6. The coal sector is largely nationalized, with only two captivemines of steel producers remaining outside the public sector. The publicsector is controlled by Coal India Limited a public company created in 1975by consolidating the Coal Mine Authority Ltd., Bharat Coking Coal Ltd.and the Singareni Collieries Ltd.

7. Various studies by public and private agencies show that coal willcontinue to play a very significant role in India's future energy supply. Itis currently estimated that coal production should reach 184 Mmt. by 1985 andabout 340-370 Mmt by 1990 compared to a target of 135 million tons at the endof the Fifth Plan. According to the K. Parikh study this would require thefollowing investments (the figures indicated below are the average betweenthe minimum and maximum requirements).

1975-1984 1980-1990Rs US$ Rs US$

million million million million

Coal Mines

New mines 13,140 1,460 18,100 2,010Replacement 860 95 1,080 120

Sub-total 14,000 1,555 19,180 2,130

Exploration 750 85 1,000 110

Treatment 970 105 1,300 145

Total 15,720 1,745 21,480 2,385

Transport 13,940 1,550 12,170 1,350

Total 29,660 3,295 33,650 3.735

Source: K. Parikh. Second India Studies - Energy. 1976

ANNEX 5

The large investment in several sectors (mining, industry- and transport)will require considerable planning and coordination. The steps taken after1973-74 to improve the availability of spares, and to impro.:: the produc-tivity of existing mines and of rail transport appear to be in the rightdirection. However some difficulties remains in the financing of coalexpansion and in coal pricing.

(ii) Hydroelectric Power

8. India's hydroelectric power potential has been conservativelyestimated at 41,000 MW (based on a 60% load factor) by the Central Water andPower Commission of which about 20% has been or is currently being developed.The north-eastern and northern regions, which include the Brahmaputra andGanga rivers, account for 30% and 26% of the total potential, respectivelythe balance being located in the eastern (6.5%), western (17.5%) and south-ern regions (19.6%). To some extent the availability of hydropower redressthe differences which arise from the very uneven distribution of coal re-serves.

9. Although India's hydroelectric power generating capabilities aresubstantial, the date by which they might be put to use is remote in mostcases as the hydropower sites are located far from the main demand centers.For example, it is unlikely that power consumption in the north-east willrequire more than the development of a small part of the identified Doten-tial. A possibility for a larger role of hydropower could be a morecoordinated approach towards multipurpose projects which would combineirrigation, water supply and power generation.

10. In the long run the share of hydroelectric power is expected todecrease from its current 41% of total power generation to about 35% in1990/91, and thereafter. Total investments in hydropower plant are pro-jected at Rs 52.0 billion (US$5.8 billion) between 1975 and 1990.

(iii) Nuclear Fuels

11. Resources of nuclear fuels in India consist of uranium andthorium. The first of these is already in use for the generation of electricpower in India, and it is planned that future facilities will use domestic-ally produced uranium as a fuel. The main concentration of uranium is inBihar and is exploited in two mines; some other deposits, of a lower con-centration, may be worth developing in Udaipur and Rajasthan. The Depart-ment of Atomic Energy is responsible for uranium exploration in collabora-tion with other Government agencies.

12. On the basis of current reserves, and with the technology which iscurrently in use, uranium supplies would meet the demand for a limited time,depending on the rate at which new nuclear facilities are built. Thisperiod could be extended by improvement in technology and the use of fastbreeder reactors which are not yet commercially exploitable.

ANNEX 5Page 4 of 7

13. The future development of nuclear fuels will to a large extentdepend on the development of other fuels, mainly coal. It is estimatedthat nuclear generation will increase from the current level of 600 MW toabout 8,500 MW by 1990. In view of the cost of nuclear power and of thetime involved this objective appears optimistic.

(iv) Hydrocarbons

14. Current hydrocarbon recoverable reserves onshore are estimated atabout 203 million tons of oil equivalent (Mmtoe) of which petroleum reservesaccount for 65% and gas reserves for 35%. Most of the onshore reserves arelocated in two states, Assam in the northeast where oil was first discovered,and Gujarat in the northwest which was developed in the 1960's by the Oiland Natural Gas Commission (ONGC). The current ratio of reserves to produc-tion is currently of 19 and 41 years for petroleum and natural gas, respect-ively.

15. The total sedimentary area in India is about 1.7 million sq. km ofwhich 1.4 million sq. km are onshore and .3 million sq. km. offshore withinthe 200 m water depth (Continental Shelf). A total of 27 sedimentary basinshave been identified, with prospects ranking from good to poor, of these ninehave been explored and three (Assam, Gujarat and Bombay High) have yield oil,exploratory drilling in the other six basins has not resulted in any notablediscovery. Work in the remaining 18 basins is either in progress or will becommenced in the near future. The most promising areas are:

- the Cambay (Gujarat) and Assam-Arakan areas which areknown to contain commercial deposits of oil and naturalgas;

- the Cauvery, West Bengal, Jaisalmer Teipura, Cachar andAndaman Nicobar areas which have good prospects but sofar have no known commercial deposits.

16. Until 1972/73 most of the survey and exploration effort of inter-national and domestic oil companies was concentrated onshore with the ex-ception of a geological-geophysical survey carried out by Soviet experts inthe mid-1960's. Although three companies are producing petroleum and gasin India - the Assam Oil Company (AOC), Oil India Ltd. (OIL) in which theGOI has a 50% participation and ONGC which is a fully government-ownedagency - only OIL and mostly ONGC were involved in onshore exploration.At the end of 1975 ONGC had drilled about 1,235 exploration and develop-ment well onshore of which 250 and 950 were located in Assam and Gujaratrespectively. These efforts have resulted in the discovery and developmentof about 25 oil and gas fields. The survey of the offshore potential car-ried out by Soviet experts identified 12 potential structures mainly in theArabian Sea. The exploration of those located in the Bombay area has re-sulted in the discovery of Bombay High and of North and South Bassein.

ANNEX 5Page 5 of 7

17. While ONGC's and OIL's exploration programs onshore have beenreasonably successful, it is the opinion of many experts that their pastand current exploration programs are not commensurate with the size and

prospects of the prospective areas particularly offshore. GOI and ONGCofficials share this opinion and have decided to step up exploration programs

in the most promising areas onshore, to build up ONGC's offshore explorationcapacity and to cooperate with international oil companies in explorationfor and development of hydrocarbon reserves offshore. This program whichwas initiated in 1972/73 has already brought about significant results:

(a) onshore reserves which had been declining since 1961,have increasSd by about 17 million tons of oil and about27 billion m of natural gas;

(b) offshore ONGC has discovered the Bombay High field and the

adjacent North and South Bassein fields which are expectedto have initial rscoverable reserves of over 250 /1 Mmt of

oil and 30,000 Mm of natural gas (Annex 3). In addition,India has entered into production-sharing/participationagreements with three oil companies which are currentlyexploring in the Gulf of Kutch and off Bengal (Reading andBates Asamera and Natomas).

18. In the future ONGC will have a leading role in onshore exploration,although it is expected that OIL will step up exploratory drilling. ONGC'scurrent plans onshore call for:

(a) a review of all geological and geophysical data collectedso far, with more powerful analytical tools. For thispurpose the computer facilities of ONGC headquarters inDhera Dua have been modernized and geologists and geo-physists are being trained in modern interpretation

techniques;

(b) the concentration of effort on a limited number ofpotential areas where ONGC personnel and foreign con-tractors will apply geological and geophysical techniquesand will drill in deeper structures where the prospectsappear to be more promising; and

(c) the exploration of areas which have not been exploredpreviously because of the technical and geographicalproblems involved (infrastructure, access, etc.).

Although ONGC plans appear reasonable, they have not yet been formulated in

great detail and there appears to be considerable room for improvement ofONGC's approach to onshore explorations, particularly in the deployment of

crews and in the selection of priorities among projects.

i/ These reserves could be increased by 85 YMmt of oil if probablereserves under evaluation are confirmed.

ANNEX 5Page 6 of 7

19. As indicated in para. 17 the responsibility for exploration off-shore is shared among ONGC and foreign oil companies operating under pro-duction sharing contracts. Prior to 1976 ONGC had practically no experienceoffshore. In the course of three years ONGC succeeded in discovering agiant oil/gas field and two other fields of lesser importance and to bringthese fields under production while continuing exploration. To achieve theseremarkable results, ONGC has followed a pragmatic policy of "owner assisteddevelopment" 1/ whereby ONGC would hire knowledgeable contractors to carryout development work, while ONGC staff, assisted by consultants, retained thedecision-make responsibility, and acquire the expertise. This approach hasenabled ONGC to minimize the acquisition of heavy equipment (drilling rigs,barges and supply boats) to what was justified by proven fields and requiredto train their own personnel.

20. The main objective of ONGC's offshore policy is first to completeexploration in the Bombay offshore areas (some structures at the limit ofthe continental slope remain to be drilled) and to move south of Bombaywhere other projects have been identified. Although no definite program hasyet been decided upon (outside of the Bombay offshore area) it appears thatONGC's program for the next two years will include about 20 exploratory/delineation well offshore. This program appears consistent with the pros-pects that have been identified so far and with ONGC's resources.

21. Future investment in offshore exploration and development asso-ciated with the development of Bombay High and North Bassein is described inAnnex 12.

B. Non-Commercial Energy

22. Non-commercial energy consists chiefly of fuel wood and animalwastes, mainly cow-dung, used in the domestic sector.

(i) Fuel Wood

23. Total consumption of fuel wood is not known precisely, but isestimated at about 130 million tons per year, thus exceeding by more than50% the output of the coal industry. Fuel wood is used predominantly inthe domestic sector and its utilization has been a source of concern to theGOI. India has a forest area which accounts for about 23% of the total geo-graphical area, which is well below the world average. Of this about 60%is considered exploitable and about 20% potentially exportable. Effortshave been made to increase the forest area and to control the use of fuelwood. These efforts appear to have brought about some results and between1960 and 1970 the forest area increased by about 8.7% from 69 millionhectares to 75 million hectares. However, the increase in oil prices of1973/74 has had a detrimental effect on the demand for fuel wood, whichappears to have increased as the price of kerosene went up. The GOI is

1/ As opposed to the concept of "operator" whereby the owner of the fieldentrusts the full responsibility of its development to a contractor.

ANNEX 5Page 7 of 7

considering the creation of plantations of fast growing trees to meet futuredemand and the implementation of tighter controls on fuel wood utilization toprevent deforestration. However, in the absence of data, it is impossible toquantify the impact of higher kerosene prices accuratly.

(ii) Vegetable Wastes and Cow-dung

24. Together these two fuels account for about one-third of total con-sumption of non-commercial energy, according to estimates of various Agenciesin India. Cow-dung and vegetable wastes are cheap sources of energy, however,their use as fuels has been very controversial since they could possibly beused more efficiently as fertilizers. The strength of this argument dependson what it is reasonable to assume for the cost of alternative fuels and onthe effectiveness with which cow-dung could be used as fertilizers. In thisconnection India has launched an experimental program for the constructionof small biogas plants.

C. Prospective Energy Sources

25. So far little is know about geothermal energy and/or solar, wind andtidal energy potential. Although there are a large number of hot springs inIndia, the total exploitable potential of geothermal energy appears verysmall. Despite a long coast line, there are very few sites which have tidalranges which would permit commercial exploitation and the total potential isestimated at less than 1,000 NW. Wind could be a potential source of energyprovided the technology exists. Solar energy appears to be the most promisingsource of prospective energy, as the annual solar intensity averages 600calories per sq. cm. Although India has been conducting some experiments,particularly in rural areas, it does not appear that solar energy will playa substantial role in total energy supply in the near future.

ANNEX STable 1

INDIA

BOMBAY HIGH DEVELOPMENT PROJECT

Coal Reserves(Mtoe)

Proven OtherReserves Reserves Total x

1. Coking Coal:Prime coking coal 3,650 2,000 5,650 6.8Medium coking coal 3,850 5,581 9,431 11.4Low-grade coking coal 1,559 3,514 5,073 6.1

Total 9,059 11,095 20,154 24.3

2. Non-coking Coal 12,306 48,490 60,796 73.3

3. Lignite 1,795 230 2,025 2.4

Total 23,160 59,815 82,975 100.0

Source: Report of the Fuel Policy Committee (1974)

January 1977

ANNEX 5Table 2

INDIA

BOMBAY HIGH DEVELOPMENT PROJECT

Hydroelectric Potential by Region

Region Power Potential x

(MW)

Eastern 2,695 6.5

Northern 10,790 26.2

Western 7,160 17.4

Southern 8,040 19.5

North-eastern 12,465 30.4

Total 41,150 100.0

of which

Run of the River 10,300 25.0

Storage 29,850 75.0

Total 41,150 100.0

Source: Report of the Fuel Policy Committee (1974)

January 1977

ANNEX 5Table 3

INDIA

BOMBAY HIGH DEVELOPNENT PROJECT

Hydrocarbon Recoverable Reserves(Mtoe)

Crude Oil Natural Gas Total

Onshore

Gujurat 46.0 14.0 60.0Assam 84.0 59.0 143.0

Total 130.0 73.0 203.0

Offshore

Bombay High 126.0 /1 15.0 /2 141.0Bassein North 34.0 /1 4.0 /2 38.0

Total 160.0 19.0 179.0

Grand Total 290.0 92.0 382.0

/1 Assuming -gas lift only, if water injection is taken into accountwould increase to 250 Mtoe.

/2 Assuming a Gas Oil Ratio (GOR) of 100.

Source: ONGC and Indian Petroleum and Petrochemical Statistics 1975,DeGolyer and MacNaughton.

INDIA

BO1DBAY HIGH OFFSHORE DEVELOPMENT PROJECT

PAST PETROLllUM PRODUCTION AND CONSIMPTTION

(000 Tons)

1965 1970 1971 1972 1973 1974 19'5

A. CPMDE PETROCLEUMProduction

ONGC onshore 1,122 3,632 3,941 4,097 4,012 4,338 5,1280T130 ofwstaore - - - - - - -OIL 1,7L2 3,070 3,116 3,183 3,102 3,080 3,087AOC 1cg 107 98 93 84 72 68Total 3,022 z9 7 5 7,373 Tl90 7-,29 3

Imports 6,311 11,665 12,688 12,310 13,643 13,973 13,669;=orts 18-Aparen-.. change in stocks 79 15 285 11 105 680 117rotal interral consumption 9,754 18,L59 19,588 19,672 20,518 20,783 21,535

Cionsumotion irn refineries 641 1,282 1,359 ,468 1,393 1,10 1-03Total i:ternal final .32

cons,xnpt4on 9,113 17,177 18,229 18,204 19,125 19,303 20,532

3. PRODTJCTION OF ST-ROLlUM PRODUCTSCrude petroleum innut 9,754 18,459 19,588 19,672 20,518 20,783 21,835

- Losses in refineries and fuel 041 1,282 1,359 1,468 1,393 1,680 1,303Total production 9,113 17,177 18,229 18,204 19,125 19,303 20,532I mports 2,880 970 1,932 3,257 3,735 2,969 2,180

- ExDcrts 3L5 L12 152 109 155 202 16cB-unker deBveries 378 2Lh 230 175 234 136 :15

- Apparent changes in stocks (598) (96) 290 (227) (12) 87 (19)otal internal final

consumption 11,868 17,587 19,439 21,606 22,683 21,827 22,380of which:

Light distillates 1,361 2,575 2,996 3,232 3,491 3,323 3,603Middle distillates 6,186 8,870 9,757 10,517 11,004 11,200 11,545Residuals 3 191 L 651 , 976 5 549 5 932 5 705 5 806

Sub-Total 10,738 16,096 17;725 19,34d 20;,27 20'228 20,952Jon Energy Products 1,130 1,L91 1,764 2,056 2,056 1,599 ', 28

TOTLAL 8 '.7 9,89 7OL 2 827 22.,1?

Source: Indian Petroleum and ?etrochirca]l Statistics 1975

June 1977

ANNEX 7Page 1 of 7

INDIA

BOMBAY HIGH OFFSHORE DEVELOPMENT PROJECT

Development of Hydrocarbon Resources in India

Policies and Constraints

A. Introduction

1. Two different approaches can be followed by a developing countryin the exploration for and development of its hydrocarbon resources. It can

enter into an agreement with a foreign oil company whereby the latter wouldexplore for and develop hydrocarbon resources and/or it can entrust respons-ibility for development to a national agency. These two approaches are notmutually exclusive, and several countries have been using both of themsimultaneously or in sequence. The rationale for preferring one approachto the other, or for using both does not solely depend on economic and tech-nical criteria. In most developing countries the choice between foreignand national companies carries considerable social, political and philosophi-cal implications. In India policies regarding the development of hydrocarbonresources changed over time from an almost total dependence on foreign compa-nies to a strong emphasis on self-reliance. Recently, however, India hasfollowed a policy of compromise between foreign participation and nationalautonomy. The following sections are an attempt to summarize the mainpolicies followed by the Government of India (GOI) at various stages andto highlight the constraints, issues and problems which underlined thesepolicies.

B. India's Policies in the Petroleum Sector

(i) The Early Years after Independence

2. In the wake of independence, India was almost totally dependenton the import of refined petroleum products. In 1948 the Assam Oil Com-pany (AOC) a subsidiary of Burmah Oil produced about .25 MmT of crude oilwhich was refined in a small plant near Digboi whose production of .19 Mmtwas less than 7% of total petroleum consumption in India that year. Thebalance was met by imports of refined products which were controlled bythree foreign companies Burmah-Shell which accounted for over 50% of themarket, Standard Vacuum Oil Company (Stanvac) and Caltex a joint ventureof Standard Oil of California and Texaco.

3. In the early 1950's, the GOI realized that future economic growthwould necewssarily lead to an ever-increasing demand for liquid fuels, evenif domestic coal reserves were developed to the maximum possible extent. It

ANNEX 7Page 2 of 7

also realized that a continuing reliance on imports of refined productswould prove to be less reliable and more costly, in terms of foreign ex-change, than the import of crude oil which could be refined locally. Be-tween 1948 and 1951, t'-e GOI approached foreign oil companies and proposedthe establishment of domestic refineries based on imported crude. Thisdecision, however, was a departure from the principles of the IndustrialPolicy Resolution of 1948 which stated inter alia that the Government shouldbe responsible for the future development of the petroleum sector. The mainreasons for the GOI decision were:

(i) the difficulty in mobilizing foreign exchange and localcurrency resources to finance Government-owned refineries;

(ii) the lack of expertise in petroleum refining, which at thattime was very strongly dominated by international oil com-panies;

(iii) the lack of expertise in the distribution and marketing ofrefined products and the potential conflict with foreigncompanies who might have refused to market the productsof Government-owned refineries; and

(iv) the hope that after having invested in refineries, foreigncompanies would also invest in exploration for and develop-ment of petroleum resources in India.

4. Agreements were signed in late 1951, whereby Stanvac and Burmah-Shell would each build a refineries with a capacity of about 1.0 and 1.5 Mmt,respectively. A third agreement was entered into with Caltex in 1953 for theconstruction of a third refinery.

5. At about the same time, the GOI entered into a joint venture agree-ment with Stanvac, known as the Indo-Stanvac Project, for exploration in theBengal Basin. According to this agreement, the GOI was to provide 25% of thefunds required for the operation of the project; Stanvac was to provide 75%and was entitled to 75% of the production. Stanvac retained responsibilityof the overall management of the project. If oil was found, it was to bepriced at import parity. In addition, the agreement included a number of taxexemption clauses which reflected the GOI's opinion that it was in the na-tional interest to attract international companies to invest in petroleum ex-ploration and development in India. This project was, however, abandoned in1960 without producing any positive results.

6. After long negotiations, the GOI also entered into a joint ventureagreement with Burmah Oil which resulted, in 1959, in the creation of OilIndia Limited (OIL) a private company in which the GOI had initially a one-third interest. OIL's prospective area was limited to the north-east ofIndia. The GOI participation was subsequently increased to 50% in1961,when OIL's prospective area was enlarged to some areas in the North-EastFrontier Area and Assam. OIL agreed to sell all its oil to the GOI, and

ANNEX 7Page 3 of 7

agreed that crude oil would be priced so as to allow a return of 9-13% on thepaid-up share capital. In this the GOI was departing from the import parityprice concept of the Indo-Stanvac Project and was moving toward a cost-pluspricing policies.

7. While the Indo-Stanvac Project did not bring about any discovery,OIL was more successful, at least in the early years of operation; and pro-duction increased from about .25 Mmt in 1959 to 1.4 Mmt in 1964 and reacheda peak of about 3 Mmt in 1970, which it has maintained since. However, OILhas not made any significant new discovery in the recent past and its produc-tion is expected to decline sharply in the early 1980's as its fields aredepleted.

8. One of the major clauses of the agreement signed with foreign com-panies in setting up- refineries in India provided that they would have thefreedom to choose their sources of supply and that crude oil prices wouldbe determined on the basis of world market prices (posted prices) at thetime and place of shipment. Within the framework of integrated companies,this really meant that India's domestic refineries were a captive market forthe purpose of selling the companies' own crude oil. Retrospectively, theseclauses and other clauses governing equity participation, duties and taxesappear somewhat inflexible, but one has to remember that at the time the"maj ors" dominated the market and would not have agreed to anything else.Also the GOI had no alternative other than to continue importing products,at a higher-cost than crude oil.

9. As a result of this policy, domestic production of refined pro-ducts increased from less than .2 Mmt in 1952 to over 4.5 Mmt in 1957/58thus meeting about 80% of total domestic requirements. The domestic pro-duction of crude oil, however, remained stagnant throughout the 1950's atless than .5 Mmt.

10. The GOI's decision to invite foreign companies to build and operatedomestic refineries rather than continue importing refined products or tryingto procure the expertise from consultants appears to have been justified.Foreign exchange savings (compared to imports of products) have been estimatedat about US$150 million between 1955 and 1960. 1/ However, the changes whichoccurred in the late 1950's and 1960's in the world oil market led the GOI toreconsider its policy.

1/ R. Vedavalli. Private Foreign Investment and Economic Developmenta case study of Petroleum in India.

ANNEX 7Page 4 of 7

(ii) The Changes of the Late 1950's and the 1960's

11. The early 1950's had been characterized by a monopoly of the majoroil companies on oil supplies and a balance between supply and demand. Inlate 1950's and in the 1960's several factors contributed to change thissituation. Large volumes of oil were discovered by so called "independent"companies and by national companies sponsored by European governments (France,Italy) in countries which were not yet producers; surplus oil from the USSRbecame available on the market; and the U.S. introduced import quotas to pro-tect their own industry. This resulted in excess supplies and rapidly dec-lining prices. While posted prices did not change substantially, a number ofcompanies introduced a system of rebates which greatly reduced the real costof oil supplies to a number of importing countries. This, however, was notthe case in India, where crude supplies to domestic refineries were procuredby foreign companies at internal transfer prices which were based on postedprices. Until 1960 India was unaware of this situation, and it is onlyafter the USSR offered crude at discount prices to India that the GOI startedputting pressure on the companies to reduce their prices and investigatingalternative ways of taking advantage of the favorable market conditions.Concurrently the GOI was still trying to attract foreign companies to par-ticipate in oil exploration. In the late 1950's the GOI convened a panelof international experts from Eastern and Western countries which recom-mended a strong impetus from privately financed exploration and development.The GOI invited companies to make proposals by early 1960. Fourteen com-panies responded but were unable to come to terms with the GOI, the onlyagreement reached was a modification to the GOIt's participation in Oil (1961).

12. Faced with an ever-increasing oil import bill, the GOI had severalpolicy options:

(i) finding oil in India to substitute domestic productionfor imports of crude oil. As we have seen, the GOI hadbeen trying successfully to attract foreign oil companiesto explore in India. The failure to obtain foreign com-panies' cooperation led to the creation in 1956, 1/ of theOil and Natural Gas Commission (ONGC), which was given thetask of exploring for and developing oil resources in Indiaoutside the areas being prospected by Oil. At about the sametime the GOI turned to the USSR and Eastern European Countriesfor technical and financial assistance in setting up an explo-ration group and in building the first state-owned refineries.by 1965 ONGC had discovered a significant amount of oil andGas in Gujarat;

(ii) Reducing the cost of imports of crude oil. This could beachieved in two ways; by obtaining cheaper crude supplies

1/ ONGC became an independent statutory Commission in 1959, prior to thisdate, it was operating within the Geological Survey of India.

ANNEX 7Page 5 of 7

on the world market through discount and/or barter deals,and by putting pressure on the companies owning the existingrefineries to match the terms offered by their competitors.However, it implied that the GOI would own sufficient refinerycapacity to refine whatever crude it could obtain at lower cost,since the companies refused to refine oil that they had not procured.From 1956 to 1970 the GOI followed a policy which included thesethree components. Various committees were appointed to look intothe crude oil pricing practices of oil companies. The GOI under-took to create a public refining sector, with the assistance ofthe USSR and other eastern European countries, which resulted inthe creation of Indian Refineries Limited - IRL - in 1958 toconstruct and operate the refineries of Gauhati, Barauni andHaldia. The main purpose of these steps was to break up themonopoly of the foreign companies, which were denied the rightto expand or to process domestic crude yielded by the discoveriesmade by OIL in Assam and by ONGC in Gujarat. In 1964 IRL wasmerged with the Indian Oil Corporation (IOC), which had beencreated for the purpose of importing and exporting products;and

(iii) The two remaining possibilities were to obtain foreign assistanceto finance the rising cost of oil imports and/or to discouragethe growth of demand for petroleum products. The former wasnot available until the oil crisis of 1973/74, and the latter didnot offer substantial possibilities for savings since the con-sumption of petroleum in India is comparatively low and sincethere is very little "fat" to eliminate.

13. The results of the GOI policies in the late 1950's and 1960's canbe summarized as follows. On the one hand, the GOI and the various agenciesdealing with petroleum at any stage of its production/utilization gained con-siderable experience in all fundamental aspects of the industry. In par-ticular knowledge of the country's geological potential improved substan-tially.

14. By the end of the 1960's ON C and OIL had proved oil reserves ofabout 175 MMmt of oil and of 75,000 Mm of gas (Annex 1). Their combined pro-duction covered about 37% of total crude consumption in India. Total refin-ing capacity was about 17 Mmt, covering more than 90% of the country's totalproduct requirements. There was a body of trained technicians in almost allfacets of the industry. This compared to the situation twenty years pre-viously was certainly an achievement India could be proud of and whichproved economically justified. Most analysts estimate that the return ofOIL and ONGC's investments has been 13-19% at pre-1973 prices. However,only a small portion of the potential oil bearing structures had beenfully explored and no significant discovery had been made since ONGC struckoil in Gujurat in the early 60's.

ANNEX 7Page 6 of 7

C. The Early 1970's - The Move Offshore

15. While the early part of the 1960's had witnessed a decrease in theprice of oil in real terms, this trend was reversed in the late 1960's andearly 1970's until the chaotic increase in world oil prices in 1973/74. Themain reasons for this change were: the increased demand of Western Europe,Japan and eventually the US in the early 1970's; the drastic modificationsin the agreements linking host countries and international oil companies,which decreased the availability of low cost crude oil to the latter; andthe growing awareness that petroleum reserves were finite, and that producingcountries, which relied solely on their exploitation to earn foreign exchange,should have a deciding voice as to what the optimum rate of depletion shouldbe. This resulted between the end of the 1960's and 1973/74 in a steady'increase in oil prices which severely affected the balance of payments ofoil importing countries, particularly India. At the same time these changesin the world market for oil created a renewed interest in having foreign com-panies to explore in areas which were not believed attractive previously, tosecure low cost supplies. This new exploration effort was accompanied by theintroduction of new types of agreements with host govern- ents (production-sharing), whereby the foreign companies were willing to invest in explora-tion (risk capital) and to participate in development expenditures providedthat, in the event of a commercial discovery, they could (a) recover theirinitial expenditures and (b) dispose of a share in the total production.Most of these new ventures took place outside OPEC countries and weredirected to the exploration and development of offshore potential areas.

16. Previously, the world market conditions had not been favorable to

foreign investment in oil exploration in India. However, by the late 1960'sthe situation had changed somewhat, the surveys conducted by the USSR tech-nical assistance team had identified a number of prospective areas off-shore and oil companies were willing to move in the area to explore andsubsequently develop oil potential provided that they could reach an agree-ment with the GOI. The GOI was not adverse to such cooperation and negotia-tions were initiated in the late 1960's with Tenneco (US) for the explorationand possible development of the Bombay High structure. The Tenneco proposalwas a typical production sharing agreement. Tenneco would bear the full costof exploration and, if oil was discovered, a joint company would be createdin which the GOI would have a majority interest (51%), after five years man-agement would be transferred to the GOI and Tenneco would retain 49% of theproduction. In many respects this proposal was attractive, it provided ade-quate financing for risk capital, and additional financing for developmentexpenditures, it also had a substantial training component in offshore opera-tion in which ONGC had no practical experience. AfLter long negotiations, theGOI rejected Tenneco's offer, apparently on the 'ground that the share of pro-duction to be allocated to the foreign partner was too high. The GOI furtherdecided that ONGC would explore and develop the BH structure. At almost thesame time the GOI decided to open 10 offshore areas to foreign oil companiesand three production sharing contracts were signed with Reading and Bates(U.S.), Natomas (U.S.) and Asamera (Canada) to explore in the Kutch Basin,in the Cauvery Basin and in the Bay of Bengal.

ANNEX 7

Page 7 of 7

17. In many ways a historical overview of India's past developmentpolicies in the petroleum sector reflects the traditional problems of nego-tiations between unequal partners. In the early years, the oil companieswere extremely powerful and the GOI had no experience in the oil industry.This resulted in agreements which in the light of later developments appearto have been in favor of the foreign partners, although most analysts agreethat these agreements had a positive effect on India's balance of payments.In the 1950's, when India had acquired some expertise and tried to attractforeign companies to develop its potential, the latter were not interestedbecause of unfavorable world market conditions, and this led to the creationdevelopment of OIL and ONGC, which have both been successful. In the recentpast India has been trying to find a reasonable balance between foreign andnational investment. However, despite the opening of offshore areas to for-eign companies, relatively few have applied for licenses.

18. In the wake of the price increases of 1973/74 the GOI made somedrastic changes in its policy towards development of petroleum resources:

(i) steps were taken to increase production from existingfields from about 7.5 Mmt/yr to 9.0 Mmt/yr within 3years by using enhanced recovery techniques wheneverfeasible;

(ii) first priority was given to the exploration and rapiddevelopment of the Bombay High and adjacent structures.The execution of this project was assigned to ONGC,which benefited from ad hoc procedures to by-pass theusual red tape involved in getting import licensesand foreign exchange allocations; and

(iii) ten offshore areas were opened to foreign companies andthree production sharing type agreements were signedwith three foreign companies.

It appears that in the future ONGC will be the main Government agency inexploration for and development of petroleum resources onshore and offshore.In the Bombay High area, ONGC has developed so called "owner assisted pro-cedures" which enable them to use foreign consultants and contracts whileretaining the responsibility of the development and training of their ownstaff in offshore techniques. These procedures have been successful. HowONGC will proceed in the future depends largely on its further success indiscovering oil offshore and of the results of exploration by foreign com-panies.

ANNEX 8Page 1 of 4

INDIA

BOMBAY HIGH OFFSHORE DEVELOPMENT PROJECT

Evaluation of Bombay High and Bassein Reserves 1/

A. Geology

1. The main hydrocarbon accumulations in the Bombay High field arefound in a Miocene carbonate section referred to as the LIII Zone. Lesseraccumulations of gas are present in the overlying LII Zone which is notincluded in the initial development plans. The LII Zone is a multi-layeredstructure consisting of several carbonate stringers separated by shale andmarle beds. These carbon stringers are referred to as the A and A Zones.There are other hydrocarbon bearing beds in this field: the i Zone hich is

sometimes developed between the A and A Zones and the B, C and D Zones1 2

which underlie the A2 Zone. Present development plans do not include exploi-tation of these other zones (see Maps).

2. The hydrocarbon accumulations in the Bassein and South Basseinfields are found in a carbonate reservoir lithiologically similar to theBombay High field but of Oligocene rather than Miocene. The Bassein struc-ture contains both oil and gas, but the South Bassein structure is a gas-condensate reservoir with no oil column.

B. Reserves

3. During the course of exploration and initial development, ONGChas had various organizations evaluate the potential oil reserves of theBombay High field. The findings are tabulated below:

Oil In Playe Oil Recovera1le

(Million m ) (Million m

Compagnie Francaise des Petroles 1,416 min.mGulf Oil Co. (Geoman) 1,622 max. 175Institute of Petroleum Exploration 1,060 190Bombay High Offshore Group - 209

4. To obtain an updated and independent assessment the Bank in agreementwith the ONGC hired D&M to appraise the Bombay High and Bassein reserves.

1/ This annex is based on the conclusions of an independent evaluation madeby DeGolyer and MacNaughton (D&M) in December 1976 and January 1977, atthe request of the Bank.

ANNEX 8Page 2 of 4

The results of D&M's appraisal were reported in January 1977 and are sum-marized in the following table. The "proved" and "probable" classificationsare defined as follows:

(i) Proved - These reserves have been proved to a high degreeof certainty by reason of actual completion, successful testing,or in certain cases by adequate core analyses and are definedreally by reasonable geological interpretation of structureand known continuity of an oil - or gas-saturated reservoir.These reserves are limited by the lowest contour closing onestablished productivity.

(ii) Probable - These reserves, susceptible of being proved, aredefined by less direct well control but are based upon evidenceof producible gas or oil within the limits of a structure orreservoir above known or inferred water saturation. Thesereserves are limited by the lowermost perforation in theproductive interval or by the base of the productive intervalwhen there is not evidence of a hydrocarbon-water contact.

TABLE I

SUMMARY of OIL Ol(iGINALLY in PLACE and ESTIMATEI) ItESERVES

for

BOMIJAY HIGHl anid BASSEIN FIELI)S

OFFSHIORE INDIA

as of

JANUARY 1, 1977

BOMBAY filCH FIELD BASSEIN FIELDA, ZONE A2 ZONE

Item Unit Proved Probable Proved Proved Probable

Voluitile .i......e . m3 x 106 253 720 5,640 48 1,813Average Thickiness ................... m 2.75 6.6 11.9

Porosity . .... . .. Percent 29.1 29.0 20.5Water Satration. .Percent 31.9 30.3 26.8Formation Voluime Factor 1.38 1.38 1.38Estimated Originial Oil in Place m3 x 106 36.3 103.4 826.2 5.3 197.2Fstimated Recoverable Oil and

Producing Mechanisii . .[3 x 106 9.8 DI 70.2 D4 40.9 CL724.4 CL2 140.5 GL'41.9 GL and W13 258.6 GL and W16

Depletion -- At 6 yeats the assigned economic limit of 3,000 m3

/d was reached (20 wells).2 Gas Lift - At 9.2 years the assigned economic limit of 3,000 m3 /d was reachied, GOR limit of 1,000 m3 /m3 was not reached (FBIIP = 70 kg/cm2 ).3 Gas lift and( Water Injection -- At 13.5 years the assigned econoinic limit of 3,000 m13 /d was reached. Water injection equivalent to withdrawals.4 Deplelion - At 15.2 years witli 80 wells tlie economilic limit of 7,200 m3 /d was reached.

Gas Lift - At 16.8 years withi 80) wells the COR exceeded 1,000 m3 /m3 .6 Gas l ift and Water Injection -- At 23 years witli 80 wells ilte water saturation in the oil column reachied 50 percent.

Gas l.ill - At 8 years willt 40 wells the economlic limit of 5,900 mn3 /d was reachied.

In .

(D

ANNEX 8Page 4 of 4

5. Because of natural pressure decline during depletion of the reser-voirs, at some point in the future it will become necessary to maintain wellflow through gas lift and other pumping devices. Also, introduction of appro-priate secondary recovery methods will enhance the quantity of recoverable oil.These optimization measures have not yet been studied, but D&M estimate thatgas life and water injection could raise recoverable oil reserves from Aand A2 Zones to 41.9 and 258.6 million cubic meters respectively.

6. No evaluation has been made of the natural gas deposits in theBassein South structure. The quantity of gas dissolved in the Bombay Highand Bassein oil reservoirs will yield approximately 100 cubic meters ofnatural gas for every cubic meter of oil produced. As reservoir pressuresdecline this ratio will increase, that is, the production of gas per unitvolume of oil will become greater as time goes on during the production lifeof the reservoirs.

C. Production

7. At the request of the Bank, DeGolyer and MacNaughton have carriedout a two dimension study of the Bombay High reservoir (Bassein North wasnot included since not enough production history was available). The resultsshow that the most likely development plan would include about 80 developmentwells at peak production of about 225,000 b/d. Peak production could bereached in the early eighties, depending on ONGC's drilling programme andcould be maintained fo5 8 years, using water injection. Total recoverywould be 202 million m of oil or 21% of the total active oil in place. Thelife of the field would be about 30 years. D & X production program isgiven in Table 1. Sensitivity analysis shows that other development planswould lead either to lower recovery or to the same recovery at higher costs.

INDIA

BCMBAT HIGH OFFSEDRE DEELPKENT PROJECT

Projected Production Schedule from theBombay High Field

PREDICTED PERFORMANCE---------- DAILY RAT ES------ - ----------CUMULATIVE PRODUCTIO ON---------

--. ELLS- PESEPVOI.. WATER GAS WAIER GAS NECYEAR pC:D ittJ PPER,JFE OIL GAS WATER INJECT. INJECT. GOR WATER OIL GAS WATER INJECT. INJECT. OI

KG/SQ.CM4. i13 M M3 M3 M3 H3 H3/M3 PCT H M3 mm H3 M H3 M H3 1 ?5 PCT.

77.00 4 0 153 1028 109 0 0 0 106 0.0 2BI 29 0 0 0 .078.00 12 0 152 S749 593 0 0 0 103 0.0 23i80 246 0 0 0 .27j.00 20 0 151 i2215 1203 0 0 0 98 0.0 6839 685 0 0 0 .780.00 2'3 0 149 Id243 1760 0 0 0 96 0.0 13498 1328 0 0 0 1.481.00 4Q 4 14S 2 17.3 2594 0 7153 0 95 0.0 23416 2Z75 0 2611 0 2.4e.0.oo 52 8 147 35613 3369 0 16692 0 95 0.0 365415 3505 0 8704 0 3.87.0.30 o4. 24 150 35671 3348 10 36614 0 94 .0 49435 4727 3 22069 0 5.1

83 8O 28 152 35771 3364 969 50378 0 94 2.6 62492 5955 357 40459 0 6.5e3.0o 7o 26 153 3i 771 3472 Z997 51367 0 97 7.7 75549 7222 1451 59210 0 7.8-2 O 7 3 2d 154 85771 34c4 4340 50125 C 96 10.8 88c05 e4.72 3035 77508 0 9.2i7.O9 :69 28 15'4 3'772 333d 4149 4c8778 0 93 1C.4 101662 9'o91 4550 95313 0 10.57r.13 w 54 23 115 3b771 350S 4250 46900 0 98 10.6 11'.719 10971 6101 112433 0 11.9oD.^O 57 28 155 J3577i 327 4644 4S249 0 107 11.5 121776 12368 7797 128951 0 13.2r.i') 43 28 155 3J."52 4051 3913 43662 0 120 10.4 140959 13847 9225 144b90 0 14.5

91.0S ea Z l5s Z4 333 2874 3501 37721 0 118 12.6 148941 14.897 10503 158660 0 15.492.09 30 2b 155 2 1It 3116 3394 35162 0 147 13.8 156674 16034 11742 172956 0 16.293.J^ 27 2S 186 1d56 3043 3122 37191 0 164 14.4 1 6:359 17145 1 2el 186332 0 1.9;,..v3 25 26 1S4 15 59 1695 35 97 2 (759 0 106 19.5 169 321 177 4 14304 197'21 0 17.55 .00 2" 23 155 127a7 1666 5363 27'613 0 130 29. 6 173'58 18372 16264 2C7112 0 18.0

93.0) 22 16 1513 1116 1910 5986 20 85 0 189 37.2 1 I (! 19069 1 6 e9 214/2t4 0 18.497. 0 21 16 152 1I1J I I6 7 5905 1 ?? 0 15'3 3'3.4 1 :1139 1Cs 03 2060i 221999 0 18.898 00 18 16 153 rr 94 1G43 573 IYeD9 0 117 39.2 184418 I9t'85 22717 Z29249 0 19.199.00 17 16 153 7t2L 778 .4737 18243 0 99 37.9 187276 201669 24464 23590b 0 19.4

0. 0J 17 lb 153 75ut 985 5046 19167 0 130 40.0 190038 20529 2 6306 242905 0 19.71.O 16 16 IS3 7420 957 45'(3 1;990 0 129 38.3 1927'47 2087 9 27Q85 249473 0 20.02.C0 13 16 154 704 . 900 3438 17976 0 128 32.8 196318 21208 29240 256035 0 20.23 Q 2 IZ 16 153 5blu 6i3 3bL06 15579 0 120 39. 7 197366 21453 30585 261723 0 20.44.00 12 16 154 5 037 830 3841 16340 0 165 43.3 199205 21757 31988 26760i 0 20.65.30 0 10 06 153 42264 490 3566 12666 O 114 45.4 200769 21 3t 332R9 272312 0 20.86.0C 100 1 153 3393 405 3303 10776 0 119 49.3 202007 22084 3 4495 276247 0 20.97.00 9 16 153 333b 351 3295 10197 0 105 49.7 203225 22212 35697 279970 0 21.0

Sc .ii7ce: DeCColyer MlacNaughton

June 1977

COh;

ANN 8 -- Chart I

PLATt U

STRUCTURE MAPsrrs + X + + TOP OF Al PAY ZONE

4t M(IET US - OS,A)

BOMBAY HIGH FIELDOFFSHORE INDIA

'I-~~~~~~~~~~~~~~~~w._F + fX~~~ + -w

-134~~~~~~~~~~~

,/36- -i3e

+

I C+ +/50

I~~~~~~~~~~ XA flwu.

14~~~~

t ~o Y ~o U -1 r 4-< wri n ' LEG_'

L~~~~~~~~~~~~~~~~~~~~ a ,,....0T._

ANNEX 8 -- Chart II

PLArE I

OIL AND GAS PROOUCTIVE AREAS, ± + Al PAY ZONE

t IN MCTfRS I

BOMBAY HIGH FIELDOFFSHORE INDIA

~~~~~~~~~~~~~~~~~~~~~~~~~~J. n\' , 0'.,,..?

0)01

4~~~~~~~* + o-+X+-, .....

%~~~2. ~ ~ 2.

4.- + y + ±,-J + ,.

+ +o +

POROVED -

30~~~~~~

0

PROBA&LE- EQE4

cLO

L~~~~~~~~~~~~~~~~~~~~~L

+-O4-5CD UCA .S + Q O

t.C LowC5r ^X0w CAt±

LE OIFTS05.NOt

,,~ ~~ *cti ,,,c a,

ANNEX 8 -- Chart III

PLATE 3'

STRUCTURE MAPTOP OF A2 PAY ZONE

IMN ETERS-SUS5EA)

BOMBAY HIGH FIELDOFFSHORE INDIA

A~~~~~~~~~~~~A0

P ERM// C\3

+ +

F~~ ,I +\\ + ±e

L EGENO

ES *OI00,4

J0 E0t'CE WELl.

e czs WEL.

*04. 0 + SO .XA*30. .j... -4....S

ANNEX 8 - Chart IVn-co' ~~~~~~~~~~~~~n;aW

PLATE 1n

] NET GAS ISOPACHnM3' - J + BASSEIN PAY ZONE +

J (IN METERS)

3 BASSEIN ANDSOUTH BASSEIN FIELD

OFFSHORE INDIASCALE

I i 1 2 3 4 5 6 7 8 9 0 11 12 13

I 0 1 2 3 4 5 6 7 a

MILES

DECGOLYER ANO MACNAucH rof )NLAs, TExA3

JANUARY 1977

ASSE'IV F/IEL D

01

SOUrH BASSEIN FIELD

w+ + ,e 0

+ + 5

ANNEX 8 _- Cbart V

PLATE =

3 NET OIL ISOPACH

.2a -t +BASSEIN PAY ZONE + . v

t11N METERS)

3 BASSEIN ANDSOUTH BASSEIN FIELD

OFFSHORE INDIASCALE

\ 0 o 2 3 4 a 7 a 9 0 ii II 13

KPLOEERSI I 2 ~~3 4 3 6 r 9

M*GdL*EugAmw Midujs,o Q." TOM&

gJAu.jAy 1977

eMG p BA $SSEIN F/EL 0

'IA 15Q f

° , \ SOUTH. HASSEIN FIELD

.+ +

t : 0 :7.

ANNEX 9Page 1 of 5

INDIA

BOMBAY HIGH OFFSHORE DEVELOPMENT PROJECT

DETAILS OF ENGINEERING EVALUATION

A. General

1. The Bombay High development program, which started in 1974 under theresponsibility of ONGC, is the first large scale offshore project undertakenin India. Stages I and II of the project, consisting of the facilitiesrequired to produce about 80,000 b/d of crude oil and temporary tanker tran-sport facilities to bring the crude oil to shore, are substantially completed.The project consists of Stage III, which will pr9vide the facilities requiredto produce 140,000 b/d of oil and up to 2,500 Mm /d of gas by May 1979. Theproject includes: drilling of development wells and construction of wellplatforms, three production platforms and permanent pipLline facilities toshore, a shore terminal and supporting facilities, and supply lines across theBay of Trombay to connect the terminal to the users.

B. Main Components of the Project

(i) Development wells and well platforms

2. It is estimated that the full development of Bombay High and ofBassein North will require a total of about 100 development wells of whichabout 20 will be drilled by the end of 1977. The remainder will be drilledover the next four years in step with the construction of production/proces-sing facilities offshore and onshore. The project includes 20 productionwells: 16 in Bombay High North and 4 in Bassein North. ONGC has been usingdeviated wells with a step out of about 1.2 km on average. Since the reser-voir is relatively shallow (lowest oil/water contact is - 1,395 meters atBombay High) no more than four wells can be drilled from a single platform,if interference in the drainage area is to be avoided. The cost of each wellhas been estimated at US$2.4 million on the basis of ONGC's historical drill-ing costs. It has been further assumed that about 15% of the wells will notbe productive.

3. After completion of drilling, the wells are connected to theplatform, and well completion manifolds (Christmas trees) are installed oneach well. In the first stage program, two of the well platforms, Plat-forms A and C, are equipped to process the crude oil for shipment ashoreand are known as well-cum-production platforms. The crude oil from the var-ious wells flows under well-head pressure to the well-cum-production plat-forms where dissolved associated gas is separated and flared and the crudeoil pumped to the storage tanker and shipped ashore through the single buoy

ANNEX 9Page 2 of 5

mooring system. In the second stage, flow lines (8" to 18" in diameter) willconnect directly the well platforms to the production platforms where the oiland gas will be separated and treated for pipeline transport.

(ii) Offshore processing platform

4. When the project facilities are installed, there will be three off-shore platforms. These platforms will be equipped with all the necessarypumping, compressing, treating and ancillary facilities necessary to transportthe oil and gas ashore to the Uran Terminal by way of the pipelines. Twoplatforms will be located in the northern part of Bombay High and the thirdin Bassein North.

5. ONGC's production plans require that the crude oil and natural gaspipelines be installed before the start of the monsoon in May 1978. However,it appears doubtful that the Bombay High North platform can be installed andequipped by that time. ONGC has, therefore, decided to build an interim plat-form, utilizing a well jacket already on order, alongside Platform A andto provide it with a new deck and equipment to pump the crude oil to shoreuntil the main platform is available. During this same period high pressuregas from the gas-oil separator will be piped to shore under separator pressureand the low pressure gas, about 15% of the total, will continue to be flared.The main Bombay High North platform will be set adjacent to the interim plat-form.

6. The Bombay High North platform will be typical of the other twooffshore production platforms. (Table 1 provides a description of the BombayNorth platform). Oil (and water produced with the oil) from Platforms A andC gas-oil separators will first go to the settling section of the platform.A de-emulsifying agent well injected by metering pumps, and the oil-watermixture will enter a coalescing section of pipe and the water settling drum.The drum will be provided with an electric field generator to promote morerapid coalescence of the water droplets. Water will be continuously removedand the oil will be treated with pour point depressants or other flowimprovers before being continuously pumped into the crude oil trunklineto the Uran Terminal.

7. Gas from Platforms A and C will be piped to a compressor suctionscrubber where water and hydrocarbon condensate are removed prior to compres-sion. The gas will be compressed in three stages with cooling and condensateremoval between stages. After the final stage of cooling and condensateknockout, the gas will be routed through a glycol dehydration unit and dis-charged into the gas trunkline to ths Uran Terminal. Dehydration will reducethe dewpoint of the gas to about -50 C. It is not expected that hydrateformation will be a problem in piping the gas ashore, but the gas does havesufficiently high carbon dioxide content which in the presence of water posesa serious corrosion threat to carbon steel. Since dehydration would berequired in any event prior to gas fractionation, by performing this opera-tion offshore a serious pipeline corrosion hazard is eliminated at relativelylittle extra cost.

ANNEX 9Page 3 of 5

8. All the platforms will be of the "piled steel type". The floatingsteel frame or "jacket" will be towed in an horizontal position from thefabrication yard out to the field where buoyancy tanks will be flooded andthe jacket iiprighted with the assistance of derrick barges. The jacketwill be secured on the bottom by massive piles driven into the seabed. Amulti-cellar deck will be fitted on the jacket, and prefabricated equipmentmodules will be installed. Because of the weight of the deck and of themodule, installation can only take place under good weather conditions andit is, therefore, expected that no major offshore construction work willtake place during the monsoon (June to October).

(iii) Subsea pipelines

9. The production platforms will be connected to shore by two 209 kmlong subsea pipelines for oil and gas, respectively. The crude oil line willbe 30" in diameter and the natural gas3line 26" in diameter, with an initialcapacity of about 260,000 b/d and 9 Mm /d, respeitively; this capacity couldeventually be increased to 460,000 b/d and 18 Mm /d by the addition of pump-ing and compressing facilities. The size of the line has been selected on thebasis of Pipeline Technologists' (PLT) feasibility study, which shows that thecost of the pipeline is not very sensititve to size as shown below.

A B C

Design rate003 b/d 260 360 460

Mm /d 9 17 8

Pipeline cost(discounted at 10%over 10 years)Crude oil (US$000) 85.441 106.018 108.446Gas (US$000) 81.447 90.448 96.500Total 166.888 196.466 204.946

% difference over (A) - 17.7 22.8% difference over (B) - - 4.3

An incremental investment of 22.8% will enable ONGC to almost double thecapacity of the lines and therefore to transport any incremental volume of oiland/or gas which may be discovered in the structures surrounding Bombay High.ONGC's decision to go for the higher diameter is justified and is in accordancewith industry practice in offshore development.

10. The two subsea pipelines will be weight coated (average specificgravity varying between 1.2 and 1.6 depending on the depth of water) and willbe laid on the sea bottom where it is expected that they will sink in the mud.

ANNEX 9Page 4 of 5

No trenching is considered except for the shore approach. The pipelineswill be connected by risers to the platforms and will be provided withscrapers and launching and receiving devices. Table II provides summaryspecifications of the trunk lines.

11. The construction of the two pipelines wil be carried out by expe-rienced contractors having adequate lay barges available.

(iv) Onshore terminal

12. The two subsea pipelines will terminate at Uran, in the Bay ofTrombay, where a shore terminal will be built including a crude stabilizationunit, a gas processing plant and storage facilities. The crude oil, afterit arrives at the Uran Terminal, will be routed through a crude oil stabiliza-tion process which will remove the dissolved gases to produce a 10 Dsi RVP(Reid vapor pressure) crude suitable for storage and refinery processing.This will be accomplished by heating the crude oil to a predetermined temper-ature and flashing off gas in two stages, the last under vacuum. The stabil-ized crude is sent to storage and the gas compressed to join the gas streamfrom offshore. From storage the crude oil will be pumped to the Trombayrefineries and to Butcher Island for shipment to other refineries or forexport. Table III includes a detailed list of the equipment and facilitiesto be built at Uran.

13. The gas stream arriving by trunkline from off shore and producedat the crude stabilization plant will go to the gas fractionation plant atUran. The plant will initially be a simple LPG recovery unit, but it willbe designed so that additional fractionation can be added at a future datewhen a demand develops for petrochemical feedstock. The LPG recovered fromthe natural gas will be stored in pressurized tanks from which it will bepumped to the Trombay refineries for additional processing or bottling anddistribution. All residual gas will initially be piped to FCI for feedstockin ammonia production. Any excess gas not utilized by FCI or others will beused for fuel at the Trombay power station.

(v) Supply lines

14. From the Uran Terminal, crude oil will be shipped by pipeline acrossthe Bay of Trombay to the refineries and through existing loading lines fromTrombay to the Butcher Island Terminal where coastal tankers will be loadedfor supply of domestic refineries. Natural gas and LPG will also be shippedby pipeline across the Bay to the Trombay fertilizer plant of FCI, to apower plant and to the refineries.

15. The crossing of the Bay of Trombay presents some technical problemsas the supply lines cross the navigational channels of the Port Authorityand routes have to keep clear of existing and planned dredging areas. ONGC

ANNEX 9Page 5 of 5

has been working with the Port Authority and a final route has been agreedupon. (Summary specifications of the supply lines are in Table II).

(iv) Supply base and telecommunications

16. So far ONGC has been operating from facilities leased from theBombay Port Authority. These facilities have been adequate but they arescattered over a wide area and will not be sufficient in the future, par-ticularly if Bombay becomes one of the major centers of offshore operationsin the west coast of India. ONGC has therefore decided on the constructionof a supply base which will include:

- Berthing facilities for supply vessels;

- Repair facilities for offshore drilling rigs andassociated equipment;

- Storage facilities for the offshore operations;

- Warehouses, offices and communicatino center;

- Helicopter base;

- Housing for employees;

The supply base will be built at Nhava Sheva, a site recently acquired byONGC. Originally ONGC planned to operate only the above facilities and tolease out additional space to offshore contractors. In the future, ONG.C maydecide on the construction of a fabrication yard depending on the developmentof offshore projects.

17. A telecommunications and telecontrol system will be built toprovide adequate operational control over the production and transportfacilities.

ANNEX 9Table I

INDIA

BOMBAY HIGH OFFSHORE DEVELOPMENT PROJECT

Summary Specifications of Offshore Production Platforms

Bombay High BasseinNorth Interim North

I. Main specifications

Oil capacity (b/d) 160,000 80,000 40-60,000

Gas capacity (MDMcfd) 90 45 35

Weight

II. Main equipment and facilities

Cellar Deck Upper Decks (Modules)

fire fighting pumps and tank; - main power generators, oil heatersand crane;

water lift pump;- standby power generator, battery

potable water system; room, workshop and stores;

sewerage treatment; - crude oil pumping, pour pointdepressant and de-emulsifier units;

oil coalescer;- control, switchgear, radio, telecom-

crude oil metering; munications heating and ventilatingroom;

gas metering;- living quarters (for approximately

diesel oil storage tank; 42-50 men less the facilities pro-vided on the interim platform) and

scraper traps and launchers; helicopter deck;

water treatment plant. - radio mast;

- gas compression scrubbers, dehydra-tion and interstage cooler units; and

- flare.

Sources: ONGC.

June 1977

ANNEX 9Table II

INDIA

BOMBAY HIGH OFFSHORE DEVELOPMENT PROJECT

Summary Specifications of Pipelines

Diameter Length(inch) (km)

I. Trunklines

Crude oil 30" 209Natural gas 26" 209

II. Supply lines

Uran to Trombay(ethane) 12" 20

Uran to Trombay(crude oil) 30" 18

Uran to Trombay(natural gas) 18" 20

Uran to Trombay(LPG) 8" 18

Sources: ONGC.

June 1977

ANNEX 9Table III

INDIA

BOMBAY HIGH OFFSHORE DEVELOPMENT PROJECT

Uran Shore Terminal

(i) Gas Fractionation Plant

Design capacity 140-175 MMCFD two-stream separation:propane and butane (LPG) and methane-ethane residualgas with provision to separate the methane and ethaneat a later date. Major equipment items are:

- refrigeration system;

- fractionating tower;

- heat exchanger, drums, pumps, etc.;

- utilities.

(ii) Utilities and Ancillaries

- main control and communication room;

- offices and living quarters;

- standby power generator;

- steam generator;

- oily water separation and treatment facilities;

- flare;

- fire fighting system.

(Power, water, telephone, etc. tie-ins tolocal systems.)

ANNEX 9Table III(Cont'd)

(iii) Crude Oil Stabilization Plant

Design capacity 230-300,000 bld including the followingmajor equipment items:

- Crude oil heaters;

- Pressure flash drum;

- Vacuum flash drum;

- Pumps and compressors;

- Possible crude oil dehydration facilities.

(iv) Crude Oil Storage Tank Farm

Net storage of 2.3 million barrels when production peaks;3 tanks at 140,000 barrels net capacity and 5 tanks at370,000 barrels.

(v) Pumphouse

- Transfer pumps for shipping crude oil to Trombay refineries;

- Transfer pumps for shipping LPG to Trombay refineries.

I I 4

INDIAAPPRAISAL OF ONGC BOMBAY

HIGH OFFSHORE DEVELOPMENT PROJECTSchematic Layout of Facilities II

EXISTING WELLHEAD ANO SEPARATION

PLATFORM 'A, GAS FLARE AND TANKER

LOADING fACILITIES PUMP AND COMPRESSOR ON SHORE FACILITIES

J $ > 16G,G0G 6PDL3T 6 HUCMD URAN TERMINAL

1500000 BPS - SO0 MMCMD

CAPACITY

(INTERIM PLATFORMNOT SHOWN)

' \i= g~~~OMRAY HI1GH FIELD

\ - ASSEIN FIELD

OIL STOFkAGE ~ ~ ~ ~ ~ ~ ~ ~ ~~IIV SltV

SEPARATION_ PUMP ONO COMPRESSOR OIL TRUNNLKNE LGINESR STATION

PLATFORM PLATFORM~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~AD A ROES LN

>X^~~~~~~~~~~~~~~~~~~~~~~~~~~SI FIELD IN X

hO,0000 DPD M-CMO tIF MECM . U

TREATiTA CITY OF BMRA

SEPARATION, PUMP AHD CUMPHESSUN OIL IHUNKLINEPA bOTINOSPUMPRAN COMPRESSO

PLATFORM PLATFORM \~~~~~~~~~~PATOR

160,000 hPD MMCMO (IF REQUIRED)

CAPACITY

sO..... ON(ic - Ilclud. .11 I.-i11416 plnned I0, l_ll aeuoloP4.ent ol Wold Rank-I7169

Jun. 1977 Ouo-..y H,h -ecptO vxlz *nA voll plalloim

I

I

I I I I

ANNEX 10Page 1 of 2

INDIA: APPRAISAL OF ONGC BOMBAY HIGH OFFSHORE DEVELOPMENT PROJECT

CAPITAL COST ESTIMATE

(US$ '000) (R's million)FE Local Total FE Local Total

A. Develooment Drilling

1. Wells 37,000 12,000 49,000 332.0 110.0 442.02. Well Platforms 28,000 37,000 250.0 80.0 330.0

Sub-tota] 65.000 21,000 86,000 582.0 l 0.0 772.0

Infrastructure

1. Land 4,500 4,500 40.0 40.02. Pipelines

Crude oil BH to Uran (30")Material 36,000 2,000 38,000 324.0 18.0 342.0Construction 40,000 3,000 43,000 360.0 27.0 387.0

Sub-total 76,000 5,000 81,000 684.0 45.0 729.0

Natural ras BH to Uran (26")Material 31,000 2,000 33,000 279.0 18.0 297.0Construction 34,000 2,000 36,000 306.0 18.0 324.0

Sub-total 65,000 4,000 69,000 685.0 36.0

Crude oil Uran to Trombay (20")Material 1,400 900 2,300 16.0 5.0 21.0Construction 1,000 2 000 3,000 .0 18.0 27.0

Sub-total 2,400 2,900 3,300 25.0 23.0 48.0

Natural ras Uran to FCI (18")Material 1,200 400 1,600 11.0 4.0 15.0Construction 1,000 1,900 2,900 9.0 17.0 26.0

Sub-total 2,200 2,300 4,500 20.0 21.0 41.0

Ethane to Trombav (12")Material 1,000 500 1,500 9.0 4.0 13.0Construction 1,000 1,500 2,500 9.0 14.0 23.0Sub-total

LPC to Trombav (8")Material 400 200 600 4.0 2.0 6.0Construction 1,000 1,600 2,600 9.0 14.0 23.0

Sub-total 1,400 1,800 3,200 13.0 16.0 29.0

Total Pipelines 149,000 18,000 1,67,000 1,345.0 159.0

3. Production Platforms

Bombay Pigh NorthJacket 13,000 13,000 117.0 117.0Deck 3,300 3,300 29.7 29.7Service Module 3,300 3,300 29.7 29.7Utility Module 4,200 4,200 37.8 37.8Electrical Module 3,000 3,000 27.0 27.0PumDing Module 1,500 1,500 13.5 13.5Compression Module 7,000 7,000 63.0 63.0Hook-up & Coomissioning 7,400 1,000 8,400 66.6 9.0 75.6

Sub-total 42,700 1,000 43,700 384.3 9.0 393.3

Bassein North

Jacket 6,300 6,300 56.7 56.7Deck 3,00a 3,000 27.0 27.0Service Module 2,200 2,200 19.8 19.8Utilitv Module 2,000 2,000 18.0 18.0Electrical Module 1,500 1,500 13.5 13.5Pumping Module 1,000 1,000 9.0 9.0Compression Module 3,300 3,300 29.7 29.7Hook-up & Commissioning 5,500 1.000 6,500 49.5 9.0 49.5

Sub-total 24,800 1,000 25,800 223.2 9.0 232.2

"F" Platform 15,000 500 15,500 135.0 4.5 139.5

Total Platforms 82,500 2,500 85,000 742.5 22.5 765.0

ANNEX 10Page 2 of 2

(US$ '000) (Rs million)FE Local Total FE Local Total

4. Uran Oil Terminal

Civil Works 6,800 6,800 61.2 61.2Tanks 6,000 6,000 54.0 54.0Materials & Eouipment 500 2,000 2,500 4.5 18.0 22.5Construction_ 2,200 2,500 _ 19.8 19.8

Sub-total 500 17,000 17,500 4.5 153.0 157.5

5. ras Processing PlantCivil Works 1,000 1,000 11.0 11.0Utilities 1,000 1,000 9.0 9.0Eouipment 5,000 3,000 8,000 45.0 30.0 75.0Construction & Commissioning 2.000 2,000 17.0 17.0Sub-total 5,000 7,000 12,000 45.0 67.0 112.0

6. Oil Stabilization Plant

Civil Works 2,300 2,300 20.7 20.7UTtilities 1,000 1,000 9.0 9.0Eauipment & Materials 1,000 2,000 3,000 9.0 18.0 27.0Construction and Cormissioning 4,700 _4,700 42.3 42.3Sub-total 1,000 10,000 11,000 9.0 90.0 99.0

7. Nhava Sheva Supply Base

Earthworks 6,700 6,700 60.0 60.0SuDD1v Base 5,300 5,300 49.0 49.0Flelioort 1,000 1,000 9.0 9.0Uitilities &Services 2,000 _2,000 20.0 20.0Sub-total 15,000 15,000 138.0 138.0

S. Telecontrol & Communications

Materials and Eouipment 4,000 4,000 8,000 36.0 36.0 72.0Construction 4,000 4,000 36.0 36.0

Sub-total 4,000 8,000 12,000 36.0 72.0 108.0

9. Customs Dutv - 12,000 12,000 - 108.0 108.0

10. Engineering, Technical Services _& Project Supervision 28,000 9,000 37,000 250.0 80.0 330.0

Total Base Cost (RC) 335,000 124,000 459,000 3,014.0 1,119.5 4,133.5

Phvsical Contingency (PC) /1 51,000 19,000 70,000 461.0 171.5 632.5

Price Contingencv 310 (8.0% of BC + PC) '100 11,000 42,000 278 103.0 381.0

Total 417,0nO 154,000 571,000 3,753.0 1,394.0 5,147.0

Source: ONGC, Consultant's (PLT) and mission's estimates.

/1 Based on: 15% wells and platforms5% materials and eauipment (offshore)25% construction (offshore)202 all onshore facilities

June 1977

INDIAAPPRAISAL OF ONGC BOMBAY HIGH OFFSHORE DEVELOPMENT PROJECT

PROCUREMENT & CONSTRUCTION SCHEDULE

1977 1978 1979 1980

[ PI re BI NE 5C O ST11 B TI ON IJ IF IMA- I I 10Et|| N DII IA|jJI 9III 1°J gFIA JJAS OINIDjF A JJAISONlDj1FM-AlM JJAlODFA JAON F A JA

DPIPELINES MATERIALS T A

PIPELINES CONSTRUCTION TEA M

"FALL BACK" PLATFORM T A M

(LUMP SUM B ID)

BASSEIN NORiTH PLATFORMS T AM

(LUMP SUM BID)

BOMBAY HIGH NORTH PLATFORM T AM

(LUMP SUM BID)

URBAN OIL TERMINAL

CRUOE STABILIZATION PLANT T A Coo

PUMPHOUSE T A

TANKFARM T A C

LPG RECOVERiY PLANT T A C

GAS FRANTIONATING PL-ANT T A a.

TELECONTROL & COMMUNICATIONS

TELEMETRY &CONTROLS T AC

I ICCOMMUNICATIONS T A

NHAVA SHEVA SUPPLY BASE VRIOUS LOCAL CONTRACTS

T -TENDER ISSUEDA -- CONTRACT AVSARDED0 DELIVERY PE-RIOD)

CCONSTRUCTION PERIODINCLUDING COMMISSIONING W,dBn 72

Revised May, 1977

I

INDIA

BOMBAY HGIH OFFSHORE DEVELOPMENT PROJECT

PHOJECT15D PRRAM DISBURSRSENTS

Actual ProjectedTotal

73/74 74/75 75/76 76/77 77/78 78/79 79/80 80/81 81/82 82/83 83/84 84185

A. Phase I and II 26.6 11.1 98.7 67.7 204.1

B. Phase IIIDevelopment wells 50.0 50.0Well platform 36.o

Sub Total 1

Infraatructure 258,6 171. 55,0 485.o

Total 344.6 171.4 55.0 571,0

C. Phses IV and VDevelopment wells 50.0 75.0 10.0 10.0 10.0 .10.0 5.0 170.0Wella platforms 6o.o _ 7. 7. 127.5

Sub Total 1 T35.0 5.0 297.5

Water injection 17.5 17.5 17.5 52.5 17.5 122.5

ftploration (dry holes) , 3 3 30 _ 3 35. 3 280.0Sub Total in 4 *-5 7 *5

Infratructure 24.0 31.0 12.0 3.0 70.0

Contingencies 1.4 9.3 7 3 0 .5 _ _ _ 6 _ 27.0 228.8

Total 36.4 183.7 264.4 107.4 152.3 10o.6 83.0 67.0 998.8

Grand Total 26.6 11.1 I17 070 .1 4L. 104.6 L; 67.0 ,.23;

SOURCE: ONGC, D&H, misaionsa estimates

June 1977

ANNEX 1-3

INDIA

APPRAISAL OF ONGC

BOMBAY HIGH OFFSHORE DEVELOPMENT PROJECT

ESTIMATED SCHEDULE OF DISBURSEMENTS

IBRD Fiscal Year Cumulative Disbursementand Quarter at End of Quarter

(US$ '000)1977/78

Sept. 30, 1977 2,000Dec. 31, 1977 22,000March 31, 1978 50,000June 30, 1978 80,000

1978/79Sept. 30, 1978 122,000Dec. 31, 1978 132,000March 31, 1979 140,000June 30, 1979 143,000

1979/80Sept. 30, 1979 146,000Dec. 31, 1979 148,000March 31, 1980 150,000June 30, 1980

Sources: Missionsf estimates.

June 1977

ANNEX 14Page 1 of 3

INDIA

BOMBAY HIGH DEVELOPMENT PROJECT

Environmental Impact

A. General

1. The GOI and its agencies are aware of the importance of protectingthe marine and coastal environment from depredation by man. Existing omnibuslegislation authorizes the appropriate ministries to promulgate regulationsgoverning activities in their areas of responsibility within the 200 mileeconomic zone. The British North Sea regulations are being used as a guidein the case of hydrocarbon exploration, production and transportation. Inthis connection, the Norwegian government has also offered assistance indrafting such offshore regulations as marine pipeline construction and oper-ation, pollution control, diving and fire safety. ONGC, for its part, hasformulated a contingency plan, still in draft form, for coping with oilspills and has issued tenders for a vessel outfitted for fire fighting andoil spill clean-up. In addition the GOI is establishing a Coast Guard Ser-vice which became operative on February 1, 1977 when the Indian navy turnedover four vessels to the new organization. Among its other duties the CoastGuard will enforce maritime pollution control regulations and come to the aidof ONGC in such emergencies as well blowouts, fires and spills.

2. The following is a discussion of the various ecological considera-tions related to the Bombay High project.

B. Pipelines

3. Transportation of crude oil by pipelines reduces the potentialfor sea pollution over movement by tankers. The pipelines from the offshoreplatforms to the onshore terminal at Uran, Butcher Island and the Trombayarea will be closed systems in which the oil and gas will be contained underpressure at all times. Potentially polluting operations such as loading andunloading tankers and releasing oily tanker ballast water will be eliminated.The possibility of leakage due to corrosion, third party damage or excessiveinternal pressure will be minimized to the fullest extent practical by thefollowing pipeline design provisions:

(a) automatic pump and compressor shutdown whenpipeline pressures or flow rates exceed safepreset limits;

ANNEX 14Page 2 of 3

(b) constant monitoring by computer aided equipmentof all pump and compressor station operationswith automatic shutdown under unsafe conditions;

(c) sacrificial anodes and impressed current corrosionprevention systems;

(d) coating of the pipelines with coal tar enamel forcorrosion protection;

(e) burying of the pipelines below sea bottom undership channels and other areas of marine activity;

(f) burying of the onshore pipelines except withinbattery limits of the terminal; and

(g) routing of the pipelines away from ship anchoringareas at sea and built-up areas on land.

C. Offshore Platforms

(a) Oil and Gas Streams

4. The movement and processing of the oil and gas will take placein closed systems which will prevent loss to the air. Water separated fromthe oil and gas streams will be treated in oily water separation and treat-ing facilities which will reduce the oil content to about 20 parts per mil-lion (PPM) before dispersal. All vapors will be released to the flare, andliquid spills will be contained and directed to the oily water facilities.

(b) Chemical Additives and Reagents

5. De-emulsifying agents: These are organic surface active com-pounds used to promote separation of the water in the crude oil. They willbe mostly retained in the oil. The portion in the effluent water will beextremely dilute and will not be harmful to marine life.

6. Glycol compounds: These chemicals will be used in gas dehydrationand will be contained in a closed regenerative system. There will be minorlosses to the gas pipeline. Accidental spills or leaks will be containedand directed to the oily water facilities where the glycols will be largelyneutralized and disbursed without harmful effect.

7. Pour point depressants: The type of viscosity modifier has notyet been determined. However, these compounds are used in very low con-centrations (about 200-300 PPM) and will be retained in the oil. Thenormal preventions against leaks and spills will be taken.

ANNEX 14Page 3 of 3

8. Corrosion inhibitors: These are also added in very low concen-trations and will be retained in the oil and gas.

(c) Life Support Systems

9. Provisions will be made to treat human waste and refuse to a stan-dard equivalent to present practices in the North Sea.

(d) Products of Combustion

10. Combustion gases from turbines driving compressors, pumps and elec-tric generators will be exhausted to the atmosphere. However, this will notcause an atmospheric pollution problem in view of the remote location andthe fact that the gas is essentially free of hydrogen sulfide and combustiontemperatures are too low for nitrogen oxides formation. This will also applyto the flares which will normally only have pilot burners lighted. Duringplant upsets when large quantities of gas might have to be flared there maybe smoke-and soot production, but proper adjustments can eliminate this con-dition.

D. Onshore Facilities

11. All oil and gas handling and processing onshore will take placein closed systems from which normal losses will be minimal. Effluent waterfrom the facilities will undergo oily water separation and treatment to limitoil content to 20 PPM before disposal. Gas leakage will be vented to a remoteflare which will also dispose of combustible gases during a process upset.Liquid leaks and spills will be contained and washed to the oily water sewer.The process areas will be paved to prevent seepage into the soil. The chemi-cals, gas combustion and life support considerations discussed for the off-shore facilities above also apply onshore and should not cause any notice-able pollution problems. Crude oil storage tanks will have floating roofswhich ride on the liquid surface as the tank fills and empties thus elimi-nating the vapor losses due to "breathing." The tanks will be erected withindikes to contain spills; spills and water drawoff will go to the oily watersewer.

INDIAAPPRIAISAL Of~ ONOCC-EOMEAY HIGH OFFSHORE OEVELOFMENT PllOJECT

ONOC -ORGANIZATION CHART AS OF DECtM8ER 31. 107.i

r^ g~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~a

I~~~~~~~~~~~~~~~~~ ti.

I ~ ~ ~ 44*4,34 ~ ~ 0F,,, Ib440440~ ~ ~ ~ ~ _ *444 _*~44

-' &44 o4j04 ,~4 & C I ,, T r-

If I~44 L 44or - tPLMUa10-

4444St4 < '. r.oC- < {1 .

{ -1" s 4.n i;0n-| 1{<}t1-1-

-| r I- - .1 {H b l . 4444._JX

.1 f^ kS~_ 0

H rnXne g | |~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~44*n.-7

e- 1 ( X r Ohl I v~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~_L ~~~~~~~~~~~ )~~~~To'4{L 1 f Ttlt5; 2 -t } {< 1 1 1-__ _ ~~~~~~~~~~~~~~~~~~~~~~~~~~~I

IINDIAAPPIIAISAL OF OJNGC bOMBAY HIGH OFFSHOR( DC/EI IWC>MENT PFIOJECI

ItVItI-~~ - F0AIDI ]t

( ~~~~~~~~~~~~~~~~~~~~__$ I_1__ I *_I 0, I ,T, I

_ L / .. lG ~@Yn ifR < ^ 00-

[ r21 6) |Xt^LHL3L +7g4<Gr^tt tL

ANNEX 17

INDIA-

BOMBAY HIGH DEVELOPMENT PROJECT

Particulars of the Insurance Coverage Maintained by ONGCfor Bombay High Development Project as of January 1977

1. With Messrs. United India Fire & General Insurance Co. Ltd.,Bombay, India (Nationalized Insurance Company):

(i) Package insurance coverage of Rs 65 million for drill-ships, tankers (and the cargo), pipelines, flare tower,and platforms with associated equipment. The gross valueof the insured assets is approximately Rs 88 million.

(ii) Separate coverage of Rs 109 million for survey vessel andsupply boats. -

(iii) Separate coverage for accident insurance, and casualvisitors.

2. With Messrs. Oriental Fire & General Insurance Company(Nationalized Insurance Company) for coverage of Rs 10 million forthree chartered helicopters.

3. With New India Assurance Company (Nationalized InsuranceCompany) for cargo insurance for transportation of materials betweenbases and various fields. No insurance is needed for materials storedin the bases.

January 1977

ANNEX 18Page 1 of 4

INDIA

BOMBAY HIGH OFFSHORE DEVELOPMENT PROJECT

Notes and Assumptions to Financial Statements and Projections

A. Producing Properties and Depletion Policies

1. Producing Properties account may be defined as the value assignedto the development of natural resources. Depletion is defined as proratedvalue assigned to the extinction of natural resources. The unit of account-ing for producing property is an area covered by a license or lease. Allexpenditure incurred on exploration and development (other than survey as itis not possible to identify survey expenditure to a particular area) of thearea under the mining lease is capitalized under Producing Properties whichrepresents the total effort in monetary terms expended to locate and developthe hydrocarbons for exploitation.

2. There had been several changes in ONGC's policy in charging deple-tion of producing properties and amortization of exploration expenditure withretrospective effect from FY 1972. These changes are described as follows:

(a) In FY 1975 ONGC adopted the amended provisions of theAgreement under Section 42 of the Income Tax Act,1961, and charged all producing properties equallyover three years instead of fifteen years commencingfrom the accounting year when the properties are de-clared as commercially productive.

(b) Up to fY 1974 ONGC treated an area as commerciallyproductive when it attained 25% of its peak antici-pated annual production. Since the adoption of theamended provision of the Income Tax Act, ONGC beganto treat an area as commercially productive from thedate the regular production started.

(c) Under the new Agreement, all expenditure on geologicalor geophysical surveys, exploration, and drilling in-curred before the date of commencement of the regularproduction is capitalized as Producing Properties.The expenditure after the date of regular productionis charged against current income.

3. The main effect of these changes is to accelerate the increaseof operating expenses, and thereby reduce operating income for tax purposes.As shown below, this policy introduces wide variations in the operating in-come computation. As a consequence, the financial accounts do not reflectthe actual position of the producing assets of the company.

ANNEX 18Page 2 of 4

FY74 FY75 FY76 FY77----Rupees in million----

Operating Revenue 816 1,250 1,369 1,448

Operating Expenses 868 729 1,127 1,060

of which Depreciation/Depletion is: 667 401 567- 482

Operating Income -52 521 242 388

B. Financial Statements

4. The financial statements in this report cover ONGC's operationsonshore and offshore for the period FY 1973 through FY 1982. Separate projec-tions have been prepared for each of the two operations. The results are con-solidated to show ONGC's overall position. The following paragraphs describethe basis and assumptions to the projections.

Production

5. The production volume estimates for BHDP were prepared by additionalDirector (Finance and Accounts) on December 1976 (Table 1). The projectionfor onshore activities is based on ONGC's revised Five-Year Plan (December1975) and the estimates made by the Ministry of Petroleum. The onshoreproduction is constrained by the producing capability of existing oil fields.The production rate depends mostly on the availability of surface facilities.It is assumed that the necessary transportation facilities and refiningcapacities will, become available by FY 1981. The gas production is esti-mated according to the projected crude oil production and average historicalgas/oil ratio. The following table shows ONGC's onshore production volume andnumber of rigs for the period FY 1976 to FY 1979:

No. of Rigs ProductionYear Addition Total 1/ Oil (M.T.) Gas (M.M3) 2/

1976/77 8 40 5.2 6381977/78 0 40 5.2 6381978/79 0 40 5.4 6641979/80 0 40 6.5 6701980/81 0 40 6.5 6701981/82 0 40 6.5 670

1/ Net after retirement of old rigs.

2/ Commercialized production.

ANNEX 18Page 3 of 4

Excise Tax and Sales Tax

6. Since August 1975 GOI has levied an excise tax on the sale ofcrude oil by ONGC at Rs 60 per ton. In the projection, an equivalent amountof the excise tax has been taken out of the operating costs for FYs 1975 and1976, and the average price per ton of crude oil has been adjusted accord-ingly. Since no royalty and state sales tax is levied on BHDP offshore crudeoil, the sales tax is calculated as 4.0%, and royalty is calculated at Rs 45per ton on ONGC's onshore crude oil only.

Operating Costs

7. The operating costs consist of drilling and engineering services,production and transportation services, repair and maintenance expenditure,and other miscellaneous expenses. It is ONGC's accounting practice to col-lect and allocate all expenditure and depreciation on service basis to eachactivity/area, which the mission was not able to breakout at the aggregatelevel. Direct opetating costs are projected at Rs 35 per ton of crude oilproduction for onshore reflecting past history. For BHDP the estimates pre-pared by Addition Director (F&A) are used. Since ONGC is to have a more re-stricted employment policy to limit its present oversize staff, and the BHDPexpansion will have a minimum effect on ONGC in terms of staff, wages are in-cluded in the direct operating costs, and are not projected separately.

Exploration Costs

8. From statistics on exploration expenditures in the US petroleumindustry compiled by the Chase Manhattan Bank, on an average the explorationexpenditure is about 25% of the fixed asset budgets. The same ratio is usedfor ONGC's exploration costs as part of the capital expenditure which includesfixed assets, development drilling and exploration expenditure. These expen-ditures include only the cost of dry holes as any successful well would becharged against a new project.

Depreciation

9. Depreciation is calculated at an average composite rate of 7% on theaverage fixed assets of two consecutive years for onshore. Depreciationfor the BHDP project is calculated on the basis of ONGC depreciation schedule(Table 2). The expenditure for development drilling and exploration aredeleted in ten equal installaments. Exploratory expenditures are amortizedequally over 15 years after they are commercially producing.

Borrowings

10. In the past, the proceeds collected by GOI from the excise tax on thesale of crude oil have been transferred to OIDB for its financing of the oil-related industries. It is assumed in the forecast that the GOI and OIDB willprovide all necessary funds to ONGC besides the Bank's proposed loan at theaverage cost of borrowing to ONGC (para. 11).

ANNEX 18Page 4 of 4

Interests and Dividends

11. The interest rate for the 15 year loans from OIDB is 4.5% per annumwith a two year grace period and 13 equal yearly repayments. Government loansbear interest at an average rate of 10.25% per annum with a four year graceperiod and six equal yearly repayments. In the absence of a definite financ-ing plan, the forecast assumes the average cost of capital to ONGC, which is6.5% with 2 year grace period and 8 equal yearly repayments. The interestrate for commercial borrowing is assumed at 8.3% with a two-year grace periodand five equal yearly repayments. As in the past, dividend on governmentcapital is waived as long as ONGC borrows from the GOI and/or OIDB.

Other

12. In the past ONGC's accounts receivable had been two to three monthsof total revenue. In the projection, it is assumed that bill collectionswill be improved to within five weeks of total annual revenues. Inventoriesand materials are estimated on the basis of average operational and construc-tion requirements. Cash has been projected on the basis of debt service, cashoperating costs, and local cost of construction requirements.

13. Accounts payable and provisions are estimated on the basis of inven-tory level, operating costs including taxes, and local construction cost pay-ments.

ANNEX 18Table I

INDIA

BOMBAY HIGH DEVELOPMENT PROJECT

ONGC's Projected Production Schedule

Fiscal Crude Natural Gas LPGYear (MM BBLS) (MM of Cu. Mtrs.) (M of MT)

73/74 4 _74/75 - _75/76 - _76/77 - _77/78 15.7 -78/79 36.3 152.7 -79/80 51.0 209.5 6080/81 75.0 571.0 18081/82 90.0 674.5 22082/83 89.5 669.5 21083/84 90.0 674.5 2z084/85 89.5 708.5 23085/86 90.1 667.5 21086/87 89.5 672.5 22087/88 90.1 700.0 22088/89 89.5 776.5 25089/90 80.1 778.0 25090/91 60.5 551.0 18091/92 55.5 649.0 21092/93 48.9 590.0 19093/94 42.9 312.5 10094/95 34.7 420.0 13095/66 30.3 360.0 12096/97 25.3 310.0 100

TOTALS 1,274.6 10,447.0 3,330

UNIT PRICES

Crude $5.00/BBL

Natural Gas $55.50/M Cubic Meters

LPG $90.00/MT

Source: ONGC and mission's estimates.June 1977

ANNEX 18Table 2

INDIA

BOMBAY HIGH DEVELOPMENT PROJECT

Depreciation Schedule

Dep. Dep.Item No. Fixed Asset Begins Rate

1 Pre-Prod 73-74 76/77 10 yrs.

2 Pre-Prod 74-75 76/77 10 yrs.

3 Pre-Prod 75-76 76/77 10 yrs.

4 Pre-Prod 76-21/5/76 76/77 10 yrs.

5 Del. & Dev. Wells 78/79 10 yrs.

6 Water Inj. Wells 80/81 10 yrs.

7 Oil Well Platforms 78/79 3 yrs.

8 Oil Production Platforms 78/79 3 yrs.

9 Water Injection Platforms 80/81 3 yrs.

10 Urban Oil Terminal 78/79 15%

11 Gas Processing Plant I 78/79 15%

12 Oil Stabilization Plant 78/79 15%

13 Pipelines 78/79 10%

14 Telecom & Controls 77/78 10%

15 Nhava Sheva Supply Base 78/79 5%

16 Land - 0%

17 Customs 77/78 12%

18 Engineering 77/78 17%

19 Bombay High South Production 80/81 10 yrs.Platform

20 Gas Processing Plant II 81/82 15%

INDIA

BOMBAY HIGH OFFSHORE DEVELOPMENT PROJECTONGC STATEMENTS OF INCOME(in millions of Rupees)

History Projection

Fiscal Tear &iding March 31: 1974 1975 1976 1977 1978 1979 1980 1981 1982(Tentative)

Production 6Crude 01 ((1o metric tore) 4.0 4.5 5.2 5.6 7.3 10.2 13.3 16.5 18.5aas (10 cLubic meters) 386.o 541.0 638.0 638.0 640.0 816.7 879.5 1,241.0 1,345.0Condenaate/LPG (10' metric torn) 7.4 7.3 5.2 7.3 7.3 7.6 68.o 188.o 228.0

RereudeB O777 1,183 1,286 1,365 1,866 2,834 3,745 4,823 5,503Gaa 36 ' 58 77 77 69 149 177 358 410Condensate/LP0 3 9 6 6 6 8 57 170 169

Total Revenues 816 1,250 1.369 1448 1.941 2.991 2aZIZ L5.3 6.082

Operatirg xpenseOperatirg Cptmea 70 141 180 246 854 1,035 1,231 1,389 1,555Depreciation/Oepletion/Amort. 667 401 567 482 624 1,O85 1,355 1,611 1,794Salea Tax/Royalties 120 172 191 267 245 254 307 307 307Income Taxes - - 138 - - - - 600Other 11 15 51 65 50 53 56 58 60

Total Operating Expenses 868 729 1,127 1,060 1,773 2,427 2,910 3,365 44,316

Operating Income ( 52) 521 242 388 168 564 1,030 1,986 1,766

Other Incoite 64 38 39 47 49 52

Total Net Incoom after Tax 12 554 280 427 210 608 1,077 2,035 1,818

Intweret 52 44 49 _5 171 294 36,o 361 333

Net Income ( 40) 510 231 362 39 314 708 1,674 1,485

Operating Ratio (S) 106.4 58.3 82.3 73.2 91.3 81.1 74.1 62.9 71.0

* Operating Costs include the coat of dry holes starting 1977/78.

SOURCEi ONOC and missionse estimates

June 1977

INDIABOMBAY NIGm OuFStiORE DEVELOP1ENT PROJECT

ONGC BAIANCE SIIEETS(in millions of Rupees)

History Proieetion

As of March 31: 1974 1975 1976 1977 1978 1979 1980 1981 1982_ _ _ _ _ _ _ _ _ _ _ _(Tentative)

kaneta

Fixed Assets including 4,567 5,126 6,350 8,263 9,567 14,989 18,002 21,021 22,969Capital Eipenditures

Lena Accumulated Depl/Depr/Amort. 3605 4, O6 4,573 5, 05579 6,764 8, 119 9730 11,524

Net Fixed Assets 962 1,120 1,777 3,208 3,888 8,225 9,883 11,291 11,1445

Work in Prcgress 191 315 610 948 3,437 1,777 2,341 1,154 2.L57

L/T Inveatments 415 432 458 471 481 492 504 517 531

Current Assetscash 17 121 25 30 35 40 45 9 1336Accounts Receivable 374 363 380 292 312 359 407 463 526Inventories 50 470 868 1,000 1,100 1,170 1,210 1,2140 1.270

Total 741 954 1,273 1,322 1,447 1,569 1,662 PA702 2LJ2

Total Assets 2821 118 5,949 9253 12,063 14,390 15A666 16615

Liabilitiea

Ialit 1,352 1,352 1,673 2,414 3,816 5,032 5,883 5,883 5,883Reserves/Surplua/Deficit ( 80) 428 657 1,018 1,057 1,371 2,079 32L753 5,28

Total Hquity 1,272 1.780 2,330 3,432 4,8 73 6,403 7,962 2.6 11,121

L/T Liabilities 809 730 1,131 1,137 3,530 4,750 5,478 5.029 4.455

Current Liabilitioa 228 311 657 780 850 910 950 999 1,039

Total Liabilities 30 2,821 4,118 5 949 9,253 12,063 2139 15,6614 6,615

Debt/Bquity Ratio 39/61 55/45 33/67 34/66 42/58 42/58 41/59 34/66 29/71

Ourrent Ratio 3.3 3.1 1.9 1.7 1.7 1.7 1.8 1.8 1.9

Rates of Return (%)ln IArert Fixed Assets:

Before Tax kdjustmtnt -4.7 50.0 16.7 15.6 4.7 9.3 11.4 18.8 15.5After Tax Adjustnt -4.7 50.0 7.2 15,6 4.7 9.3 U1.4 18.8 10.3

On Average Invested CapitalBefore Tax Adju.t.n t -2.4 27.9 9.5 9.0 2.5 5.8 8.4 14;1 11.7After Tax Adjuetnnt -2.4 27.9 4.1 9.0 2.5 5.8 8.4 14.1 7.7

SOURCE: ONOC and aission's estimatesJune 1977

INDIABOMBRAY HIGH OFFSHORE DEVELOPMENT PROJECT

ONGC STATEIIENT OF SOURCES AND APPLICATIONS OF FUNDS(in millionts of Rupees)

History -Projection

TotalFiscal Year biding March 31: 1974 1975 1976 1977 1978 1979 1980 1981 1982 1978 toH______________Rnding __Harch __31t (Tentative) 1982

Internal SourcesTotal Net Tncome before Deprn. 12 554 280 427 210 608 1,077 2,035 1,818 5,748Depreciation/Depletion 667 401 567 482 624 1 1.,355 1,611 1,794 6.469

Total 679 955 847 909 834 1,693 21432 3,646 3,612 12,217

Opora,tionalcquiremnta

Repaymente 52 178 129 209 140 203 278 450 574 1,645Interest 52 44 49 65 171 294 369 361 333 1,528

Working Capital 127 131 (_26) |_73) 55 62 53 42 58 270

Total 231 353 152 201 366 559 700 853 965

Net Available from Operation 448 602 695 708 468 1,1314 1,732 2,793 2,647 8t774

Investment Programs 443 685 1,519 2,251 3,793 3,762 3,578 1,832 2,301 15,266

L/T Investmente 5 17 26 *13 10 11 12 13 42 60

Total Inveetmsnt 702 1,545 2,264 3,803 3,773 3,590 18145 2,315 15,326

Balance to Finance - 100 2, 0 5 _ _

Financed by:

Equity oontribution -00I -21 l 1402 1.216 oil , _&

Longi Term B3orroving-43 - 43

OIDB - 100 529 815 990 765 765 _ 2,520IRD - - - - 900 360 90 _ _ 1,350Other I _ 298 152 - - 45°

Total Borvowinp P_ 100 529 815 9 1.,423 1, 007 _4,363

Total - 100 850 1,556 W 2.639 1 ,858_ 7.832

Surplus _ 948 332 1.280

Debt Service Coverage: - 4.3 4.8 2.4 2.7 3.4 3.8 4.5 4.0

SOURCEs ONOC and mission's eatinatea

Jdme P, 1977

ANTN 21Page 2 of 2

INDIA

BOMBAY HIGH OFFSHORE DEVELOPMENT PROJECT

ONGC STATEMENTS OF DEBT(in millions of Rupees)

Fiscal YearEnding March 31: 1977/78 1978/79 1979/80 1980/81 1981/82

GOI and OIDBBorrowings 1,033 765 765 - _Repayments 140 203 278 338 403Interest 125 173 207 184 168Opening 1,737

IBRD Proposed LoanBorrowings 900 360 90 - -

Repayments - - - 53 81Interest 46 108 131 139 133

Cotncercial BanksBorrowings - 298 152 - -Repayments - - - 59 90Interest - 13 31 38 32

SummaryBorrowings 1,933 1,423 11007 - -Repayments 140 203 278 450 574Interest 171 294 369 361 333Debt Services 311 497 647 811 907

SOURCE: ONGC and mission's estimates

June 1977

ANNEX 22Page 1 of 2

INDIA

BOMBAY HIGH OFFSHORE DEVELOPMENT PROJECT

Financial Viability of the Bombay High Development Project

A. General

1. On the basis of production volumes, unit price assumptions, operat-ing expenses, and capital investments derived from De Golyer and MacNaughtonstudies and agreed upon by ONGC, a discounted cash flow analysis has beendeveloped for the BHDP. The analysis which includes the entire developmentprogram including water injection covers a twenty-four year period 1973/74 to1966/97.

2. The analysis follows the practice in the petroleum industry, anduses such yardsticks as internal discounted cash flow (DCF) rate of returnand payout period essentially to rank vaious alternatives in the investmentdecision process.

3. The analysis is based on the actual domestic price to ONGC as ofJanuary 1977. The US dollar equivalent of these unit prices are $5.00lblfor crude oil, $55.50/1,000/cubic meters for natural gas, and $90.00/metricton for LPG. The analysis also includes a study on the basis of $13.00/blfor crude oil which is closer to the import parity of a similar quality crudeoil landed at Bombay.

B. Summary and Conclusion

4. The Bombay High field is a giant field, which, with the additionof North Bassein, would produce over a billion barrels over the next 30years under conservative assumptions. According to industry standards,these fields are extremely profitable and would yield oil at an averagecost of about US$1.35 per barrel, or about one-tenth of the internationalprice of oil as of January 1977. On the basis of US$13 per barrel, theoverall net foreign exchange savings are of about US$16.0 billion over theperiod considered in the analysis (1977/78 - 1996/97). The discounted cashflow return (DCF) is 66.2%. This shows that nothing short of a completecollapse of international prices or a drastic reduction of output couldjeopardize the financial viability of the proposed project. The former isnot likely to occur and, in fact it is more likely that oil prices will in-crease in real terms in the future, thus improving the feasibility of theproject. The latter is a risk that exists in any oil development project.However, as explained in Annex 8, the studies carried out by ONGC and theirconsultants, including the independent experts hired by the Bank, indicatedthat ONGC's production targets are reasonable. The production schedulefor crude oil, natural gas and LPG is given in Annex 18.

ANNEX 22Page 2 of 2

4. At US$ 5/barrel the development program would yield a DCFreturn of 19.8% after taxes to ONGC. This return is somewhat lower thanwhat an international oil company would require for a foreign venturebut it is comparable to what is normally required for domestic ventures.

5. The net present value of the savings, calculated on the basisof US$13 (barrel, over the life of the project (20 years) is as follows:

discount rate (%)

10% 20% 40%

Net Present Value(US$ million) 6,682 3,362 1,030

The payout time is about 1.7 years at US$13/66 and 4.8 years at US$5/barrel.

C. Sensitivity Analysis

6. The main risk in this project is a delay in the production.The sensitivity analysis shows that a delay of one full year, which isunlikely to occur would bring the DCF return to about 50% at US$13/barrel.

7. Table I and 2 provide the discounted cash flow under the twoprice assumptions.

INDIAAPPRAISAL OF ONW - BAY1OMT1 OFFHORE DEVEMP' PROWECT

Discounted Cash Flwn Analysis at u3*13/b1

-4 -3 -2 -1 0 1 2 3 4 5 6 773/74 74/75 75/76 76/77 77/78 78/79 79/80 80/81 81/82 82/83 83/84 84/85

PRODUCTION VOLUMES__________________

CRDllE OIL (Million Barrels) 00 0.0 0.0 3.8 15.7 36.3 51.0 75.0 90.1 89.5 90.1 89.5NATURAL GAS (Million Cubic Meter.) o,o 0.0 0.0 0.0 0,0 152.7 209.5 571.0 674,5 1071.0 1079.0 1134.0LPG (Million Tons) 0.0 0.0 0.0 0.0 0.0 0.0 0.1 0.2 0.2 0.2 0.2 0.2

REVENUES

CRUDE OIL 0.0 0.0 0.0 49.4 204.1 471.9 663.0 975,0 1171.3 1163,5 1171,3 1163.5NATURAL GAS 0.0 0.0 0.0 0.0 0.0 8.5 11.6 31.7 37,4 59.4 59.9 62,9LPG 0.0 0.0 0.0 0.0 0.0 0.0 5.4 16.2 19.8 18.9 19.8 20.7

TOTAL REVENUES 0.0 0.0 0.0 49.4 204.1 480.4 680.0 1022.9 1228.5 1241.8 1251.0 1247.1EXPENSES

OPERATING COSTS 0.0 0.0 0.0 8.2 44.4 48.9 57.2 58.7 58.7 58.7 58.7 58.7DEPRECIATION 0.0 0.0 0.0 20.4 29.4 83.9 107.3 117.1 124.6 127.8 125.1 116.3INTEREST 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0FINANCIAL CHARGES 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

TOTAL EXPENSES 0.0 0.0 0.0 28.6 73.8 132.8 164.5 175.8 183.3 186.5 183.8 175.0OPERATING INCOME

GROSS 0.0 0.0 0.0 20.8 130.3 347.5 515.6 847.1 1045.3 1055.4 1067.2 1072.2TAX LOSS CARRY-FORWARD 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0TAXABLE INCOME 0.0 0.0 0.0 20.8 130.3 347.5 515.6 847.1 1045.3 1055,4 1067.2 1072.2INCOME TAX 0.0 0.0 0.0 0.0 0,0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

NET PROFIT(LOSS) 0.0 0.0 0.0 20,8 130.3 347.5 515.6 847.1 1045.3 1055.4 1067.2 1072.2INVESTMENTS

INCREASE OR (DECREASE) IN CASH 0.0 0.0 0.0 1.0 3.1 5.5 4.0 6.9 4.1 0.3 0.2 - 0.1INCREASE OR (DECREASE) IN A/C REC 0.0 0.0 0.0 4.1 12.9 23.0 16.6 28,6 17.1 1.1 0.8 - 0.3INCREASE OR (DECREASE) IN INVTRY 0.0 0.0 0.0 1.0 3.1 13.2 3.9 6.5 4.0 - 0.2 0.2 - 0.1

NET WORKING CAPITAL 0.0 0.0 0.0 6.1 19.1 41.7 24.6 41.9 25.2 1.2 1.1 - 0.5FIXED ASSETS 26.6 11.1 98.7 67.7 331.4 281.5 228.5 47.0 73.0 35.0 17.5 5.0

TOTAL INVESTMENT 26,6 11.1 98-7 73.8 350.5 323.2 253.1 88.9 98.2 36.2 18.6 4.5

NET CASH FLOW - 26.6 - 11.1 - 98.7 - 32.6 - 190.8 108.3 369.8 875.3 1071.6 1146.9 1173.7 1184.0

CUMULATIVE NET CASH FLOW - 26.6 - 37.7 - 136.4 - 169.0 - 359.8 - 251.5 118.3 993.6 2065.2 3212.1 4385.8 5569.8

0l

8 9 10 11 12 13 14 15 16 17 18 1985/86 86/87 87/88 88/89 89/90 90/91 91/92 92/93 93/94 94/95 95/96 96/97

PRODUCTION VOLUMES

CRUDE OIL(MllUion Barrels) 90.1 89.5 90.1 89.5 80.1 60.5 56.5 48.6 42.9 34.7 30.3 25.3NATURAL GAS (Millon Cubic HMters) 1068.0 1076.0 1120.0 1242.0 1245.0 882.0 1038.0 944.0 500.0 672.0 576.0 496.0LPG (Million Tons) 0.2 0.2 0.2 0.3 0.3 0.2 0.2 0.2 0.1 0.1 0.1 0.1

REVENUES

CRUDE OIL 1171.3 1163.5 1171.3 1163.5 1041.3 786.5 734.5 631.8 557.7 451.1 393.9 328.9NATURAL GAS 59.3 59.7 62.2 68.9 69.1 49.0 57.6 52.4 27.7 37.3 32.0 27.5LPG 18.9 19.8 19.8 22.5 22.5 16.2 18.9 17.1 9.0 11.7 10.8 9.0

TOTAL REVENUES 1249.5 1243.0 1253.3 1254.9 1132.9 851.7 811.0 701.3 594.4 500.1 436.7 365.4EXPENSES

OPERATING COSTS 58.7 58.7 23.7 23.7 23.7 21.3 19.2 17.3 15.5 14.0 12.6 11.3DEPRECIATION 107.7 84.4 83.3 41.6 22.3 13.5 6.5 3.0 1.3 O.B. 0.8 1.7INTEREST 0.0 0.0 0.0 0.0 0.0 0.0 0°0 0.0 0.0 0.0 0.0 0.0FINANCIAL CHARGES 0.0 0.0 0-0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

TOTAL EXPENSES 166.4 143.1 107.0 65.3 46.0 34.8 25.7 20.3 16.8 14.8 13.4 13.0OPERATING INCOME

GROSS 1083.1 1099.9 1146.2 1189.7 1086.9 816.9 785.3 681.0 577.7 485.3 423.3 352.4TAX LOSS CARRY-FORWARD 0.0 0.0 0.0 0.0 0.0 0,0 0.0 0.0 0.0 0.0 0.0 0.0TAXABLE INCOME 1083.1 1099.9 1146.2 1189.7 1086.9 816.9 -785.3 681.0. 577.7 485.3 423.3 352.4INCOME TAX 0.0 0,0 0.0 0,0 0.0 0.0 0.0, 0.0 0.0 0.0 0.0 0.0

NET PROFIT(LOSS) 1083.1 1099.9 1146.2 1189.7 1086.9 816.9 785.3 681.0 577.7 485.3 423.3 352.4INVESTMENTS

INCREASE OR (DECREASE) IN CASH 0.0 - 0.1 0.2 0.0 - 2.4 - 5.6 - 0.8 - 2.2 - 2.1 - 1.9 - 1.3 - 7.3INCREASE OR (DECREASE) IN A/C REC 0.2 - 0.5 0.9 0.1 - 10.2 - 23.4 - 3.4 - 9.1 - 8.9 - 7.9 - 5.3 - 36.4INCREASE OR (DECREASE) IN INVTRY 0.1 - 0.1 0.2 - 0.1 - 2.4 - 5.2 - 1.0 - 2.1 - 1.6 - 2.1 - 1.2 - 15.9

NET WORKING CAPITAL 0.4 - 0.8 1.2 0.1 - 15.1 - 34.3 - 5.2 - 13.4 - 12.7 - 11.8 - 7.7 - 59.6FIXED ASSETS 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0°0 0.0 0.0 - 4.4

TOTAL INVESTMENT 0.4 - 0.8 1.2 0.1 - 15.1 - 34.3 - 5.2 - 13.4 - 12.7 - 11.8 - 7.7 - 64.0

NET CASH FLOW 1190.4 1185.1 1228.3 1231.2 1124.2 864.6 797.0 697.4 591.6 497.9 431.8 418.1

CUMULATIVE NET CASH FLOW 6760.2 7945.3 9173.6 10404.8 11529.0 12393.6 13190.6 13888.0 14479.6 14977.5 15409.3 15827.4

INTERNAL (DCF) RATE OF RETURN = 66.2 PER CENT ^

o-1

. z 8~~~~~~~~~~~~~~~~~~~~~~

IN1DI1iPP1UISAL OP ONOC - BOKAYf1f OMSHORE DZV10PK1T PR OET

Diacounted Cash Flow Analyiui at US$5b1

-4 -3 -2 -1 0 1 2 3 4 5 6 773/74 74/75 75/76 76/77 77/78 /8/79 /9/80 80/81 81/82 82/83 83/84 84/85

PkODUCTION VOLUMES

CRUDE OIL (Million Barrel.) 0.0 0.0 0.0 3.8 15.7 36.3 51.0 75.0 90.1 89.5 90.1 89.5NATURAL GAS (Killion Cubic Hater.) 0.0 0.0 0.0 0.0 0.0 152.7 209.5 571.0 674.5 1071.0 1079.0 1134.0LFP (Million Tons) 0.0 0.0 0.0 0.0 0.0 0.0 0.1 0.2 0.2 0.2 0.2 0.2

REVENUES

CRUDE OIL 0.0 0.0 0.0 19.0 78.5 181.5 255.0 375.0 450.5 447.5 450.5 447.5NATURAL GAS 0.0 0.0 0.0 0.0 0.0 8.5 11.6 31.7 37.4 59.4 59.9 62.9LPG 0.0 0.0 0.0 0.0 0.0 0.0 5.4 16.2 19.8 18.9 19.8 20.7

TOTAL REVENUES 0.0 0.0 0.0 19.0 78.5 190.0 272.0 422.9 507.7 '-25.8 530.2 531.1EXPENSES

OPERATING COSTS 0.0 0.0 0.0 8.2 44.4 48.9 57.2 58.7 58.7 58.7 58.7 58.7DEPRECIATION 0.0 0.0 0.0 68.0 77.0 256.6 216.8 165.6 146.0 102.9 68.3 44.0INTEREST 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0FINANCIAL CHARGES 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

TOTAL EXPENSES 0.0 0,0 0.0 76.2 121.4 305.5 274.0 224.3 204.7 161.6 127.0 102.7OPERATING INCOME

GROSS 0,0 0.0 0.0 - 57.2 - 42.9 - 115.5 - 2.0 198.6 303.0 364.3 403.2 428.5TAX LO05 CARRY-FORWARD 0.0 0.0 0.0 0.0 - 57.2 - 100.1 - 215.6 - 217.6 - 19.0 0.0 0.0 0.0TAXABLE INCOME 0.0 0.0 0.0 - 57.2 - 100.1 - 215.6 - 217.6 - 19.0 284.0 364.3 403.2 428.5INCOME TAX 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 164.0 210.4 232.9 247.4

NET PROFIT(LOSS) 0.0 0.0 0.0 - 57.2 - 42.9 - 115.5 - 2.0 198.6 139.0 153.9 170.4 181.0INVESTMENTS___________

INCREASE OR (DECREASE) IN CASH 0.0 0.0 0.0 0.4 1.2 2.2 1.6 3.0 1.7 0.4 0.1 0.0INCREASE OR (DECREASE) IN A/C REC 0.0 0.0 0.0 1.6 5.0 9.3 6.8 12.6 7.1 1.5 0.4 0.1INCREASE OR (DECREASE) IN INVTRY 0.0 0.0 0.0 0.4 1.2 5.1 1.6 2.6 1.6 - 0.1 0.1 - 0.0

NET WORKING CAPITAL 0.0 0.0 0,0 2,3 7.3 16.6 10.1 18.2 10.3 1.8 0-5 0.1FIXED ASSETS 26.6 11.1 98.7 67.7 331.4 281.5 228.5 47.0 73.0 35.0 17.5 5.0

TOTAL INVESTMENT 26.6 1.1 98.7 70.0 338.7 298.1 238.6 65.2 83.3 36.8 18.0 5.1

NET CASH FLOW - 26.6 $11 - 98.7 - 59.2 - 304.6 - 157.0 - 23.7 299.0 201.7 220.0 220.6 219.9

CUMULATIVE NET CASH FLOW - 26.6 - 37.7 - 136.4 - $95.6 - 500.3 - 657.3 - 681.0 - 382. Q 180.4 39.6 260.2 480.2

-4' "' --' .' '' ' ' ' '' '' aqh

v - * 9~~~~~~~~~~~"

8 9 10 I1 12 13 14 15 16 17 18 1985/86 86/87 87/88 88/89 89/90 90/91 91/92 92/93 93/94 94/95 95/96 96/97

PRODUCTION VOLUMES

CRUDE OIL(Mfllion Barrels) 90.1 89.5 90.1 89.5 80.1 60.5 56.5 48.6 42.9 34.7 30.3 25.3NATURAL GAS (Million Cubic Meters) 1068.0 1076.0 1120.0 1242.0 1245.0 882.0 1038.0 944.0 500.0 672.0 576.0 496.0LPG (Million Tons) 0.2 0.2 0.2 0.3 0.3 0.2 0.2 0.2 0.1 0.1 0.1 0.1

REVENUES

CRUDE OIL 450.5 447.5 450.5 447.5 400.5 302.5 282.5 243.0 214.5 173.5 151.5 126.5NATURAL GAS 59.3 59.7 62.2 68.9 69.1 49.0 57.6 52.4 27.7 37.3 32.0 27.5LFG 18.9 19.8 19.8 22.5 22.5 16.2 18.9 17.1 9.0 11.7 10.8 9.0

TOTAL REVENUES 528.7 527.0 532.5 538.9 492.1 367.7 359.0 312.5 251.2 222.5 194.3 163.0EXPENSES

OPERATING COSTS 58.7 58.7 23.7 23.7 23.7 21.3 19.2 17.3 15.5 14.0 12.6 11.3DEPRECIATION 25.4 20.0 18.9 2.1 0.8 0.8 0.8 0.8 0.8 0.8 0.8 1.7INTEREST 0.0 0.0 0.0 0.0 0,0 0.0 0.0 0.0 0.0 0.0 0.0 0.0FINANCIAL CHARGES 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

TOTAL EXPENSES 84.1 78.7 42.6 25.8 24.4 22.1 19.9 18.1 16.3 14.8 13.4 13.0OPERATING INCOME________________

GROSS 444.6 448.3 489.8 513.1 467.6 345.6 339.1 294.4 235.0 207.7 180.9 150.0TAX LOSS CARRY-FORWARD 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0TAXABLE INCOME 444.6 448.3 489.8 513.1 467.6 345.6 339.1 294.4 235.0 207.7 180.9 150.0INCOME TAX 256.8 258.9 282.9 296.3 270.1 199.6 195.8 170.0 135.7 120.0 104.5 86.6

NET PROFIT(LOSS) 187.8 189.4 206.9 216.8 197.6 146.0 143.3~ 124.4 99.3 87.8 76.4 63.4INVESTMENTS

INCREASE OR (DECREASE) IN CASH - 0.0 - 0.0 0.1 0.1 - 0.9 - 2.5 - 0.2 - 0.9 - 1.2 - 0.6 - 0.6 - 3.3INCREASE OR (DECREASE) IN A/C REC- 0.2 - 0.1 0.5 0.5 - 3.9 - 10.4 - 0.7 - 3.9 - 5.1 - 2.4 - 2.4 - 16.2INCREASE OR (DECREASE) IN INVTRY 0.0 - 0.0 0.1 - 0.0 - 0.9 - 2.1 - 0.3 - 0.8 - 0.7 - 0.8 - 0.5 - 6.2

NET WORKING CAPITAL - 0.2 - 0.2 0.6 0.7 - 5.8 - 14.9 - 1.2 - 5.6 - 7.1 - 3.7 - 3.4 - 25.7FIXED ASSETS 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0,0 0.0 0.0 0.0 - 4.4

TOTAL INVESTMENT - 0.2 - 0.2 0.6 0.7 - 5.8 - 14.9 - 1.2 - 5.6 - 7.1 - 3.7 - 3.4 - 30.1

NET CASH FLOW 213.4 209.7 225.3 218.3 204.1 161.7 145.2 130.8 107.1 92.3 80.6 95.2

CUMULATIVE NET CASH FLOW 693.6 903.3 1128.5 1346.8 1550.9 1712.6 1857.8 1988.6 2095.7 2188.0 2268.5 2363.8

INTERNAL (DCF) RATE OF RETURN 19.8 PER CENT

SEXC 0 ~~~~~~~~~~~~~~~~~~~~~~~1 4~~~~~~~~~~IT

. ,~~~~~~~~~~~~~~~~~~~~~~

ANNEX 23Page 1 of 3

INDIA

BOMBAY HIGH DEVELOPMENT PROJECT

Assumptions Used in the Economic Evaluation

A. Future supply/demand of petroleum in India

1. Petroleum demand projections were derived from the Fuel Policy Com-mittee Report of 1974 and from the Second India Studies: Energy (K. Parikh -1976). These studies show that india will require about 40-50 tmint of oil by1983/84 and about 57-77.5 Mmt by 1990. In establishing India's future demandthe higher assumption was used until 1985, as it was assumed that coal substi-tution would not have had its full impact. Beyond 1985 it was assumed thatcoal substitution will be more significant and petroleum demand was estimatedas the average between the higher and lower bracket (Chart II).

2. Future onshore production was estimated using linear regression overa period of 17 years. The results show that it would reach about 11.75 Mmt in1980, 14.5 Mmt in 1985 and 17 Mmt by 1990 (Chart I). These projections assumethe continuation of past trends (the discovery of small to medium fields).Offshore production is based on ONGC's projections and on DeGolyer andMacNaughton Report (Chart II). The results are summarized below:

Million metric tons Average rate1980 1985 1990 of Growth (%)

Total Petroleum requirements 31.50 50.00 67.50 7.9

Domestic productionOnshore 11.75 14.50 17.00 3.8Bombay High and Bassein North 7.00 12.00 8.00 -

Total 18.75 26.50 25.00 2.2

Imports 12.75 23.50 42.50 13.9

import dependence (imports/total requirements 40% 47% 63% 64%

8. Selection of the Optimum Development Program for Bombay High

3. At the initiative of the Bank, De Golyer and Mac Naughion (consult--ants, U.S.) have carried out two reservoir engineering studies. The first oneto assess the reserves of the Bombay High and North Bassein fields (Annex 8),the second one to optimize the production program of the Bombay High field.

ANNEX 23Page 2 of 3

No optimization was carried out for the North Bassein field as productionhistory was too short. The second study led to the selection of two possibleproduction schedules. The first one is based on achieving maximum productionas soon as technically feasible, the second one aims at maintaining a steadylevel of production (plateau) for several years and at maximizing ultimaterecovery. A summary of the technical characteristics of the two schemesand of their relative economic feasibility is given below.

Case I Case II(maximum recovery) (maximum production)

Life of the field (years) 31.0 81.0

Maximum recovery of oilin place 21.0 19.5

Miaximum production (000 b/d) 225.0 280.0

Maximum oil recovered(million tons) 170.0 158.0

Duration of plateau (years) 8.0 2.0

Number of wellsdevelopment 80.0 60.0water injection 28.0 28.0

Rate of return % 93.2 91.4

Net present value over 15years at discount rates of- 10% (US$ million) 4,787 4,585- 20% (US$ million) 2,527 2,456- 40% (US$ million) 866 845

4. ONGC development program is predicated on maintaining a steadyproduction over an 8 to 10 years period and on maximizing recovery, whichaccording to the above results in the technical solution which would maximizebenefits. Since reservoir studies are still being carried out for the NorthBassein field, a flat production rate of 40,000 bd, which can be achievedfrom existing wells, has been assumed over the life of the project.

C. Cost/Benefit Analysis

5. The cost of the project is estimated at US$1,620 million, it ex-cludes cutoms duties and taxes but includes provision of US$350 million for

ANNEX 23Page 3 of 3

the further exploration of the Bombay High area and US$32.3 million forthe facilities required to use the crude oil and the gas (Annex 24).Operating costs are based on ONGC's projections adjusted on the basis ofhistorical costs in similar projects.

6. Benefits are the saving derived from the substitution of domesticcrude oil, natural gas and LPG for imports. The value of these products wasestimated on the basis of international prices (CIF India) for crude oil andLPG and of domestic prices, which are comparable to international prices, fornatural gas.

Crude oil US$13.00/bl

Natural gas US$55.00/000 m

LPG US$90.000/Mt

7. The rate of discount which equalizes the costs and benefits streamsover a period of 20 years is 165% if sunk costs are not included and 66% ifthey are included. Since sunk costs are essentially the cost of explorationand early development drilling, the latter provides a better appreciationof the economic feasibility of the entire program. No attempt has beenmade to calculate an incremental return for the project as the facilitiesto be built under Phase III cannot be dissociated from those already cons-tructed and from those planned under Phase IV and V.

D. Sensitivity Analysis

8. An increase of 20% in the program cost would bring the economicreturn of the entire program (including sunk costs) to 56%. A delay ofone year in production would bring it to 50%.

ANNEX 24Page 1 of 5

INDIA

BOMBAY HIGH OFFSHORE DEVELOPMENT PROJECT

Utilization of the Crude Oil, Natural Gasand Natural Gas Liquids

A. General

1. The question of the utilization of the crude oil, associated naturalgas and natural gas liquids (NGL) to be produced at the Bombay High field andassociated structures was raised quite early after the first productive wellshad been drilled. At that time a Working Group (the Bombay High WorkingGroup) had been created under the chairmanship of the General Manager ofHindustan Petroleum Corporation Limited (HPCL) to study:

(i) what design modifications would be required inthe two Trombay refineries to use the Bombay High(BH) crude;

(ii) what markets existed for natural gas, liquifiedgetroleum gas (LPG) and other NGL in the Trombayarea; and

(iii) what would be required to make maximum use of theassociated gas which otherwise would have to beflared.

From February to July 1976 the Working Group did some considerable work byitself and hired consultants to carry out a comprehensive market survey ofthe potential utilization of gas and associated products in the Trombay area.A contract was signed in mid-September 1976 with Stone and Webster IndiaCorporation (SWIC) a subsidiary of Stone and Webster (consultants, U.S.).The final report of Stone and Webster would be available by mid-1977. Thefollowing is based on their preliminary conclusions, and from data suppliedby the Working Group and HPCL.

ANNEX 24Page 2 of 5

B. Plans for the Utilization of the Bombay High Crude Oil

2. There are at present two refineries in the Trombay area with acapacity of 3.75 tfmt/yr and 2.75 Mmt/yr respectively. These two refineriesare located in the same area and are supplied by a single marine terminallocated on Butcher Island in the Bay of Trombay. Both are relatively simplerefineries with a high yield in middle distillates and white products. Untilrecently they were supplied by Persian Gulf crude imported by tanker. TheWorking Group has already studied the problems arising from a switch fromimported crude-oil to Bombay High supplies. Their conclusions are that thetwo refineries could use a BR crude feedstock provided that some minor modi-fications are made to the process design. These modifications would includethe installation of additional heating and desalting equipment. The currentprogram calls for an input of Bombay High crude of 2 Mmt by the end of 1977,which will be processed with Middle East crude and of 4.6 Mmt by the end of1978 which will be processed neat.

3. Other refineries are making modifications to absorb BE crude by1980/81 (Koyali 3 Mmt, Cochin 1 Mmt, and Coril 1.2 Mmt). Thus by the end of1980 the volume of Bombay High crude which could be refined in Indian refin-eries should be close to 10 Mmt/yr (200,000 b/d) which is consistent with-ONGC's production schedule. The cost of these modifications should not exceedUS$10 million equivalent which should be financed from internal cash genera-tion or loans from OIDB or domestic commercial banks.

4. Even after the above modifications have been carried out, the twoTrombay refineries will not absorb the entire crude production of the BH field(para. 3). Excess crude oil will therefore be shipped by coastal tankers toother coastal refineries in the south and north-western part of the country,or exported abroad if the existing process of these refineries cannot absorbthe full production of Bombay High. It is not expected that there would beany problem in marketing Bombay High crude which, despite its high pour pointand wax content, is very attractive because of its high yield in light andmiddle distillates.

C. Potential Market for Natural Gas and NaturalGas Liquids in the Trombay Area

K 5. The natural gas produced in association with Bombay High crude oilcontains several components which can be divided into three main categoriesof products:

(a) lean gas consisting mainly of methane which can eitherbe used as a high quality fuel or as feedstock for thefertilizer industry;

(b) liquefied petroleum gas (LPG) which consists mainly ofpropane and butane and can be used in cylinders of about15 to 45 kg to supply the residential market or in bulkto supply some commercial and small industrial users; and

ANNEX 24Page 3 of 5

(c) ethane which is a feedstock for the petrochemicalindustry.

It should be pointed out that while associated gas is a valuable by-productof the oil production, its relative value compared to crude is low. At acrude production level of 200,000 b/d, assuming present international pricesfor crude oil and a price based on heat content equivalence for the gas, thetotal value of the gas produced in association with BH crude oil would beabout US$85 million/yr equivalent to about 1/10 of the value of the crude.It is therefore obvious that any project should be designed to maximize crudeproduction and utlization in the shortest possible time, even if it impliesthat some gas has to be flared in the early stage of production.

(a) Potential Markets for Methane

6. The Fertilizer Corporation of India (FCI) owns a large plant in theTrombay area. Part of this plant currently produces fertilizers using naphthaas feedstock and refinery gas as fuel for steam raising and utilities. FCIestimates that these facilities 5ould be converted to the use of natural gasand could absorb about 700,000 m /day by mid-1978 when the gas will be firstavailable. FCI is in the process of studying the conversion of its facilitiesfrom naphtha to gas. In addition, it is planned that an additional fertilizerunit (ammonia/urea plant) will be added by the end of 31979. It has alreadybeen decided that it could absorb about 1.2 million m /day.

(b) Potential Market for LPG

7. The main use of LPG in the Trombay/Bombay area will be for residen-tial purposes as a substitute for kerosene or charcoal currently used forcooking and water heating. As in most cities where a large number of poten-tial consumers do not have access to an organized distribution of energy(large gas and/or electricity distribution grid), the demand for LPG has beengrowing fast in the area and had to be limited because of inadequate suppliesfrom the refineries. After processing, associated gas should yield about200,000 tons of LPG which will be marketed in the Trombay/Bombay area.Current plans are that about 50% of the total LPG productio7 will be marketedin cylinders and the other half in bulk, within the Bombay/Trombay area orwill be shipped by rail tankers to other areas where there is already ashortage.

(c) The Market for Petrochemical Feedstocks

8. A substantial part of the Indian petrochemical industry iSin the Trombay area, and could use the ethane fraction obtained frow :Tprocessing of the associated gas as feedstock for the production of StLuyIer,_and other petrochemicals. The Working Group has already carried out a stud-which shows that over the years it would be possible to absorb about iO0 tonsper day of petrochemical feedstock. However, these estimates are baess on a

ANNEX 24Page 4 of 5

market survey which is now somewhat outdated and should be revised in thelight of the studies currently being carried out by the Working Group andtheir consultants.

9. It is likely that the utilization of petrochemical feedstock willnot start before the early 1980's and therefore the value of these productshas not been taken into account in the financial and economic evaluations ofthe project as it was considered that any further project will have to beeconomically justified and financially viable.

D. Plans for the Utilization of Natural Gas and Natural Gas Liquids

10. As explained in Annex 9 dealing with the description of theprojects, it has now been decided that the primary separation of crude oiland gas will take place offshore. The main reason for this is that a two-phase flow pipeline (oil and gas in solution) would present some seriousoperational problems.

(i) Proposed Plans for the Utilization of Methane

11. The facilities required to use the methane fraction would includesubtransmission lines from the gas treating plant (or the shore terminal)to the main users and delivery stations at the users' plants. At presenttwo main users are being considered: FCI and possibily a power plant whichwill be used as a load balancing factor. With the continuous3supply of gasand the storage capacity of the line (estimated at about 2 Mm ) no storage isbeing considered.

12. The required conversion from liquid fuels will be carried out by theenterprises themselves with the assistance of the process designers and/orconsultants. It is planned that FCI and the power plant will be ready to takegas from mid-1978 onwards. The cost of conversion of existing facilities isestimated at US$15 million and the cost of the sub-transmission facilities atabout US$3 million.

(ii) Proposed Plans for the Utilization of LPG

13. LPG will be available at the refineries where facilities exist forhandling and storing. It is planned that these facilities will be expandedto include additional storage of about 5% of total annual production andcylinder filling facilities at the refinery and outside Bombay with acapacity of 80,000 t/y and 40,000 t/y respectively. In addition it isplanned to procure additional rail tank cars to supplement existing onesand ship LPG to other cities in India, principally Delhi.

ANNEX 24Page 5 of 5

14. The total cost of these facilities is estimated at about US$4.3 mil-lion of which about 70% will be for the purchase of about 1.2 million cylinders.

15. It is expected that the procurement and construction of the abovefacilities would be carried out by the staff of the two refineries which arequite experienced in this field.

IBRD - 2 7 74

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