L /!\J Document of the World Bank

$L /!\J Document of the World Bank$

AJ ~L3 ,y5 L_ /!\J Document of The World Bank

F'OROFFICIAL USE ONLY Public Disclosure Authorized

Report LNo.9305-lN

STAFF APPRAISAL REPORT Public Disclosure Authorized INDIA

GAS FLARING REDUCTION PROJECT

MAY 31, 1991 Public Disclosure Authorized Public Disclosure Authorized

Transport and Energy Operations Division Country Department IV Asia Region

This documenthas a restricteddistribution and may be usedby recipientsonly in the nerformanceof their official duties. Its contentsmay not etherwisebe disclosedwithout World Bank authorization. CURRENCY EQUIVALENTS (As of January 15, 1991) Currency units = Rupees (Rs) One Rupee = US$ 0.051 (approx.) One US Dollar = Rs 19.43

MEASURESAND EQUIVALENTS

I Million cubic meters of gas = 37 million cubic feet of gas = 6,*n500barrels of oil = 890 mt of oil = 1,940 mt of (Indian) coal

ABBREVIATIONSAND ACRONYMS

ADB - The Asian Development Bank bbl - barrels BcFm billion cubic meters BICP - Bureau of industrial Costs and Prices CIL - Coal india Ltd. ECA - export credit agencv Ell. - Encgineers India Ltd. GAIL - Gas Authority of India Ltd. GOI - Government of India cOR - gas/oil ratio HBJ - Hazira-Bijaipur-Jagdishpur gas pipeline ICB international competitive bidding IOC - Indian Oil Corporation Ltd. 1-EXIM - The Export-Import Bank of Japan kgoe kilograms of oil equivalent km - kilometer LICB - limited international competitive bidding LNG - liquefied natural gas LPG - liquefied petroleuim gas NGL - natural gas liquids MMCMD - million cubic meters per day MMCM - million cubic meters per year MOEF - Ministry of Environment and Forests mt - metric ton MW - megawatt OIL - Oil India Ltd. ONGC - Oil and Natural Gas Commission

FISCAL YEAR

April 1 - March 31 i F)OROFFICIAL USE ONLY

INDIA GAS FLARING REDUCTION PROJECT

Loan and Project Summary

Borrower. Oil and Natural Gas Commission (ONGC)

Guarantor India, acting by its President

Amount: US$450.0million equivalent

Terms: Repayment over 20 years, including five years of grace, at the Bank's standard variable interest rate. ONGC would bear the foreign exchange and interest rate risks.

Guarantee Fee: The Government of India (GOI) would charge a guarantee fee of 1% p.a. on the outstanding amount of the Bank loan.

Project Description: The objectives of the project are: (a) to eliminate the flaring of about 12 million cubic mnetersof associated gas per day (MMCMD) in the Bombay High oil field and improve the management of the Bombay High reservoir in order to arrest the decline of oil production and optimize the ultimate recovery of hydrocarbons; (b) to reduce energy shortages and contribute to greater efficiency of energy use in India's Westem Region; and (c) to promote a greater participation of private oil companies in India's oil and gas sector. The project is designed to recover about 25.3 MMCMD of additional gas from the Bombay High oilfield. The infrastructure facilities that will be constructed under the project will make it possible for ONGC to transport up to 29 MMCMD of additional gas supplies from offshore fields in the Western region to the Hazira gas terminal in the State of Gujarat and to Uran, near Bonmbay.The project, which has been designed consistent with environmentally sound principles, includes: * erection of two process platforms; * construction of three submarine pipelines: i.e. (i) a 28 inch pipeline from the southern sector of the Bombay High oilfield to the South Bassein gas field, (ii) a 42 inch ripeline from the South - Bassein gas field to the Hazira gas terminal, .. i (iii) a 30 inch pipeline from the southern sector of the Bombay sHiL.,oil field to the Heera oil field where it connects with the Heera - Uran trunkline; * the expansion of the existing gas terminal at Hazira to process the

This document has a restri, ted distribution and may be used by recipients only in the performance of their official duties. Its contents may not otherwise be disclosed without World Bank authorization, ii

additional gas supplies. This will nearly double the current capacityof the terminal. • the provisionof support for a reservoirstudy of the BombayHigh oilfield. The aim of this study is to optimizeoil and gas production from this, India'slargest oilfield,and reduce the chances for the recur- rence of excessivegas flaring. In parallel, the projectwill provide support for the trainingof ONGCs technicalstaff. * the provisionof support for the implementationof a packageof measures required to achieve proper reservoir mnanagementpractices in the BombayHigh oilfield. * the provisionof support also for ONGCs ongoing effortsto reduce the risk of environmnentaldamages from its offshoredrilling operations and to improve the overall safetyof theweoperations. ProjectBenefits: The investmentsunder the proposed projectwill increaseindigenous oil production by about 4 million tons per year and eliminatethe flaring of about 12 MMCMDof gas. The resulting increasein gas supplies will reduce imports of naphtha, which would be otherwiserequired for the manufacture of fertilizer,and of middle distillatesfor peak load power generation.This will save India about US$350million of foreignexchange annually (from 1995/96onwards) that would otherwisebe required for the import of these fuels. The total net present value of the investmentis approximatelyUS$1.3 billion. Project Risks: The projectfaces three major risks, i.e. (i) delays in the implementationof the project which would sharply reduce its viability,(ii) delays in the offtakeof the additional gas that willbe made availablethrough the project,and (iii) the possibilitythat ONGC will not be able to raise the foreignexchange required for the project. To minimizethe risk of implementationdelays, ONGC has agreed to award the constructionof major items, such as platforms and submarine pipelines,on the basis of a series of contractsunder single responsibility.In addition,ONGC has w-srzd closelywith the Bank to streamline its organizationand managementfor the implementaticnof projects. The bidding documents for all but two of the major componentsof the project will have been reviewed by the Bankbefore the loan becomes effective. The risk of delays in the offtake of the gas will be signiticantly reduced through the Govemment'sdecision to set up a specialmonitoring committeein the Departmentof Petroleumand Natural Gas that will review quarterly the progressin implementingthe proposed projectas well as the projectsthat will utilize the additional gas supplies. The quarterly reports of the monitoringcommittee will be submitted to the Bankfor review together with recommendationsin case of any slippage in projectimplementatioi.. The Bankwill have an opportunity to review the implementationof these recommendations.To minimizethe risk that difficultiesin the financingof the foreignexchange components delay the project,the Bankhas worked closely with ONGCand the Govemmentto ascertain the availabilityof financethrough export credit agenciesand suppliers' credits. isi

Estimed Costs: CostComptmts Foreign L=al Total -- US$ MiOO--

Proce platform, NQP 209.0 50.2 2592 Compresor, SHG 125.0 30.0 155.0 Proces platfDorm,SHC 230.0 55.2 285.2 Unepipe, SHGBPB 58.0 17.4 75.4 Co4dngand wrapping,SHG-BPB 15.7 6.1 21.8 Platformmodifiacdons 63.3 15.2 78.5 Unepipe,ICP-Heera 70.0 21.0 91.0 Laying coting a*ndwrapping, ICP-Heera 97.0 23.3 120.3 iUnepipe,BPB-Hazira 220.0 66.0 286.0 Laying, coahlngand wrapping, BPB-Hazira 129.3 31.0 160.3 Expmnson Haim p terminal 275.3 217.8 493.1 Resrvoir nanagement servic and equipment 67.4 61.7 129.1 Engineering andproet management 7.5 22.5 30.0 Studiesand trining 2.0 0.6 2.6 Environmental component 14.7 9.8 24.5

Base cost (991 prices) 1,5842 627.7 2,211.9 Physicl contingendes 158.4 62.8 2212 Pricecondngncndes 239.5 205.8 445.3

Total project coat 1,982.1 896.3 2,878.4 lnterestduring construction 204.1 101.8 305.9

Total FinancingRequired 21862 996.1 3,184.3

Note:Base cost indude custoas duties od US$3744 il4ion equivalcnt. ONGCcharges interest during construction to opetios.

Financing Plan: Srav of Finaer L1x Forei8p Totl Percent

-- US$ ilo

World Bank 450.0 450.0 14.2 Asian DevelopmentBank - 300.0 300.0 9.4 Export-ImportBank of Japan' 350.0 350.0 11.0 Export/suppliercredits - 745.6 745.6 23.4 ONGC 998.1 340.6 1388.7 42.0

Total 998.1 2186.2 3184.3 100.0

GOf'srequest for financngis currenlyunder study by J-EXIM

Estimated Disbursements: IBRD Fisa Year Year7 Yer 2 Year3 Yer 4 YearrS FY92 FY93 FY94 FY95 FY96

-- -US$ milon Annual 111.1 139.4 135.0 61.0 3.5 Cumulative 111.1 250.5 385.5 4465 450.0

Economic Rate of Retumr 30% iNDIA GAS FLARING REPUCTICN4 PROJECT

Table of Contents

Eage No.

1.THE ENERGY SECTOR...... 1

Role of Energy in the Indian Economy ...... 1 India's Rapidly Growing Energy Demand ...... 1 High Energy Intensity ...... 2 Energy Conservation ...... 4 Constraints to Expanding Indigenous Energy Production ...... 5 Energy Prospects for the 1990s ...... 7 The Govemment's Energy Strategy ...... 7

11.THE NATURAL GAS MARKET...... 9

Developmnentof India's Gas Resources ...... 9 Gas Reserves ...... 9 Reasons Behind the Extensive Gas Flaring ...... 10 Gas Production Prospects ...... 14 Gas Utilization...... 15 Gas Pricing ...... 16 The Role of the Bank...... 19

III. THE OIL AND NATURAL GAS COMMISSION...... 20

Introduction ...... 20 Organization and Management ...... 20 Institutional J-3ues ...... 21 Accounting, Management Information and Auditing ...... 22 Financial Performance ...... 22 Meeting ONGC's Foreign Exchange Requirements ...... 23 ONGC's Financial Relationship with the Government ...... 25 ONGC's Operational Performance ...... 25 Investment Program ...... 26 Financial Prospects ...... 26

This report was prepared by Messrs. P. Pollak (Senior Economist), D. Fallen-Bailey (Consultant), G. Dolenc (Senior Country Officer), M. Flassan (Consultant), L. Kumar (Consultant), M. Levitsky (Econo- mist), H. Morsli (Senior Petroleum Engineer), C. Peacock (Consultant), S. Shaw (Environmental Specialist), J. Silcock (Consultant), H. £ hober (Consultant), T. Storm van Leeuwen (Senior Financial Analyst), K. Stichenwirth (Consultant) and Mrs. N. Parshad (Economist). Miss J. Basin assisted in the economic and ;inancial analysis. Mr. D. Bat, m-an(Senior Mining Engineer) prepared the illustrations. Mmes. M. Chatterji and K. Cherrie typ . various drafts of the report. The report has been reviewed by Ms. A. Mashayekhi and Mr. F. Najmabadi. The report has been endorsed by Mr. H. Vergin, Director (India Department) and Mr. J. F. Bauer, Division Chief (Energy and Transport Division, India Department). ii

Financing Requirements ...... 27

IV.THE PROJECT...... 29

Background...... 29 ProjectObjectives ...... 30 Project Description ...... 30 Implementation ...... 31 Status of Project Preparation ...... 32 Environmental and Safety Issues ...... 32 Project Cost ...... 34 Financing Plan ...... 35 Procurement and Disbursemnents...... 36

V. FINANCIAL AND ECONOMIC ANALYSIS...... 39

Project Benefits...... 39 Project Financial Analysis ...... 39 Project Economic Analysis ...... 40 Project Risks...... 41

VI. AGREEMENTSAND RECOMMENDATION...... 42

ANNEXES

1.1 Energy Balances, 1980-81to I 388-89...... 45 2.1 Gas Production lrojiections...... 46 2.2 Gas Flaring in Major Gas Producing Regions...... 48 2.3 Projected Gas Utilization ...... 49 2.4 Gas Prices ...... 53 3.1 Organization Chart of the Oil and Natural Gas Commissice ...... 54 3.2 Summary of ONGC's Accounting Practices ...... 55 3.3 ONGC Sales and Revenues, 1981 to 1990...... 57 3.4 ONGC Income Statements, 1981 to 1990...... 58 3.5 ONGC Sources and Applications of Funds, 1981 to 1990...... 59 3.6 ONGC Balance Sheets, 1981 to 1990...... 60 3.7 Performance Parameters ...... 61 3.8 ONGC's Investment Program, 1991 to 1995...... 63 3.9 ONGC Rcvenue 7rojections, 1990 to 1995.64 3.10 ONGC Income Staternents, 1990 to 1995.65 3.11 ONGC Sources and Application of Funds, 1990 to 1995.66 3.12 ONGC Balance Sheets, 1990 to 1995.67 3.13 Assumptions to the Financial Projections ...... 68 4.1 Layout Optimization of the Pipelines to be Constructed ...... 70 4.2 Detailed Project Description ...... 74 4.3 Project Management Organisation ...... 82 4.4 Project Implemcrnt3tion Schedule ...... 83 4.5 Environmental Aspects ...... 86 4.6 Detailed Project Cost ...... 89 4.7 Project Financing Plan ...... 90 4.8 EstimnatedSchedule of Disbursements ...... 92 iii Page No. 5.1 Assumptions Underlying the Project Financial Analysis ...... 93 5.2 P'rojectFinancial Analysis ...... 94 5.3 Assumptions Underlying the Project Economic Analysis ...... 95 5.4 Project Economic Analysis...... 98 6.1 Project File ...... 99 6.2 Supervision Plan ...... , 100

Map: No. 22892 INDIA

G;AS;FLAP!NG RMEUCTION PROJECI

STAFF AHPRAISAL, REIORtI

1. 1IHE.ENER(;Y SECTI'OR

Role of Energy in the Indian Economy 1.01 Energy remains critical for the Government's efforts to accelerate evonomic giowth. T'he Government is aware of this, and continues to invest about one-third of public resources in the development of indigenous energy resources. Tl.e acceleration of economic growth during the 1980s has strainexd the capacity of the energy sector to meet the surge in the demand for energy and, in spite of massive investments in the expansionof oil, gas, coal and power sectors, energy demand continues to outstrip supply. Thus, in the years ahead, India will again have to contendwith the economic implications of sharply rising oil imports.

1.02 This puts the Government in a difficult position. It is under pressure to improve the balance of payments, reduce the budget deficit and provide a modicum of economic growth in order to avoid losing whatever progress has been made in the reduction of poverty during the 1980s.Und',r these circuinstances, an increase of oil imports will most likely necessitate a reduction in the imports of capital goods, while a cut in public expenditureswill slow the development of indigenous energy resources leading to a further increase of oil imports in later years. This leaves the Government with few options. Assuming the Government continues to pursue its objective of accelerating growth in order to reduce poverty and provide employment for a rapidly growing labor force, it will need to ensur- that energy is usedefficiently, thus eliminating the demand caused by wasteful energy use. It will also need to ensure that investments in expandingenergy production are guided by efficiency considcrations. This coulJ be achieved with a shift towards fewer controls and greater reNianceon market forces.

1.03 Managing the transitioni tow.;-ds a more open, market-oriented energy sector will bxea formidable task, sinceit will be carried out in an environment of increasingiv severe budget and balance of payments constraints. The proposed project is a step in this direction. Its objectives are to eliminiate the wasteful flaring of gas, improve the reservoir management of the Bombay lHighoilfield, reduce the need for oil imports and help meet the energy needs in India's rapidly growing western region. While the proposed project supports change towards a more oren energy sector, it is only the beginning ot a difficult transition. The following paragraphs highlight the main issues and constramintswhich the Government needs to address in order to raise the efficiency of energy use and indigenious energy prOduction.

India's Rapidly Growing Energy Demand 1.04 The acceleration of economic growth during the 1980s has led to a sharp increase in the demand for commercial energy. While the economy grew at an average rate of 4.5%cbetweeni 1979/80 ar,d 1989/90, commercial energy demand grew at a rate of 6%. Within commercial energy, the demand for oil products and electric power showed the fastest growth. Their demand grew at 7% and 9.57, respectively.

1.05 In spite of the iast growth of energy demar.d, India's overall level of energy consumnptioniis low compared to that of other developing countries. While IndianE consume about 2(X)kilograms ot oil equivalent (kgoe) per capita, Chinese consume 540 kgoe and Brazilians 84()kgoe. Althouigh energy consumption is relatively low in absolute terms, the Govmrnmentis concerned ahout it, rapid grovth and the relatively low efficiency with which energy is used.l1o curb the growth of denmuldelrr a!id imi -2 -

prove the efficiency of energy use, the Government continues to pursue a i wo-pronged approach. To slow the growth of power consumption and the use of imported oil products, tho Government rel.es primarily on rationing. In parallel, the Government has introduceo several energy coi'servation' programs to eliminiate the wasteful use of energy. Overall, the strategy has not been very efiective. Two factors art primari!y responsible for that: the reletively high energy intensity of major sectors of the Indian economy and the ineffectiveness of energy conservation; rograms.

h-igh tnergy Intensity 1.(K Perhaps the most important factors behind the fast growth of energy consumption are the relatively high energy intensity of India's industrial sector and the rapidly growing energy intensity of the agrictiltural sector.

1.07 INDXUs'RY.While the energy intensity of the industrial sector has deciined by 8% during the 1980s, mostly as a result of the slower growth of energy-intensive industries, such as steel, aluminum and fertilizer, and the phasinig out of somneenergy-intensive technologies in the manufacture of cement and fertilizer, the industrial sector continues to account for more than half of India's commercial energy consumption, and, in terms of its energy intensity, India's industrial sector ranks near the top among dc'veloping countries and well above the average among industrial countries. Several factors account for the high energy intensity and r..atively inefficient use of energy in the industrial sector:

(a) Since Independence, India has pursued an industrial development strategy whose main objective was to reduce India's dependence on imports. Consequently, large investments were made in the 1960sand 1970sin basic energy intensive industries such as steel, cement, aluminum, fertilizers, heavy chemicals, refineries, etc. All of these industries are highly energy-intensive and absorb a considerable share of indigenous energy production.

(b) Many of these industries still use technologies and equipment which were developed at a time when energy was cheap. By toc.iy's standards, most of the machinery, equipment and infrastructure is outdated and energy-inefficient. To achieve self-sufficiency, the Govern- merit has encouraged the design of indigenous technologies and development ef a capital goods industry. Protected from international and internal competition through high import tar,ffs and extensive regulat ry controls, this inuu,try has few incentives to provide Indian industrial enterprises with energy efficient capital (oods.

(c) EInergyefficiency improvements require replacement of capital stock, process modifications, retrofits and technology changes, all of which require large new investments. The scarcity of capital ar,d the high cost of importing new technologies in the face of a worsening balance of payments situation continue to put the brakes on the adoption of energy efficient technologies and the shift towards lessenergy-intensive industries. In addition, a growing domestic demand for manufactured products makes expansions of capacity more financially attractive thani cost cutting through efficiency improvements.

(d) Another disincentive for improving energy efficiency has its roots in the widespread use of 'costplus pricing' in India. This is still the most widely used approach by the Government for setting prices of goods and services that fall under an administered price regime. While the number of goods and services under administered price regimes has declined gradually in recent years, they are now used mainly to price the goods and services of pubil. sector enterprises that face little intemal or external competition. To provide some incentives to these enterprises to raise their overall efficiency, the Government has, over the years, intro- duced pricing formulas that contain 'rewards' and 'penalties' for achievement or non- achievement of agreed efficiency targets. This has encouraged some reduction in the waste- -3 -

ful use of energv. However, the effectiveness of these incentives has been blunted by the Government's willingness to provide financial support to 'sick' industries in order to prevent the closure of large enterprises aiid the loss of jobs. Price incentives for using energy efficiently are also undermined by the fact that protective import tariffs raise the pt ixes of final products and thus lower the relative cost of energy. Thus, in spite of the fact that many energy prices laced hy industrial conaumers are more or less in line with ec:onomic prices (the price of rnost petroleum products used by the industrial sector are at or above border prices and electricity prices faced by industry are also close to the estimated long run marginal cost . they do not result in efficiency improvements.

(e) Another objective of India's economic development strategy, which contributed to the relatively high eneigy intensity of the economy, was the decision to ensure that all parts of the country shat equitably in the benefits of developmenrt.To achieve this objective, the Government ens,red, thtough its public investnents that economic activities and in particular, industries that provided employrnent were set up fairly evenly spread across the country. To supply these industries with energy an extensive energy supply system based on thermal power generation using coal, India's most abundant commereial energy resource, had to be set up. In thermnalpower generation only a small share (between 25% -40%) of the fuel used (coal, fuel oil, natural gas, etc.) is convertpd into electric energy. The remainder is lost in the conversion process. These 'conversion losses' together with transmission and distribution losses contribute significantly to the energy intensity of the economy.

(f) The Govemment's location policy and the resulting need for an energy supply system based on coal fired thermal power has contributed to the growth in the demand for middle distillates. Most of the coal deposits are in the eastem and central parts of India. About 70% of all coal is shipped by rail mostly to power and industrial plants that are spread fairly evenly across the country. The surge in energy demand during the 1980shas strained the capacity of the railways to move coal. This has contributed to disruptions in coal supply, which in turn has encouraged investrnents in 'captive' power generation using primnarilymiddle distillates. Since the railways have been replacing steam locomotives with diesel driven electric locomotives even though steam locomotives were more cc st efficient -- their demand for oil products has increased sharply.

1.08 TRANSIPORT.The steep increase in energy consumption during the 1980sis partly due to the growing demand for energy in the transport sector. This s-ctor accounts for about one-fourth of total energy consumnptionin India. While its overall energy intcensityhas declined with the shift from rail to road transport (mainly because of under-investment in the railway system), its need for oil products, in particular diesel oil, has increased dramnatically.The current designs of indigenously manufactured trucks and cars are highly energy inefficient and the relatively high average age of the truck fleet (more than 40% of the truck fleet is 12 years old or older) contribute to the high energy intensity of transport.

1.09 AGRICULTURE.Of all major sectors of the economy, agriculture shows the steepest increase in energy intensity, mainly for two reasons: (a) to increase productivity and (b) provide a butfer against droughts and floods resulting from the unpredictable behavior of monsoons. Expansion of the use of high- yielding wheat and rice varieties have increased the demand for (energy-intensive) fertilizer and irriga- tion. Subsidized electricity has led to a sharp increase in the number of electric pumpsets. Together with increased mechanization they have contributed to the rapid growth in the demand for electricity and petroleum products in the agriculture sector. To protect agriculture against the vagaries of the monsoo-, the Government has encouraged the expansion of irrigated areas. As a result of these efforts, it takes now twice the amount of energy to produce an average unit of agricultural output (for example, a ton of wheat) than it did fifteen years ago. 4-

1.19) Si II I:c('M I RADrIlONAI. It)C:OMMIKtlA!. I t At the tine of Independence, Ir.dias iiajor source of energy was biomass, whichlaccounted for more than 85% of all energy used. Currently, biomass, mostly fuelwoodi, crop r c'ueand animal wastes, accounts for less than 40% of total eaergy consumption. Several factorsare responsible for the sh,iftto cornmercial energy: the growth of indcistrial production, urban,wation, thie expansion of rural electrification and price subsidies for electri( power andl kr -osine. The price stlhsidics arte rooted ifntit (Governrment's concern about the r ural poor and t?heneed to slow the procc, (if (idton-;tation In part, the sihifta way fromatraditional fuels is the result of the development proct- ; in part it is tit resilt of the Government's pricing policies for power ar.d oil products. While it is doobtful wihther these pril ing pXolicieSiniC1dee achit ve their intended objectives, studies of energy use in the rmol wtor pA)Inttito ihighly wasteful use of electricity anL a steep tise in the deimind forniddile distillatti ' ri injoand diesl.l oill).There are also no sigins tihat the rapid pace of deforestation has slowed down .

Energy Conservation 1.11 l'o eliminate the wasteful use of energy continues to be a major objective of the Government's energy strategy. Stidies carried out by the Government cstiinate that, through better energy demnandmnanagement andS conservation, the industrial sector could save 25% and the agricultural sctor 30t,t of their cuirretitenergy demands. Howcver, up to now the Government's energy conservation efforts have been largely ineffective A discussion of the causes of the high energy intensity of manjor sctors of the cc onowiv poinits to the linderlvingreasons.

1.12 lo enscurethat energy is use'l efficiently wouli require fundamental changes in the current policy tr,men.v\ork that guides the use of energy:

(a [Il-iirgy uisers need to have a clear economic and financial incentive to use energy effliently. !his woul(d require that the C;overnmrientno longer deterna.ies 'administered' prices on the ha.&,ls 1flistorical costs ('cost .plus pricing'). but allows competitive markets ':e'sot prices. I h .,w tlId nmke it ti fficuilt to pass on incre-se!; ii, the cc3t of energy to f aal cornsumers thElmrbu orji increases.

oinede' to bN effective a po!licv change wouIld require thiat producers face internal or esxtesrnali lmrtOtiiio01 thus eliminating the opportunity of absorbing increases in tihe cost of oncts throuigh monopoflistic profits. It would also require that the Government no longer AlhSerbsLthe 'osses of enterprises to safeguard employmenit.

O.) Eln'rgy users would need to he able to use capital goods embodying energy-fficient designs In order to be alble to compeste, Indian entrepren1eurs would netiedto bh able to pur chasLeWuionnesticallv or throtugh impoxrts) the most energy-efficient capital goodis.

hi1l f Inal V, thle a,Ilous torms of energy (fuels and electric power) need to be priced in liinewith ni,kCt rincples. 'his 5 would require that the Government replaces price subsidy programs, intended to raive the standard of living of the poor, with other forms of support.

1.13 ITple)lCmenItationof theoe changes ;would bring into question the fundamental values which have guided Indian policvmakers since Independence. The political and financial costs of such drastic changes ws.)uld h ennormotisand cotuld not alone be justified with the gains in energy conservation. Thus, until thesc changes can be implemernted the Government will continue to rely primarily on developing its indigeniotis energv resources1 to the fullest extent, in order to minimize imports, and an energy ronserva- tion policv which 'ill ! etc! primiilv u. fn ad -hoc n trve\t.ntrt:ns aimed at curbing the blatantly wasteful uSe 01 itlI' - -

Constraints to Expanding Indigenous Energy Production 1.14 As noted in the section above, efforts to manage energy demand have been largely ineffective to late. Even if implemented successfully in th( future, energy conservation will not fully substitute for the need to expand indigenous energy production to close the widening energy gap. In order to assess the potential of further developing indigenous resources it is important to first take stock of the energy resource base of the country and the constraints to further increases of production in the main energy subsectors.

1.15 ENtcy RESOURCEBASE. Considering the size of its economy and its rapidly growing popula- tion, India is relatively modestly endowed with energy resources. In spite of allocating almost a third of its public investment resources to the development of these resources, India depends on oil imports to meet its domestic energy needs. India does, however, have a wide range of commercial energy resources including oil, natural gas, coal, hydro-electric potential and uranium. Unfortunately their relative size does not match the structure of energy demand (Figure 1). India's energy resource base is dominated by coal. Total coal and lignite reserves are estimated at more than 170 billion tons. Although these reserves are mostlyof low quality, they are India's most important commercialenergy resource.India has also a sizeablepotential for the generation of hydro-electricenergy, estimated at 100,000MW, of which up to now only about 13,000MW have been developed.Environmental concems, the high cost of, and growing resistanceto, the resettlementof a large number of people, disputes about water rights and financial constraintsmake hydro-electricpower projectsincreasingly unattractive. Thus, the power sector prefersto invest in coal and gas-basedthermal power generation.Considering the size of its economy India is poorly endowed with hydrocarbon resources. Proven and probable reserves amount to about 840 million tons. At projectedconsumption levels these reserveswill last for about two decades. Th'is, unlessexplora- tion efforts succeed in raising the level of reserves, India will need to meet its demand for petroleum products increasingly through imports. Natural gas may provide some respite in the short run. Natural gas reserves, which are estimated at 961 Bcrn,would permit India to significantly reduce imports of oil products. Up to now this effort has been hampered by conflicting policies and insufficient financial resources. Finally, India also has modest reserves of uranium, which would be sufficient to support a nuclear power program of about 8000MW.

1.'6 OILAND GAs. Oil production has increaseddramatically over the past ten years, mainlyas a result of the discoveryof BombayHigh and its satellitefields during the esily .)70s. These fields now account for about 65%of indigenous production.Prior to the discoveryof Bombayhigh, the oilfieldsof

Figure 1 Reserves,Production and Consumption of CommercialEnergy in India, 1990 Milluin tonsof od equivalent

oil Hydr. Hydro Hydro

1~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~ Ga.~~~~~~~a ,,I'

Reserves (83574) Production (157) Consumption (114)

%urm. Tat&Enwa R_dach Instituteand World BDnkStaIf stimate -6 -

Assamand Gujarat were the only indigenous sourcesof oil supply. Developmentof BombayHigh drasti- cally reduced India's dependenceon oil imports.However, in 1984/85oil output from the BombayHigh oilfieldreached a plateau. Further production increaseswill require the use of costly enhancedoil recovery technologyas well as substantial investmentsfor the development of the smallersatellite fields. The Govemment'sofficial projections of crude oil production (51 million tons by 1995/96and 67 milliontons by 2000/01)indicate that ONGC expectsto maintaincurrent levels of self-sufficiencythrough heavy investmentsin enhancedoil recovery,the acceleratedexploitation of undevelopedfields, large investments in oil exploration,and substitutionof a significantshare of domesticoil products demrandwith natural gas. The Bank'sstaff is less optimistic.Based on a field-by-fieldreview of oil reserves,the Bank's staffconcluded that indigenousoil production would reach a peak of 42 milliontons in 1996/97and then graduallydecline to about 38 million tons in the year 2000;this projectionis based on the assumption that India's oil companieswill face no difficultiesin getting the investment resources(including foreign exchange) they would need and that neither company makes any significant oil discoveries. In case exploration efforts result in a major oil discovery during the next 2-3 years, production would continue along the projected plateau postponing the inevitable decline of oil output. The Government's projections of indigenous oil production assume a significant increase in the pace of developing existing in-place reserves as well as large additional discoveries in the next few years. Both would require large capital. Considering the increasingly tight constraints on investment resources, particularly in foreign exchange, that India's oil companies will most likely face in the years ahead, the Bank's staff recommends that the Government implement policies that encourage the efficient use of energy and substitution of oil products with other indigenous energy resources. The proposed project, which would provide the infrastructure for the use of gas that is currently flared, is in line with this recommendation.

1.17 COAL.Because of its abundance, coal remains the mainstay of the Govemment's energy strategy. To meet the growing demand for coal, particularly from the power sector, the Government nationalized the coal industry in the early 1970s.This provided the industry with access to public investment resources, and allowed Coal India (CIL) to meet the Government's ambitious coal production targets by channelling most of its investments into open-cast mining. Although coal that can be mined in open- cast mines in India is of low quality, it has substantially lower production costs than that the higher quality coal mined in underground mines. Coal India's strategy led not only to a decline in the average quality of its coal output, but also to a neglect of its labor-intensive underground mines. Freqvent real increases in the wages of miners, poor labor discipline and low labor productivity have turned most underground mines into loss-making operations. Hamstrung between the need to meet production targets and political pressure not to retrench excess labor, CIL's financial performance became dependent on the magnitude and timing of coal price increases and the allocation of pub!ic resources. In all but four years CIL closed its accounts with a loss.

1.18 Budgetary constraints will force the Government to sharply reduce its allocation of funds to CIL, and inflationary pressures will make it more difficult to approve coal price increases. The Govem- ment will have little choice but to grant CIL the autonomy it needs to operate as a commnercialcoal company, and to create a poli-y environment that would attract private investment into an industry that is so vital for the growth of the Indian economy.

1.19 ELECrRICPOWER. With the emphasis on self sufficiency and a policy of balanced regional growth, the electric power sector plays a key role in meeting the energy needs of the Indian economy. Not only is electricity the prime input into industries dispersed all over the country, a large effort to expand rural electrification to substitute for oil products has further increased the demand for electric power. Total installed capacity is currently 62,000megawatts (MW). Additions to capacity have been made at an average growth rate of 10 % per annum, but demand for electricity has continued to outstrip supply by 10-12%. Low capacity utilization, transmission losses, institutional bottlenecks and an inefficient pricing structure which results in inadequate returns and disincentives to conservation have contributed to financial constraints and a widening power gap. Power shortages have adverse implications for the -7-

growth of the economy rendering production capacities idle and also 'or ring power users to resort to investments in captive power plants which increase the demand for oil products. In view of tl.e current budgetary constraints, it is unlikely that the gap between power demand and supply will be reduced from the current level of 12-15%.More importantly, the deficit between 'peaking demand' and generating capacity will widen significantly. The Government has essentially two options. -,,~ and hydro-electric or thermal power generating capacity.

1.20 Hy'Vo-ELECFRICPOWER. India has one of the largest untapped hydroelectric generating resources in the world. However, development of this potential, which is estimated at close to 100,000 MW, faces considerable environmental and tinancial constraints. The long gestation periods, high capital costs and implementation delays have deterred investment in hydro power and the share of hydro power in the total currently installed capacity is only 25%. While the Govemment has continued to emphasize the need for developing more hydro electric -. ower, especially in view of the severe shortages in peaking capacity, budgetary and financial constraints have encouraged a shift away from hydro electric power to shorter gestation, lower capital cost, coal-based thermal power generation.

1.21 TFERMALPOWER. Most of the existing thermnalpower generation capacity is based on coal. In light of the vast resources of coal, the shorter construction period for thermal power stations than that of hydro-electric plants, and the locational flexibility of thermal plants wherever access and water facilities are sufficient, the Govemment has increasingly invested in coal based thermal power. This investment has not been without cost. High conversion losses, high costs of transporting low quality coals over long distances, high transmission losses, the firing up and idling of boilers to meet peak demand using large quantities of expensive fuel oil, and growing environmental costs of burning high ash coal are raising the cost of coal-based power generation and reducing its attractiveness as the premier option t3 meet India's rapidly growing energy demand. Gas- based combined cycle plants, which have lower energy conversion losses and shorter gestation p2riods than even coal plants, have been limited to areas near gas fields.

Energy Prospects for the 1990s 1.22 Table 1.1 summarizes the prospects for the growth of energy demand and supplies during the 1990s.Oil production will be constrained by the growing scarcity of foreign exchange and the need to shut-in an increasing number of oil wells with a high gas/oil ratios. The Bank's staff doubts that India's oil companies will be able to attain, under these circumstances, the Government's production target of 67 million tons by the end of the decade. In addition, the financial constraints and environmental pressures confronting the power and coal subsectors will most likely sharply reduce the expected growth of their respective outputs.

The Government's Energy Strategy 1.23 With the widening gap between energy demand and supply, and tight resource constraints, the Government needs to rethink its strategy of relying wholly on increasing indigenous supply. In the past, the energy sector has absorbed as much as 30% of total Plan outlays. It is unlikely that the Govern- ment can afford to increase this share. On the other hand, increasing oil imports will place a heavy burden on the balance of payments. Under these circumstances the Government is faced with a limited range of options to bridge the widening gap between energy demand and indigenous energy supplies.

1.24 ENERGYCONSERVArON. The first option is to contain the growth of energy demand. This can only be done through a concerted effort at energy conservation, reducing the energy consumption of the highly energy intensive industrial, agricultural and transport sectors. While the Government is now dedicating more resources to energy conservation efforts, the sheer magnitude of the problem and the structural changes required indicate that it will be some time before any impact on demand will be felt, -8 -

Table 1.1 Commercial Energy Supplies and Their Uses in India, 1970 to 2000 Miliwn tons of oil cquivlent

Enrrgy Resources/ Sectors 1970 l980 1990 2000

Energy produc.ion 46 74 147 223 (il 7 12 32 39 Gas 1 2 12 40 C oal 36 56 98 135 Electricity 2 4 5 9

Net imports 12 17 28 66 Oil 12 16 26 60 Coal 0 1 2 6

Energy Supply 58 91 175 289 Conversion and distribution losses 13 20 48 64 Stock changes 1 1 2 2

Energy use 44 70 125 223 Industry 22 40 65 104 Transport 12 17 29 52 Agriculture 1 2 5 14 Residential and commercial 5 5 12 24 Non-energy uses 4 6 14 29

S'LurceTata Energy ResearchInstitute, World Banks^ff projectons

1.25 COMMEIRC'JAI.ORIEN71 ATION. In addition to using energy efficiently, there is a pressing need to improve the efficiency of the existing energy supply infrastructure and the p;ublicsector companies in the energy sector. Ihe Government needs to implement drastic institutional and pricing reforms to allow the oil, gas, coal and power industries to operate along commercial lines. The resulting increase of internally generated resomrceswould make these industries less dependent on budgetary resources.

1.26 INCEASEDINVOVI.VI .MENT OF TIHE PRIVATE SECTOR. In view of the tight budget constraints, the Government is now looking towards the private sector to mobilize additional resources, particularly in oil exploration and power generation. In oil exploration, the Government is planning to again invite (fourth round) bids trom international oil companies and the Indian private sector for exploration and development of oil and gas fields in India. The Government is also initiating policies to attract private sector participation in the power sector, particularly in coal and gas based thermal generation.

1.27 ACci.EFRATIEDDlviELoPMFKI OF INDIGENous ENERGY REsoukcEs. The overriding objectiveof the Government's energy strategy will remain the full development of India's indigenous energy resources, in particular its natural gas resources to meet the increasing shortage of energy supplies and reduce the need for oil imports. The current project aims precisely at providing the requisite infrastructure to reduce wasteful flaring of associated gas and optimal utilization of both associated and free gas resources in the country.

11.THE NATURAL GAS MARKET

2.01 Although India's reserves of natural gas are small compared to its reserves of coal and its hydroelectric potential, natural gas is playing an increasingly important role: gas takes some of thc pressure of the demand for oil pioducts (fuel oil, naphtha and kerosine); it also reduces the demand for -9 - coal, particularly in India's Westem Region, which is farthest away from the main coal producing areas -n India; it helps to reduce India's widening energy gap at a time when oil and coal production fall short of production targets; finally, its use contributes significantly to the reduction of environrmental pollution, which is particularly severe in t' e highly industrialized Western region. This chapter provides an overview of India's 'associated' and 'free' gas resources, the likely demand for gas and the steps the Govemn- ment has taken to eliminate the flaring of gas and ensure that available gas supplies are used efficiently (e.g. gas utilization and gas pricing policies).

Development of India's Gas Resoutrces 2.02 Natural gas has been produced in India for many years jointly with oil in Assam. However, apart from a small amount used for internal consumption by the oil company (Oil India Ltd.), most of this gas was flared. In the rnid-1960s ONGC began to explore systematically for oil all over India. Although the main thrust of ONGC's exploration efforts was directed at finding oil, these efforts led to the discovery of several free gas fields: the Cambay Basin (in the State of Gujarat) in 1960, the giant Bombay High oil field (about 160 kilometers north-west of Bombay) in 1974, the Krishna-Godavari basin (in Andra Pradesh) in 1985 followed by the discovery of oil and gas in the offshore Ravva field in 1987;the Cauvery Basin (in the State of Tamil Nadu) in 1989. When oil discoveries were put on production, the 'associated' or 'solution' gas, which is unavoidably produced with the oil, was for the most part flared. Although the main thrust of ONGC's exploration efforts was directed at finding oil, these efforts led to the discovery of several free gas fields.

Gas Reserves 2.03 Gas is found in India mainly in four widely separated regions, the Northeast (Assam, Tripura), the eastem region (Krishna-Godavari), the south-east (Cauvery), and the western region (Bom- bay off-shore, Cambay and Rajastan). India's gas reserves are estimated at 961 billion cubic neters (Bcm). They consist of 320 Bcm of associated and solution gas and 641 Bcm of free gas. More than 50% of these reserves are located in the Bombay Offshore area. Up to now about 150 Bcm of gas have been produced, a large part of which has been flared. This quantity represents about 13%of the original recoverable gas reserves, whereas 32% of the original recoverable reserves of oil have been produced.

Table 2.1 ONGC's Gas Reserves, 1990 Billioncubic etrs

Area Sodution Gs FrwGas Tota

Bombay offshore 64.5 391.6 456.1 Kutch offshore 0.0 0.3 0.3 Krishna-Godavari 2.6 18.3 20.9 C^ ery 3.9 2.5 63 1 wr Assamn 21.6 3.2 24.8 i-Arakan Fold Belt 0.1 9.6 9.8 Carnbay 37.1 55.5 92.6 Rajasthan 0.0 1.0 1.0 Andaman and Nicobar Islands 0.0 0.1 0.1

Total India 129.8 482.1 611.9

SourceONCC -10-

2.04 REGIONALDlsrTIBunON OF GASRESERVES. Since gas contains much less energy than oil (on a volure basis), it is expensive to transport; gas is also difficult to store; and the need to maintain a ctertain pressure in the pipeline system requires close coordination between gas producers and users. In the gas industry, this close link between producer, gas transmission and distribution company and users, frequently referred to as the 'gas chain', res .nbles the relationship between power generating companies, transmission and distribution companies and the users of electricity. Since about 90% of ONGC's gas reserves (Table 2.1) are located close to the highly industrialized western and northwestern regions, whose energy needs are met primarily through coal, there is a strong incentive to develop these gas resources.

2.05 The situation is somewhat different in the north-eastern region, which has the second largest reserves. There are two separate gas producing areas in this region: the oilfields of Assam and Arunachal Pradesh and the free gas fields in the land-locked state of Tripura. Assam has oil and coal resources that far exceed its own requirements, and companies find it difficult to mnarketall the associated gas. Unlike in the western region, oil companies in Assam have little incentive to develop free gas reserves. Although gas is the major source of commercial energy in the State of Tripura, the local demand is too small and major gas markets are too distant to justify at present the development of the gas resources that have been discovered there.

2.06 1he lack of remunerative gas markets has been the major disincentive for oil companies to explore more aggressively for gas. There is widespread agreement among geologists that future discoveries will most likely consist of gas fields. A rapi -ly growing demand for oil and balance of payments consideration will remain the driving force behind ONGCs and OIL's all-out efforts to explore for oil. The relatively low prices producers receive for gas encourage this. Gas goes a long way towards replacing oil products and coal. In setting producer prices for oil and gas, the Government needs to carefully weigh the cost of encouraging oil exploration in areas that would yield high cost oil against the benefits of exploring for low-cost gas resources.

Reasons Behind the Extensive Gas Flaring 2.07 India is not taking full advantage of gas resources that are currently available. Current gas reserves could sustain a production of 90 million cubic meters per day. Yet, in 1990, India produced only slightly more than half of that (53.2 MMCMD).Only two-thirds of the gas produced was actually used one-third of the total gas production was flared (Annex 2.2).The substantial gas flaring has been caused by a number of factors, explained in the following paragraphs. These factors fall into two broad categories: technical factors which have their roots in decisions related to the development of oilfields and a number of institutional factors that have slowed the development of gas markets in India.

2.08 GAS FLARINCIN Tn E BOMBAYHIGH OILFIELD. The reason for the sudden increase in flaring gas during the 1980s lies principally in the production history of the Bombay High oilfield. The reasons are various, some connected with the nature of the oil reservoir rock and somneattributable to the production regime of the field.

2.09 The reservoir rock is a fossil reef limestone which contains highly permeable layers interca- lated in a much less permeable matrix. Originally all the reservoir rock layers were saturated with the same fluids, but in the course of oil production pressure differentials developed within the reservoir and the more permeable zones acted as conduits to bring gas and water towards the producing wells, bypass- ing the oil in the less permeable sections of the reservoir. This problem was compounded by an overall reservoir pressure drop resulting from an increase of oil production rates not being compensated adequately by injection of water into the reservoir below the oil/water contact, as envisaged in the original production plan. The water injection plan was initiated too late and on an inadequate scale. - 11 -

2.10 The problem was further compounded by well drilling and completion techniques employed in the wells. These permitted the presence of channels and voids in the current layer surrounding the oil well casing pipe, so permitting the vertical migration of fluids up and down behind the casing. Since fluid flow in an oil reservoir is influenced by pressure differentials in the reservoir rather than by gravity, this permitted the most mobile fluids, gas and to a lesser extent water, to be drawn towards the producing section of the well. Thus, some of the free gas from the gas cap has also been produced with the oil.

2.11 The net result of all these effects has been a dramatic rise in the gas/oil ratio from the producing oil wells. The natural solution gas volume in the reservoir was 90 cubic meters of gas to one cubic meter of oil (GOR 90 v/v). In the north half of the field, at the start of water injection the GOR was 175 v/v, and by April 1990 it had risen to 520 v/v. In the southem part of the field the producing GOR was 150 v/v until the end of 1985. Water injection conmmencedin 1987, out by the end of 1989 the GOR had risen to 360 v/v. Some wells were producing with a GOR in excess of 1000 v/v, and ONGC has now taken a decision to shut in such wells in order to avoid dissipating reservoir energy. In 1990 the Bombay High field produced overall 20.1 million tons 3f oil and 9.7 Bcms of gas at an average GOR of 400 v/v. Since the existing gas pipelines from Bombay High field can handle only 16.5 MMCMD as compared with an associated gas production of 26.5 MMCMD in 1990, the balance (minus the amount used for in-field use) is flared.

2.12 Remedial action being taken by ONGC consists of shutting in wells with high GORs, drilling of work-over wells with high permeability zones in the reservoir and voids behind the casing in attempt to seal them off and accelerated installation of water treatment and reinjection facilities. As a result of these efforts ONGC has reduced associated gas production, although at the coti of a reduction of oil production; as ONGC continues its strategy of containing excessive gas flaring by shutting in wells with a high gas/oil ratio, oil output will continue to decline correspondingly.

2.13 LAcxOF PiPE NE NETuWORK.Despite huge investments in the development of offshore gas projects, India still has a relatively inmmaturegas pipeline infrastructure. Until the early 1980slittle attempt was made to construct a pipeline network for gas distribution. There are two reasons for that. Until the mid-1980s the volume of gas (associated as well as free gas) available from the Bombay offshore area was vastly underestimnated. When it became apparent during the late 1980sthat gas could play a significant role in reducing energy shortages in the Western region and take some of the pressure off the balance of payments, the Govemment could no longer mobilize the foreign exchange required for these investments.

2.14 SLOWEXPANSION OF MARKJES OR GAS. In addition to the unexpected increase of associated gas in the western offshore area and the lack of pipelines for the transmission and distribution of gas, the Govemment paid little attention to the timely development of markets for the gas. As mentioned in the introduction to this chapter, the efficient use of gas resources requires close coordination between gas producers and consumers, (costly) investment infrastructure facilities for the transport of gas and institutional arrangements that encourage the expansion of the gas market in line with potential production. Apart from establishing a national gas marketing company, GAIL, which was initially preoccupied with the construction of the HBJ gas pipeline, the Govemment did little to encourage the growth of gas markets. Poor coordination between gas producers ONGC, GAIL and najor potential gas consumers, the lack of a clear policy that would spell out how the conflicting demands on gas resources by major interest groups, such as the fertilizer and power industries, should be resolved and the lack of a pricing policy for gas were the main factors that slowed the growth of gas markets. They will be discussed briefly in the remaining paragraphs of this chapter together with steps that have or will be taken by the Government to resolve these issues. -12-

2.15 POORCOORDINA110N BE1WEFN PRODUCERS ANDCONSUMERS. Efficient use of gas requires careful coordination of plans for the production and the use of gas. This coordination is particularly critical in the case of associated gas, where the option for suppressing its supply are usually limnited.After all, the supply of associated gas is determined by the demand for oil and, unless reinjection of associated gas is feasible, it has to be either used or flared. While some efforts were made in the Planning Commission in the context of the preparation of the Seventh Five-Year Plan to ensure that tho gas supplies projected by ONGC and OIL would be fully allocated to specific consumers, there was no institutional mechanism in place that allowed the Planning Commission to change these allocation plans, in case more (or less) of the projected volume of gas became available or designated consumers failed to use their gas allocations. The Government has agreed to set up a body ('Gas Coordination Committee9) in the Department of Petroleum and Natural Gas that will monitor quarterly the implementation of oil and gas field developments and revise gas production plans accordingly; it will also monitor quarterly the progress in construction of plants and other facilities (pipelines, gas processingfacilities, etc.) required for the offtake of gas. This body will issue a quartcrly report, in which it will list any deviation from the plans of gas producers and potential consumers. This report will also contain recommendations for steps that would need to be taken to ensure the efficient use of projected gas supplies. Copies of these reports would be submitted to the Bank for comments . The Bank's staff recommended that greater consideration should be given in the future to retrofitting existing industrial plants to burn gas, preferably on a dual-fuel, interruptible basis. In most other developing countries conversion has been a major early factor in the development of gas markets. Conversion has the advantages of short lead times, little capital requirenent and establishment of dual-fuelled plants providing future demand flexibility. Benefits in terms of reduced oil imports are substantial. Increased attention to conversion and dual firing in power and industry in India could greatly improve the efficiency of offtake in the short and medium term. This would give GAIL much needed flexibility in coping with supply and demand fluctuations, quite apart from the environmental benefits which would accrue as a result of such a policy. This would obviously require construction of a secondary gas distribution system along the HBJ pipeline.

2.16 UNCLEARGAS USE PoucIy. Until the late 1970soil companies sold gas to consumers in the vicinity of oilfields at whatever price the market would bear. The completion of the gas pipeline from Bombay High to Uran in 1978, following upon the discovery of the large reserves of South Bassein two years previously, led to an examination of gas use options by the Govemment. In 1979 a committee recommended that butane and propane (C3/C4) fractions be separated for liquefied petroleum gases or bottled gas (LPG) use, and the ethane and butane (C2/C3) fractions be used for petrochemical feedstock. The methane (Cl) fraction (about 80% of the total) was to be used as fertilizer feedstock, where it would substitute for naphtha. Use for power generation was rejected in view of the availability of domestic coal at prices competitive with the high oil prices prevailing at that time. The economics of fertilizer production, which favor location of plants close to consuming areas, and the desire to spread the benefits of offshore gas to states other than Maharashtra, led the committee to reconmmendthat the bulk of gas should be allocated to fertilizer plants in the Westem and Northern states. To supply these plants, the 1300 km Hazira-Bijaipur-Jagdishpur (HBJ) pipeline was constructed to take gas through Gujarat and Rajasthan to Uttar Pradesh. During the 1980s the Government's gas utilization policy shifted towards broader uses for gas, for power and liquid fuel replacement in industry. This change of policy was due to a perception that gas availability would exceed the requirements of the fertilizer sector, and to the increasing attraction of combined-cycle power plants for reducing India's power shortages, particularly in regions away from the coalfields in the eastern part of the country. It was decided to construct eight combined cycle power plants, with total capacity of 1500 MW along the HBJgas pipeline.

2.17 The decision to give priority to fertilizer plants in the allocaticn of gas has resulted in a substantial underutilization of the capacity of the HBJ pipeline and the full development of the South Bassein (free) gas field. Two distinct reasons lie behind the shortfall in gas demand along the HBJ pipeline: - 13-

(a) Construction of three of the six fertilizer plants planned in the early 1980shas only started very recently. This has been due to the delays in the authorization process and to changes in the fertilizer pricing system after authorization of the plants, which reduced the profitability of fertilizer production causing the plant's sponsors to delay investments.

(b) The two combined cycle power plants located along the HBJ pipeline have been unable to operate at base load as originally planned, because the higher unit cost of power from new gas-based combined cyclc plants has made it difficult for the National Thermal Power Corporation to sell their electricity to the SEBs.SEBs can purchase base-load power more cheaply from older coal-fired thermal power plants.

2.18 In March 1990, the Department of Petroleum and Natural Gas issued a paper outlining the Government's policy for allocating gas to consumers. The paper recognizes that the gas market in India is heavily dependetit on fertilizer production, power generation, and relatively large commitments to new metallurgical plants producing sponge iron by direct reduction of iron ore. The paper contains the following specific recommendations for the use of gas:

(a) first priority is given to the elimination of gas flaring, except where flaring cannot be avoided due to technical reasons, and the extraction of LPG and other gas fractions. Thus, the following statements refer to lean gas or methane (C1);

(b) to ensure that existing gas resources are fully used, the paper recommends the adoption of a time-bound gas utilization plan and the signing of gas contracts well in advance of the actual use of the gas;

(c) where competitive claims on gas resources require a decision on gas allocation, this decision should be based on the imputed value of gas; the user with the higher imputed value should receive the allocation;

(d) preferenre should be given to the allocation of gas to the power sector. The rationale for this recommendation is based on India's persistent power deficit, and the fact that, unlike fertilizer where imports are likely to be less expensive than domestically produced fertilizer for the foreseeable future, power cannot be imported. However, gas should not L allocated to base-load power plants unless these plants are located in areas far away from coal mines. In the allocation of gas to base-load power plants, associated gas should be used first. Power plants that generate power for peaking purposes could use free gas, since there is greater flexibility in adjusting gas supplies from these fields.

(e) in the decision on the development and use of gas resources priority should be given to the use of associated gas; free gas fields should only be developed after firm commitments for the use of their gas have been received;

(f) to reduce the risk of delays in the offtake of gas, the Department of Petroleum and Natural Gas should be authorized to seek commitments for the use of gas that exceeds projected availabilities by up to 12.5%;contracts for the 'excess commitment' of 12.5% should be on a 'fallback' basis, that is at a discounted gas price. GAIL confirmed that this policy had been implemented. Its current commitments to potential gas consumers (Table 2.4) exceed projected gas supplies and offtake by a sizeable margin.

2.19 Overall the policy recommended by the Dep.artment of Petroleum and Natural Gas should eliminate gas flaring and result in the efficient allocation of gas resources. The Government has agreed that it will ensure that gas allocations to end-users will be economically efficient; to this end the Govern- - 14-

Table 2.2 Reserves and Marketed Production of Natural Gas in Selected Developing Countries, 1990 Billwn cubk wmiS

Country Resere Produc*im

Algeria 3248 43 Venezuela 2993 18 Indonesia 2590 27 Mexico 2060 23 Malaysia 1611 13 China 1000 14 India 961 19 Argentina 765 17 Pakistan 551 7 Bangladesh 360 3 Egypt 351 5 Bolivia 117 2

Sources:Oil andGas journal, ONCC, UN WorldEnergy Statiscs

ment will submit annual teports to the Bank about changes in gas allocations together with their imputed or net-back values.

2.20 LACXOF A Ct.rEARRFSPONSIBILnTY FOR GAS MARKIN. Production, transport, and distribution of gas is entirely in the hand of state organizations, mainly OCNGC,OIL and GAIL. Gas supplies are allocated administratively by the Department of Petroleum and Natural Gas. Until recently both the producing companies, ONGC and OIL, and GAIL were allowed to sell gas to final consumers. To ensure the orderly matching of supply and demand, and the consistency of demandfrom established plants, the Government has decided to streamline all marketing activities and transfer the sole responsibility for the marketing of gas in India to GAIL. This decision greatly strengthens GAIL's role as a gas marketing company, bringing their operations closer into line with gas marketing companies in industrial countries. Apart from eliminating inefficiencies in the marketing of gas, this decision will make it easier to implement the recommendations of the Gas Coordination Committee (para. 2 15), which will be set up in the Department of Petro- leum and Natural Gas.

Gas Production Prospects 2.21 In terms of well head gas production, India ranks among the leading gas producing developing countries (Table 2.2). The Government's current plans call for the full development of the remaining discovered gas resources during the 1990s,which will lead to a substantial increase in gas availability in the medium term. Expected gas production in India's major gas producing region, the Western offshore area, is shown in detail in Annex 2.1. Table 2.3 which summarizes these projections, shows that associated gas production will decline fairly rapidly after the year 2000. The significance of these figures can be appreciated when it is realized that 1000 cubic meters of natural gas have approximately the sante calorific value as one ton of oil, for which it can substitute in power stations, industrial steam raising, process heat, etc. Natural gas can also substitute for coal used for these purposes. Given that the greatest reserves of gas are in the west of India, whereas the coal fields are nearly all in the east, the substitution of gas for coal can lead to substantial economic and environmnentalbenefits. - 15 -

Gas Utilization

2.22 The increase in gas supplies as a result oi the project will be used in three regional markets:

(a) the Bombay market served by the Uran terminal. This market serves a varied base of fertilizers, power and industry close to the terminal at Uran, with substantial potential demand arising from Bombay's concentration of heavy industry;

(b) the Gujarat market served both from the terminal a' Hazira and from the ortshore Gujarat fields. This is a diverse market, with a number of large power and fertilizer customers, and some 50 small industrial users; and

(c) the Northern market se-ved by the HBJ gas pipeline. The primary users along the gas pipeline will be power and fertilizer plants as well as industrial users.

Annex 2.3 provides a detailed overview of the current pattern of gas allocations and projected gas use in the three gas markets served by the project. It also contains a review of the status of implementation of projects that have received gas allocations and are expected to come on stream over the next five ye rs. Table 2.4 summarizes this information.

2.23 TtuFBOMBAY MARKET. Bombay is one of the more industrialized arees of India, and gas is consumed by power stations, fertilizer and petrochemical plants. The market for gas in Bombay is projected to expanc to 16 MMCMD by 1995,partly due to increasing consumption by existing consumers and partly to the construction of new petrochemical and metallurgical plants. This market has a large energy deficit, and the Bank's staff agrees with GAIL's expectation that all allocated gas supplies will be utilized.

2.24 THlEGUJARAT MARKET. This market, which is centered around the Hazira gas terminal, receives gas from oil fields in the western region. The demand for gas in this market is dominated by fertilizer and power plants, and some 50 industrial users. In general this is an energy-deficient region, and since gas will be sold at 'landfall prices', the Bank's staff expects that there is only a small risk that there will be significant shortfalls in the offtake of the gas supplies a,located to this marke..

2.25 TinENoR11iaLN MARKET. ThM HBJ gas pipeline has currently a capacity of 20 MMCMD. With additional compression and some 'looping', this capacity can be increased to 33.5 MMCMD. At present, plants along the HBJ gas pipeline use barely 9 MMCMD. Some of the reasons for delays in the offtake of gas have been listed in paras 2.08 - 2.16. GAIL charges consumers along the pipeline an additional fee of Rs 850 per 1000 m3. 'Te National Thermal Power Corporation has pointed out that it cannot sell power generated in combined cycle power stations to SEBsat prevailing power tariffs and the higher gas prices along the HBJ gas pipeline. Offtake of gas along the HBJ poses a serious marketing risk for gas. This risk has been further heightened by the growing scarcity of investment resources, which may delay the completion of projects along the HBJ gas pipeline. The Bank's recommendation to set up a monitoring body in the Department of Petroleum and Natural Gas (para. 2.15) makes it possible for the Goven.ment to redirect gas supplies to the Gujarat market in a timely manner. If there ar,. clear indications that the gas supplies allocated to users along the HBJ are not utilized, the Governrmentand GAIL wi'l have to rethink their gas marketing strategy for the western offshore region, and address the constraints that prevent the marketing of a larger share of gas supplies in the Bombay areai.

Gas Pricing 2.26 The Government's pricing policy for gas remains a key factor in the successful and timely development of gas markets. Gas pricing is a highly controversial issue. The Government has informally discussed the various options for pricing of gas with the Bank. The policy that is currently before the Cabinetis in line with the Bank's recommendations. * l6-

Table 2.3 Gas Production and Utilization in the Westem Offshore Region, 1991 to 2010 Millaimcubic metm perday

Year .4ssc iated F:er Total Ilazira Termnal Uran Terminal Total GasC ('as Gas Capacity Offtake Capacity Offtake Cilt4ke

1991 17: 7.5 24.6 20.0 12.5 12.5 12.1 24.6 1992 t:7.5 9.7 27.2 20.0 14.7 12.5 12.5 27.2 1993 13.8 13.8 29.6 20.0 17.6 12.5 12.0 29.6 1994 20.7 15.3 36.0 200 20.0 16.0 16.0 36.0 1995 23.3 12.7 36.0 20.0 20.0 16.0 16.0 35.0 1996 32.2 28.8 61.0 45.0 28.0 16.0 14.0 42.0 1997 30.3 30.7 61.0 45.0 38.0 16.0 14.0 52.0 1998 27.3 33.7 61.0 45.0 45.0 1&0 16.0 61.0 1999 26.0 35.0 61.0 45.0 45.0 16.0 16.0 61.0 2000 23.8 37.2 61.0 45.0 45.0 16.0 16.0 61.0 2001 21.5 39.5 61.0 45.0 45.0 16.0 16.0 61.0 2002. 18.9 42.1 61.0 45.0 45.0 16.0 16.0 61.0 200.3 16.6 44.4 61,0 45.0 45.0 16.0 16.0 61.0 2034 15.0 46.0 61.0 45.0 45.0 16.0 16.0 61.0 2005 13.6 47.4 61.0 45.0 45.0 16.0 16.0 61.0 2006 11.6 49.4 61.0 45.0 45.0 16.0 16.0 61.0 2OCr 10.5 50.5 61.0 45.0 45.0 16.0 16.0 61.0 20038 9.5 51.5 61,0 45.0 45.0 16.0 16.0 61.0 2(X9 9.0 52.0 61.0 45.0 45.0 16.0 16.0 61.0 2210 8.4 52.6 61.0 45.0 45.0 16.0 16.0 61.0

Notes: 'Net gas availability e.g. after internal use and tkidng into account compressor and pipeline constraints I Free gasproduction includesproduction from new known fields (Annex2.1) with additioinalproduc- tion from South Basseinaasumed asmeeting denud as reqired. Sourre ONGC and mission estimates.

2.27 ThiEORTICAL CONSIDERAIONS. Gas prices have three important functions: (i) to provide an incentive to consumers to use gas efficiently, (ii) to encourage the optimal level of investments in potential gas-using industries, and (iii) to stimulate exploration and development of gas resources. While nearly ali commodity prices have these functions, the physical link between gas producers and consumers (gas chain') makes it difficult to determine gas prices under 'free market conditions'. The situation is similar to the pricing of &c'ctric power. The physical link between the producer (power generating company), the transmission and distribution companies, and consumers reduces the number of altemative sources of supply and thus encourages monopolistic pricing practices. This risk is considerably smaller in many industrial countries where gas producers have the option to sell their gas to several gas companies, while gas companies have the option of buying gas irom a number of producers; and, consumers have the option to switch to alternative fuels. In most developing countries, producers have little choice but to sell their gas to a national gas company and to allow the Government to set prices. Depending on whether gas supplies exceed detnand or demand exceeds supplies, two different approaches to gas pricing have emerged. For countries where supplies exceed demand, the long-run marginal cost of gas prm !iction plus a depletion premium becomes the correct basis for settirnggas prices. For countries, such as india, where demand is likely to exceed gas supplies for the foreseeable future, the correct pricing basis to achieve the pricing objectives outlined above is the cost of the marginal replacement fuel. The Government's proposed pricing principles are in accordance with these principles.

2.28 EVOLULnONOF A PRICINGPOLI, Y FORNATURAL GAS. In India gas has historically been vroduced along with crude oil. Since most such gas, which would otherwise be flared, is sold to consumers on a cost-plus basis, there has been no pressing need for a comprehensive gas pricing policy. With the i dvent of larger vohtmes of offshore associated gas from Bombay High, ONGC and the GOI have been moving - 17 - more towards replacement pricing over the past few years. As a result, a numTlberof dlifferent pricing levels have evolved based on contractual arrangements negotiated at different times in different regions ot the country. For example, on shore associated gas from Gujarat has been pricedi as low as Rs 355 per 1000m3. Although this price is the result of a decision by an arbitration cormnittee, it is indicative of the low contractual prices ONGC received as a result of the lack of alternative markets for gas at the tinmeot field development. Offshore associated gas has been priced between Rs 555 and Ks 2,78)pxr l(.Xhrn, depending on end use. The lower price was for interruptible supplies to power plants, anid theshigher pnce for guaranteed supplies to fertilizer and industry.

2.29 With the advent of large quantities of free gas (primarily from South Bassein), the Govern- ment recognized in 1986 that there was a need for a more comprehensive pricing policy. T'hey examined various policy optioris and eventually adopted the following set of pricing principles:

(a) the base price of natural gas should be linked to the price of the fuel or fkedstock repliced;

(b) the price structure should be simple to administer and to underst, nd, and with prices to users to be uniform along the pipeline, and

Table 2.4 Gas Commitments and Offtake by Sector, 1991 to 1995 Million cubic meters per day

Mlarket/Sector 1991 l992 1993 1994 1995

Bombay market Fertilizer 5.10 5.10 5.10 5.40 5 40 flower 4.50 6.00 6.00 6.(X0 6(0) Industry 2.98 3 73 3,74 5 94 W.10 Other 000 ()10 (050 (0(8 1 S(2

Subtotal Bonibay market 12 58 14 93 15 34 18 14 1l (X) Expected offtake Bombay market 12.50 12.50 12.50 16.(0) In (X)

Cujarat market Fertilizer 3.30 3,30 3.30 3 30 3.30 Power 0.00 0,00 0.0() 2.25 2.25 Industry 0.80 0.80 2.80 3.7(0 4.70 Otther 1 00 1 00 1.3(2 1.30 1 30

Subtotal Gujarat market 510 5.10 7.40 10.55 11 S5 Expected offtake Gujarat market 5.10 5.10 7(X) 9.25 1(00

Northern market (HBJ pipeline) Fertilizer 5 40 5,40 5.40 12. f 14.40 Power 5.10 7.60 7.60 7.85 11 85 Industry 0.50 1.00 2.30 5 40 7.2( Other 0.50 0.50 0.80 1.00 1.0()

Subtotal northern market 11.50 14.50 16.10 26.85 3445 Expected offtake along HBJ 7.40 9.60 1060 1875 24.50

Total commitments 29.18 34.53 38 84 55 S4 (50)

Source GAll. and mission estimates -18 -

(c) the gas company, GAIL, should earn a fair return on costs. Any surplus would accrue at the producer end, where the resource rent would be taxed by the Government.

2.30 These policy principles have been formalized into the following set of gas prices announced in mid-1987:

(i) gas at landfall points and onshore gas would be sold at Rs 1400 per 1000m3;

(ii) gas along the HBJ gas pipeline would be sold at Rs 2250 per 1000 m; and

(iii) in Assam, where associated gas exists in surplus, gas would be sold at Rs 500 to Rs 1000 per 1000m3.Allowances are Iso made for discounts in the cases of interruptible users, and to encourage market build-up during the initial years of new fieid development.

2.31 The Government had decided to review gas prices every three years. In 1989 the Govern- ment asked the Bureau of Industrial Cost and Prices (BICP) to review the existing pricing policy for gas and, if necessary, recommend changes. In March 1990 the BICP issued its report, in which it proposes that:

(a) the price paid to producers (ONGC and OIL) should be based on the long-run average production cost of gas from the South Bassein (free) gas field, and proposed a price of Rs 1500 per 1000 m3. This price should ensure producers a 15% rate of return on investments;

(b) prices to consum ,rs should be based on the economic cost of the marginal replacement fuel. The question of ti ie appropriate ga;, price then boils down to the definition of the marginal replacement fuel. The BICP based its recommcndavion on the assumption that gas should primnarilybe used to replace costly tradeable oil products, wherever this was technica-lly feasible. Annex 2.4 ..lustrates this approach. It is based on the Govemment's projections of gas use in the western and northern regions in 1995/96. Table 2.5 illustrates the relative

Table 2.5 Comparison of Domestic and International Prices for Selected Fuels, 1991 US DLar5

Fuel Typeof Use Unit Ex RefineryPrice Wltolel CIF Price Ratio of Whoksaek Ex Pithead Price Price to CIFPrices

Naphtha Fertilizer metnc ton 117.0 127.5 240.0 0.53 Naphtha Non-fertilizer metric ton 117.0 206.6 240.0 0.86 .asoline MS93 metric ton 127.7 975.8 260.1 3.75 Kerosine Industrial uses metric ton 129.4 251.2 404.6 0.62 Kerosine Other uses metric ton 129.4 161.8 404.6 0.40 Diesel oil I ISD metric ton 123.4 282.8 3523 0.80 Fuel oil Fertilizer metric ton 83.4 91.0 144.0 0.63 Fuel oil Non-fertilizer metric ton 83.4 200.0 144.0 1.39 Crude oil metric ton N.A. 108.7 125.0 0.87

Natural gas 2 1000m3 72.1 146.6 N.A. Coal' EGrade, ROM metric ton 10.7 28.8 51.0' 1.58

Notes: ' Wholesaleprices in Bombay Natiuralgas prices refer to producerprice and pricealcng the HBJgas pipelne (includingtaxes), respectively XCoai price refersto coal (2330KcAl) from theMaira mine,Chandrapur, delivered at Bombay Importa,dcoal is estimatedto have6500 Kca. -19-

prices of fuels competing with gas. The BICP decided on fuel oil as the marginal replacement fuel, and proposedthat gasprices to consumersshould be brought in line with the cost of international fuel oil prices.The Govemment has decided to implement this volicy over a three year period starting July 1, 1991. In the first year gas prices (at landfall points) will be raised to Rs 1550per 1000m3; in the second year to Rs 1650per 1000m3;and in the third year to Rs 1750per 1000m3. At the end of the third year gas prices will be raised to Rs 1850per 10o0m3 .

(c) the committee recommended that Gas Authority of India nimited(GAIL) should be allowed a margin of RS 850 per 1000m3 for transport and distribution costs. This was the recommended price for all consumers along the HBJ pipeline regardless of distance from the supply point of the pipeline at Hazira.

(d) the difference between the producer price and the prices to consumers will accrue to GAIL; and

(e) consumers in the North-east (Assam and Tripura) would continue to pay for gas at a rae of only Rs 600--1000 per 1000m3.

2.32 The proposed gas pricing policy is line with the pricing principles the Bank has recommended. The link between domestic gas prices and international fuel oil prices eliminates much of the arbitrariness that governs the Govemment's price setting practices by tying the price Indian consumers have to pay to the international market price of the marginal replacement fuel. The Government has agreed to discussany proposalsfor revisionsof this pricing policy with the Bank.

The Role of the Bank 2.33 Bank lending operations in India's , il and gas sector go back to the late 1970swhen the development of ONGC's giant Bombay Hign o,J i. ld was first undertaken. The projects financed from Bank loans since then have been successfully c 't eted and have achieved their main objectives. The first Bank loar helped finance the Bombay High OtnI,-c Development project (Ln. 1473-1N).This was followed by the Second Bornbay High Offshore D"',.nment project (Ln. 1925-1N),the Krishna Godavari Petroleurni Exploration project (Ln. 2205-IN)anc aLbeCambay Basin Petroleum project (LLn.2403-IN). Then, with the rapid grow+. of oil production fromr'torln y High and the corresponding i sc eased amounts of associated natural gas along with the large natusa,' .c r-served discovered at South bassein, the Bank shifted the emphasis u f its support to the naturail g, d ector. A need was foreseen to come to grips with such critical issues as gas utilization, sector plannin, :..ndgas pricing. The Bank's first lending operation in the gas sector was to help Financethe South Bassein C. - Development project (Ln.2241-IN);this was followed by the Westem Gas Development project (I i.J.9)4-IN), which is still under implementation.

2.34 ONGC's offshore operations have grown at aknunprecedented rate and in the process ONGC has developed into a full-fledged production ol onmpany. Despite its rapid growth ONGC has been able to train and maintain i competent and dedicated staff. ONGC, however, has one weakness which greatly detracts from an otherwise creditable perfornance. Its poor procurement performance, which is also in part due to excessive bureaucratic procedures required by the Government, causes numerous delays which past experience has shown can add two or more years to the projection completion date. ONGC has requested ;he Bank's support for effort^:

(a) to streamline its pro.urement procedures and practices; and

(b) to provide project management training and guidelines including project coordination. - 20 -

In parallel with the appraisal of this project, the Bank is working closely with ONGC on the above two objectives.

2.35 T'i; BANK"' laNDoINCSTRArhC;Y. The Bank supports the Covernment's efforts to

(i) climinate ihe flaring of associated g is;

(ii to accelerate the development of gas markets in India and ensure that gas is used efficiently; and

(iii' to tully develop India's gas resources.

Apart from eliminating the wasteful flaring of gas, the most pressing need in the years ahead is development of gas markets in line with the existing gas production potential. Thus, in parallel to its ongoing support for gas projects with ONGC and OIL, the Bank increasingly seeks to support GAIL's efforts to expand the existing gas mnarkets.

Lessons Learnt From Previous Bank Operations

2.36 Expeiencce with the implemertation of gas projects in India has shown a critical need to co- ordinate the development of gas fields and gas mnarkets.The excessive flaring of gas in the Bombay High oilfield is largely the result of delays in the development of gas markets (in particular the identification of 'fall back' consumers) and the lack of investments in pipelines and other infrastructure facilities. To ensure that gas will be used efficiently under the proposed project, the marketing plans for gas have been reviewed with the Gas Authority of India Ltd., fall back plans for the allocation of gas have been drawn up in case sonmeusers are unable to utilize their gas allocations and a body will be set up in the Department of Petroleum and Natural Gas that will monitor progress in the implementation of gas projects as well as of projects that will utilize gas

2.37 Several projects with ONGC have taken longer to irrnA!ementthan anticipated at appraisal. ONGC's complex decision making structure has been a major cause of these delays. ONGC has requested the Bank's assistance in streamlining its procurement and project implementation organization.

III. THE OIL AND NATURAL GAS COMMISSION

Introduction 3.01 The Oil and Natural Gas Commission (ONGC) will be the beneficiary of the proposed project. ONGC was established by the Government in 1959as a statutory body to plan, promote, organize and implement programs for the development of oil and natural gas resources and the sale of oil and natural gas products. ONGC, which is fully owned by the Government, now shares this mission with several other publicly-owned corporations. About 10%of India's oil and gas output is produced by Oil India Ltd. (OIL), whose operations are concentrated in India's northeastem region, mainly Assam, and Rajasthan. Refining of crude oil and the marketing of oil products is in the hands of six refinery and three marketing companies. With a market share of almost 50% and six refineries, the Indian Oil Corporation (IOC) is India's largest refinery and marketing company for oil products. The marketing of natural gas is in the hands of the Gas Authority of India Ltd. (GAIL). All of these corporations report to the Ministry of Petrolcum and Chemicals. All major investments in the oil and gas sector have to be approved by the Cabinet Committee on Economic Affairs following a recommendation by the Public Investmer; Board on which all concerned ministnes as well as the Planning Commission are represented. Decisions on the -21 -

pricing of oil and gas products are made by the Cabinet based on reLconunenddtionsOf the Mfililstrvef Petroleum and Chemicals and inter-ministerial consultations.

Organization and Management 3.02 The 1959 ONGC Act provides that the Commission shall coonsist of a Chairmanii and iot les'i than two, but not more than eight Members. Members are appointed by the Government for ternis not exceeding five years and are eligible for reappointment. The conmmissionsets policies, manages the activities, and develops plans and budgets for ONGC. All decisions must be approved by a majority of Members. At present, the Commission consists of the Chairman and six Members from within ONGC and two Fart-time Members representing the Ministry of Finance and the Ministry of Petroleum and Chemi- cals. An Executive committee consisting of the Chairman and the six ONGC Members oversees ONGC's day-to-day operations.

Institutional Issues 3.03 GREATERMANAGERIAL EFFcCENcY. In 1986, ONGC's oard reorganized the activities of the Commission along functional lines and regions. The objective of the reorganization was to improve the operational performnance,raise accountability, and achieve greater coordination between functional groups. Six regional 'business centers' were established that integrated all activities of each region (Annex 3.1). Each business center is headed by a regional director. Within each business center, staff is organized along functional lines (e.g., exploration, development) in the form of business groups. ONGC has set up eight institutes with the aim of providing technical support and training to the staff in the business groups in each regional center. Each member of the Commission is in charge of one of the regional centers. As a result of this reorganization ONGC has been in a better position to deal with the strains caused by the rapid growth of its operations. Over the past ten years, ONGC was able to increase oil output by almost 15% per year while keeping the growth of its staff to 1% per year.

3.04 GREATmsAUroNomyc. As a statutory body, ONGC's room for tak"nGdecisions is constrained by Govemment prevailing policies and procedures. In order to reap the full benefits of its efficiency improvements, ONGC uses Memoranda of Understandings with the Government (MOUs) to define its responsibilities vis-a-vis the Government, to minimize Government interference in its day-to-day operations and to accelerate Govemment approvals. ONGC signed the first MOU with the Ministry of I'etro- leum and Chemicals in 1986. The MOU spelled ou. performance targets and steps the Government was to take to speed up approvals. Subsequent MOUs extended ONGC's autonomy, and in 1990 the Government granted ONGC far-reaching autonomy over its foreign exchange budget. ONGC can now spend 75% of its approved annual foreign exchange budget; the remaining 25% will be released by the Government after ONGC provides the required detailed information. In many respects, ONGC's autonomy is now compa- rable to that of other public sector corporations.

3.05 GREATERINVOLVEMENr OF nTE PRIVATE SECrOR. In addition to attaining a greater measure of autonomy in its decision making, ONGC is relying increasingly on private sector companies for the expansion of its operations. In addition to contracting out services to Indian and foreign companies which were originally provided by ONGC's staff, the Government is relying increasingly on international oil companies in the exploration of oil and gas resources.

3.06 DIvTrErRE.ONGC uses not only the services of existing domestic private and public sector companies, it also assists former employees in setting up cooperatives and joint ventures with foreign companies. ONGC's main areas for divestiture involve activities of a highly technical nature. A: presen1t, there are about 40 privately owned specialized companies of which ONGC uses regularl,y about 25. They include charter hiring of drilling rigs; helicopter, marine and diving services; operation and maintenance of installations and vessels; soil investigation, surveys, well logging and production testing. Nlost of these - 22 -

services were originally procured from foreign sources. Orders to local privately-owned companies have increased from Rs 1270million (US$71million) in 1980/81 to Rs 9,900 million (US$560million) in 1989/90.

3.07 ROLEOF INTERNATONAL OIL COMPANTES.In the early 1980s,the Govemrnmentadopted a policy of inviting international oil companies to explore for oil on a sole risk basis. Under this arrangement oil companies commit themselves to a program of exploration work in certain geographical areas. They are under an obligation to finance and carry out this program within a certain tirne frame, in exchange for a share of their output if hydrocarbons are found.

3.08 Up to now, there have been three "rounds of offerings of exploration acreage". The first two rounds mnetonly with limnitedsuccess. The industry felt that the terms of the production sharing contracts were not competitive and the blceks offered were not sufficiently prospective. In the first round (in 1980), the Government offered 15 onshore and 17 offshore blocks. Only four international companies submitted bids for two blocks and only one contract was signed. In the second round in 1982, the Government offered eight onshore and 42 offshore blocks. No contracts were signed. For the third round (in 1986/87), the Government improved the terms of the contracts and offered more prospective areas. Of the 27 offshore blocks that were offered, seven international oil companies submitted 12bids. A fourth round is expected to be announced by the Government before August 1991.The contractual termnswill be similar to those of the third round. These terms are in line with international practices. Despite the lack of success of the three previous rounds, international oil companies appreciate that India is essentially still underexplored, particularly in technically difficult areas such as the Bay of Cambay, Kutch and the possible western extension of Bombay High in deeper waters on the continental shelf and slope. The fourth round should therefore result in a substantial number of bids.

Accounting, Management Information and Auditing 3.09 ONGC keeps its accounts in accordance with international accounting practices. In 1986, ONGC adopted the successful efforts method of accounting (Annex 3.2) to cost its exploration and drilling operations - a practice followed by most international oil and gas companies. ONGC's accounting system, which is computerized, meets the requirements for financial accounting, budgetary control and cost and mnanagementaccounting. ONGC prepares detailed rolling budgets that are largely based on physical performance targets (million tons of oil produced, meters drilled, etc.) for each of its operating units. Since achievement of the agreed physical performance targets remains the paramount objective of ONGC's management, the budget system lacks sufficient orientation towards cost control and improving efficiency. It also makes it difficult to respond to changing circumstances. ' "anges in performance targets frequently require ministerial or cabinet approval, particularly when foreign exchange expenditures are involved, resulting in delays in implementation of corrective measures. ONGC is aware of this and is introducing changes that will make the budget a more effective tool for enhancing efficiency. Long term financial planning is currently only carried out in conjunction with the Government's five year plans, but steps are being taken to prepare rolling five year financial projections on an annual basis.

3.10 Over the past two years, ONGC has built up an elaborate management information system which makes it possible for management to assess ONGC's operational performance through detailed monthly reports and other reports. ONGC is in the process of computerizing the system by establishing satellite linkages between headquarters and its regional centers.

3.11 ONGC's accounts are audited annually by the Comptroller and Auditor General of India. The audit is normally completed by November, after which the accounts have to be submitted to Parlia- ment for approval. ONGC's internal auditors carry out a continuous audit during the year, while the Corporate Management Group undertakes management audits on a regular basis. The audit arrangements are satisfactory. ONGC has agreed that its annual accounts, including the audit report of the special account and the statement of expenditures for the project, if any, will be made available to the Bank - 23 -

Table 3.1 ONGC: Summary of financial results, 1986 to 1990

Fiscal yr endingMarch31 1986 1987 1988 1989 1990

Volumes sold: Crude 0hi (mill tons) 26 28 27 29 30 Natural Gas (MMCM) 3,3( 5,042 5,873 6,932 8,610 LPG and NGL (mill. tons) 0.4 0.6 0.7 1.1 1.3 -_ -Rs biDion - 0i1 revenues 38.2 48.0 49.5 53.7 63.2 Otherrevenues 5.7 8.3 11.6 16.0 18.1 Total Revenue 43.9 563 61.1 69.7 81.3 Royalties, excise cess and sales tax 12.3 21.8 24.6 28.1 37.2 Total revenues retained 31.1 34.5 36.5 41.6 44.1 Total operating expenses 10.7 12.2 15.3 19.9 22.9 Operating income 20.4 22.3 21.2 21.7 21.2 Les: Interest (net) 1.6 1.2 0.7 0.8 1.0 Corporate taxes 6.0 6.2 5.4 4.9 4.0 Net operating incorme 12.8 14.9 15.1 16.0 16.2 Dividends 0.3 0.4 0.4 0.5 0.5 Net income retained 1Z5 14.5 14.7 15.5 15.7 Key financial ratios Operating ratio (revenues retained) (Percent) 34 35 42 48 52 Return on total equity (Percent) 32 27 21 19 16 Return on average net fixed assets (Percent) 31 28 23 21 19 Return on capital employed (Percent) 22 20 17 16 14 Dividend as Percent of total equity I 1 1 1 1 Current Ratio (times) 1.3 1.5 1.6 1 8 1.7 L.ong-term debt to total equity ratio (times) 0.5 0.5 0.4 0.5 0.5 Debt service coverage (times) 4.8 1.9 3.6 5.4 2.8 Self financing ratio (Percent) 83 40 149 172 81

Source: ONGC

within nine months of the end of the fiscal year. ONGC has further agreed that it will submit unaudited financial statements (income statements, funds flow statement and balance sheet) to the Bank within six months of the end of the fiscal year.

Financial Performance 3.12 The financial performance of ONGC over the past ten years is sunmmarizedin Annexes 3.3 - 3.6. An overview of its performance during the past five years is provided in Table 3.1. The table shows that ONGC's operations grew rapidly during the past ten years. Sales of crude oil increased from 9 million tons in 1981to 26 million tons in 1985 and 30 million tons in 1990.Sales of natural gas increased more gradually from 972 MMCM in 1981 to 8610 MMCM in 1990, an average increase of about 27% a year. Total revenues increased from Rs 4.5 billion in 1981 to Rs 81.3 billion in 1990,an average increase of 38% a year. The proportion of oil revenues in total sales has declined from a peak of 88% in 1985 to 78% by 1990.

3.13 ONGC's operating ratio has increased steadily since 1986, and returns on equity and net fixed assets in operation have declined since 1986. This is to a large extent due to the Government's decision not to raise ONGCs net retention price of Rs 967.85per metric ton (mt) of crude oil which has been aimde at this level since July 1981 in spite of increasing operating costs, rising inflation and a steady devaluation of the Rupee. Similarly for natural gas the basic price of Rs 1,400per 1000 m3 has been in effect since 1985. Taking into account the devaluation of the Rupee over the past ten years, the net retention price for oil has declined from US$123per mt (equivalent to US$17per bbl) in 1981 to US$54per mt (equivalent to US$7per bbl) in 1990. In spite of the lack of adjustments in the producer prices for oil and - 24 - gas, ONGC's financial position has remnainedsound. All its financial ratios agreed with the Bank under previously approved loans have been considerably exceeded.

3.14 Since 1984,ONGC's net internal cash generation has exceeded its total capital expenditire. ONGC's self financinig ratio averaged 82% during the Sixth Five Year Plan (1981-85)and 105% during the Seventh Plan (1980-90).The high self-financing ratios reflect the rapid growth of oil output from the Bombay High oilfield, where production costs are lower than in other Indian fields, a reduction of corporate taxes and ONGC's policy of paying rather modest dividends.

Meeting ONGC's Foreign Exchange Requirements 3.15 ONGC's recourse to long-term borrowings has been dictated by the Ministry of Finance's requirement that all foreign currency expenditure on capital projects be financed either directly or through the Government from official sources. Sources, timing and currencies of foreign loans are decided by the Ministry of Finance to ensure consistency with India's overall borrowing strategy. Currently, about 30 - 40% of ONGC's capital expenditure and 10 - 15%of its cash operating costs require foreign exchange. These shares have declined over the past few years as a result of ONGC's indigenization policy. Table 3.2 provides an overview of ONGC's sources of finance.

3.16 Over the past ten years, some 42% of ONGC's total foreign exchange requirements (including capital expenditures, operating costs and debt service requirements) were met from the country's free foreign exchange resources. The remaining 58% of the total foreign exchange requirenents were secured through direct borrowing from foreign private sources or indirectly from loans (mostly from the World Bank) on-lent to ONGC by the Government. During 1985-90,ONGC's foreign borrowing amounted to Rs 55.4 billion (about US$ 3.2 billion) of which 88% consisted of long term syndicated loans and issues of securities, both predominantly US Dollar denominated and arranged with the help of US, Japanese and

Table 3.2 ONGC: Sources of Financing, 1986 to 1990 Rs billion

F-iscaiyears endin.g March 31 1986 1987 1988 1989 1990 Total

Funding requirements Tota! capital e>penditures 17.36 18.96 18.96 23.29 31 00 109.57 Total debt service 4.74 13.34 7.86 6.43 13.67 46.04 Corpx)rate taxes 5.96 6.21 5.35 4.93 3.97 26.42 Inaease in working :apital 3.80 5.17 1 45 1.21 4,57 16.20 Total funding requirements 31.86 43.68 33.62 35.86 53.21 198.23

Financed by: Net internal cash generation 28.61 30.95 33.67 39.50 41.88 174.60 Borrowings: Domestic be-rowmngs 0.08 0.04 0.02 0.02 0.00 0.16 Foreign currency loans onlent by GOI 0.93 0.76 1.60 1.00 1.35 5.64 International capital market borrowings by ONGC 2.81 13.74 7.87 8.40 16.12 48.94 Suppliers/buyers credits ONGC 0.08 000 0.04 0.54 0.00 0Q66 Total borrowings 3.90 14.54 9.53 9.96 17.47 55.40 Total sources 32.50 45.49 43.20 49.46 59.35 230.00 Surplus 0.64 1.81 9.58 13.60 6.14 31.77 Used for: Long terrn investments 0.30 1.45 9 18 13 09 5.59 29.61 Dividends 0.34 0.36 0.40 0.51 0.55 2.16

Sourre ONGC -25 -

European private banks and security houses. Such wide market access enabled ONGC to minimnizethe use of tied, market priced financing, such as export and supplier credits. As of March 31, 1990,ONGC's total direct foreign currency long term debt amounted to Rs 48.1 billion (equivalent to about US$ 2.8 billion at the exchange rate then applicable), of which 71% was denominated in US Dollar and 200%in Yen, the remainder in other currencies. At the same date, indirect foreign currency debt amounted to Rs 9.3 billion.

3.17 ONGC has sought to insulate itself to the extent possible from the risks associated with its growing foreign exchange indebtedness; it sought to diversify the currencies in which it borrowed, and strike a balance between fixed and floating rate borrowings; it also arranged a number of interest rate swaps. In 1987,ONGC prepaid some loans in order to take advantage of the drop of interest rates in international financial markets. However, since ONGC has no direct foreign exchange earnings, its options for using hedging techniques conducive to a more cost-effective liability management are limited.

ONGC's Financial Relationship with the Government 3.18 ONGC's contributions to the Govemment's revenues are substantial. Dunng the Seventh Plan, ONGC contributed about R.s16.5 billion to the budget of the Central (Rs 14.5 billion) and State Govemment (Rs 2 billion) in the form of excise cess, royalties, duties, corporate tax and dividends. The Government's policy regarding producer prices for oil and gas and ONGC's borrowing strategy have allowed ONGC to generate substantial Rupee surpluses, which have been used for long term investments in public sector securities and public sector undertakings. On March 31,1990, the total value of these investments and loans was about Rs 35 billion (about US$2billion). It has provided ONGC with substantial additional revenues (Rs 3,870 million in 1990).

ONGC's Operational Performance 3.19 It is difficult to compare ONGC's operational performance with that of other national and internationial oil companies. Unlike private intemational oil companies, whose main objective is profit maximization, ONGC's role is more complex. While its primary role is to explore for and develop India's oil and gas resources, ONGC remains an important vehicle for raising revenues in domestic markets and foreign exchange loans in intemational financial markets. ONGC has also emerged as a major institutional investor in non-oil and gas related activities in India. To foster this role, the Government has kept producer prices well in excess of ONGC's production costs and, more recently, reduced the corporate tax rate to compensate for inflation and the devaluation of the Rupee. Administered prices for crude oil and gas have protected ONqGCfrom fluctuations of oil prices in international markets and its near-monopoly position shelters it from competitive pressures. To ensure that ONGC operates efficiently, the Government monitors ONGC's operations through the physical and financial performnancetargets agreed in the annual MOUs. Annex 3.7 provides a comparison of ONGC's performance in terms of selected cost and other ratios.

3.20 ONGC's production costs for cTude oil have re-rined well below the import parity price throughout the 1980s.In 1990, ONGC's average production costs at the wellhead were about US$25per ton of oil (US$3.42per barrel) and US$48per 1000m 3 of gas. Offshore production costs were US$22 per ton for oil (US$3.0per barrel) and US$38 per 1000m 3 of gas. After declining steadily until 1988,ONGC's production unit costs in 1989and 1990 and operating expenses in 1990increased considerably. This was due to several factors: rising inflation, the devaluation of the Rupee, higher financing costs a less successful exploration program in these years, which increased the level of amortization and ONGC's costly indigenization policy (para. 3.06). In spite of these cost increases, ONGC's production costs are rough)v in line with those of oil and gas companies of this size. Its reserve to production ratios of about 22 for oil and 41 for gas remain at acceptable levels. -26 -

3.21 There is, however, room for efficiency improvements. With a staff of about 47,000,ONGCs production of about 17 bbl of oil equivalent/day per employee is relatively low by international standards. Its average drilling cost has declined to about US$ 541 per meter in 1990but remains high by international standards. Continuous involvement of the Bank with ONGC has, over the years, led to improvements in operational efficiency as well as policy changes with respect to increased involvement of the private sector. ONGC has recently requested the Bank to review project implementation arrangements and its reservoir management. As ONGC owns most of its field service equipment, compared to other oil companies, the Bank has recommended improving efficiency by farming out services to both domestic and foreign specialized firms. This should lead to a further reduction of drilling cost, although the prefer- ence of domestic suppliers should be gradually eliminated. The Government's decision to invite international oil companies to explore for oil and gas in India will expose ONGC to state-of-the art exploration techniques and efficient operations, particularly if ONGC enters into a production sharing agreement with the foreign oil companies. While ONGC's mnanagementfavors close interaction with the private sector, particularly through joint ventures, privatization of ONGC would be politically not feasible. Bank support for the Government's policy to increase ONGC's exposure to a more competitive environment extpnd its autonomy and shift the emphasis from attaining quantitative targets to efficiency improvements, would achieve similar objectives.

Investment Program 3.22 ONGC's level of capital expenditure almost doubled from Rs .58billion during the Sixth Plan (1981 - 1985)to Rs 110 billion during the Seventh Plan (1986-1990).Output from the Bombay High oilfield accounts for about 60% of indigenous oil production output has reached a plateau and will decline by about 10%a year unilss steps are taken to arrest the decline. ONGC's investment program, therefore, contains a large financial provision for sustaining oil production action in the Bombay High field. This, together with the development of recent discoveries, is expected to offset the inevitable decline of production from existing fields. Investments during the Eighth Plan (1991-1995)are expected to amnountto about Rs 200 billion in constant terms (about Rs 222 billion in current terms), of which the proposed project

Table 33 ONGC's Investment Program, 1991 to 1995 R.-billion

Fiscalyearending March31 1991 1992 1993 1994 1995 Toal

Ongoing proects 63 1.8 1.8 0.0 C.0 9.9 Proposed projects 1.6 9.1 37.9 33.8 25.4 107.8 Other capital acquisition 5.6 6.1 1.5 1.5 1.3 16.0 Total capital acquisition 13.5 17.0 41.2 35.3 26.7 133.7

Surveys 1.4 1.3 !.0 1,0 1.1 5.8 Exploration drilling 10.7 10.1 5.3 4.0 4.7 34.8 Development drlling 5.3 6.5 4.0 4.4 2.5 22.7 Research and development 0.6 0.9 0.7 0.7 0.5 3.4

Total investments (1991 prices) 3;.5 35.8 52.2 45.4 35.5 200.4 Total investments (current prices) 31.5 37.8 57.5 52.2 42.9 221.9 of which foreign exchange expenditure 10.1 12.5 31.6 29.8 22.8 106.8 Project cost 1.3 1' 0 20.5 15.2 54.0 Percent of total capital expenditure 4.0 3 0 39.0 35.0 24.0

Notes:'Includes priceescalation Rupees62 billion of projectexpenditure vill be spentin 1996 Proiectcost excludesequipment and services for reservoirmanagement as they we considered to be operstionalexpenditures SourceONGC and Bankstaff estimates -27-

Table 3.4 ONGC Financial Projections, 1991 to 1995

Fiscalyor endingAMarch 31 1991 1992 1993 1994 1995

Volumes sold Crude ol (milL tons) 29.4 31.1 31.8 38.0 43.5 Natural gas (MMCM) 9,875 11,170 15,527 19,211 20,506 LPG, NGL,C2, C3 (mill. tons) 1.5 1.9 2.1 2.2 2.2

--- Rs biUion- - Oil revenues 62.1 65.7 67.1 80.4 92.0 Other revenues 21,7 25.1 3Z5 39.4 41.8 Total Revennes 63.7 90.8 99.6 119.8 133.8 Royalties, excise cess and sales tax 37.4 40.0 45.1 51.8 58.8 Total revenues retained 463 50.8 54.5 68.0 75.0 Total operating expenses 31.2 29.9 30.0 38.6 41.5 Operating income 15.1 20.9 24.5 29.4 33.5 Less: Interest (net) 2.0 1.7 3.5 6.9 9.3 Corporate Taxes 3.0 4.2 4.9 5.9 6.7 Net operating irpcome 10.0 15.0 16.1 16.6 17.5 Dividends 1.0 1.1 1.3 1.4 1.6 Net income retained 9.0 13.9 14.8 15.2 15.9

Key financial ratios Operating ratio (revenues retained) (percent) 67.0 59.0 55.0 57.0 55.0 Return on total equity (percent) 11.0 13.0 14.0 15.0 16.0 Returnonaveragernetflxedassets(percent) 11.0 13.0 a2.0 12.0 12.0 Return on capitalemployed(percent) 9.0 11.0 10.0 10.0 10.0 Dividend as percent of total equity (percent) 1.0 1,0 1.0 1.0 1.0 Current Ratio (times) 1.4 1.5 1.6 1.7 1.7 Long-term debt to total equity ratio (times) 0.7 0.7 0.9 0.9 1.0 Debt servicecoverage(tirnes) 3.7 4.2 2.5 1.9 2.0 Self financing ratio (percent) 179.0 100.0 36.0 45.0 78.0

Source:ONGC and Bankestimates

would represent about 24%. ONGC's investment program is summarized in Table 3.3, and details are given in Annex 3.8. The bank supports the objectives and strategy reflected in the proposed investment program. ONGC has agreed to review its investment program annually with the Bank together with the implications of this program on its financial position.

Financial Prospects 3.23 Over the next five years, ONGC is expected to continue to grow rapidly. Table 3.4 summna- rizes ONGC's projected financial performance up to 1995. Details are given in Annexes 3.9 to 3.13. The financial projections are based on the assumption that the retention price for crude oil and gas will remain unchanged. The projections show that, in spite of rising inflation rates and a gradual devaluation of the Rupee against the US Dollar and other currencies, ONGC will remain financially viable. However, ONGC will no longer generate sufficient resources to fully finance its investment program, working capital and debt service, but it is expected to have sufficient borrowing capacity to supplement its own resources and to raise foreign exchange. Also, unless the Government decides to raise producer prices, it would need to divest part of its non-oil related investment portfolio. In order to ensure that ONGC continues to remain financially viable, ONGC has agreed to maintain its cutrent ratio at 1.2 times or higher, its debt semice ratio at 1.5 times or higher and its long term debt to equity ratio at not more than 1.5. In addition to the technical risks associated with oil and gas production, there are, however, a number of factors which could easily affect ONGC's financial position and its capability to implement its investment program. - 28 -

First, with the exception of the loans from multilateral donors onlent by the Government, ONGC carries the foreign exchange risk on most of its long term debt. Its debt profile is rather uneven, and debt service is projected to double in Rupee terms by 1993 from its 1991 level and to triple by 1994. The Rupee has depreciated by an average of about 12%against foreign currencies from March to November 1990. An accelerated devaluation or an increase in local inflation in excess of the rates projected would weaken ONGC's financial position and may torce the Government to increase producer prices. The second uncer- tainty relates to ONGC's and the Government's ability to raise foreign exchange.

Financing Requirements 3.24 Table 3.5 shows the estimated financing requirements during the period 1991 to 1995. During this period, ONGC is expected to maintain an average self-financing ratio of about 78%. In the case of ONGC, this relatively high level of self-financing is crucial as a cushion against devaluation, inflation and for maintaining its sound credit rating. It is estimnatedthat, during the period 1991-1995,ONGC would need about Rs 203 billion (US$9.4 billion) in foreign exchange, about US$ 4.9 billion (52%) to cover the foreign exchange cost of its capital expenditure program and US$4billion equivalent (43%) to cover debt service, the balance (US$0.5 billion) being for operating costs. Of this amount about US$110million has been already arranged through previous loans and about US$400million from recent bond issues in Germany and Japan. An estimated US$2billion is expected to be arranged in the context of this project. ONGC plans to raise directly an additional US$3.7billion (equivalent) from external sources, primarily from export credit agencies and suppliers. The balance of about US$3.2billion would need to be provided by the Government. Given India's need to sustain investments in oil and gas exploration, it is expected that the Governm ent will give ONGC priority in its allocation of free foreign exchange. There is considerable risk that ONGC and the government will be unable to mobilize all of the projected foreign exchange requirements. If this should happen, ONCC would most likely delay investments in the Bombay offshore region, particularly in Neelam and Gandhar, and India's oil production would be substantially lower than currently projected.

Table 3.5 ONGC: Sources of Financing, 1991 to 1995 Ks .nilion

Fiscal years ending March 32 1992 1992 1993 1994 1995 Total Plercent

Funding requirements Total capital expenditures 31.5 37.8 57,5 52.2 42.9 221.9 63 Total debt service 10.8 10.4 18.9 287 29.1 979 28 Corporate taxes 3,0 4.2 4.9 5.9 6.7 24.7 7 Increase in working capital (8.5) 2.7 5.0 6,0 4.4 9.6 Total funding requirements 36.8 55.1 86.3 92.8 83.1 354.1 100

Financed by: Net internal cash generation 42.5 48.' 51.3 60.9 65.0 268.0 68 Borrowings Foreign currency loans onlent by GO! 1.0 1.3 6.7 7.3 5.1 21.4 5 Export credits and other foreign currency borrowing 13.4 13.6 27.7 29.1 23.6 107.4 27 Total borrowings 14.4 14.9 34.4 36.4 28.6 128.8 32 Total sources 56.9 63.2 85.7 97.3 93.6 396.8 100

Surplus 20.1 8.1 (0.6) 4.5 10.7 42.7 Usedfor Long term investments 19.1 7.0 (1.9) 3.1 9.0 36.3 Dividends 1.0 1.1 1.3 1.4 1.6 6.4

Source ONGC and Bankestniate - 29 -

3.25 ONGC's external resource mobilization during the 1991-95period will have to be carried out und2r substantially less favorable conditions than in the preceding period and its strategy will, therefore, have to be adjusted accordingly. In the fall of 1990,reacting to India's deteriorating external position, Moody's revised India's (and ONGC's) credit rating from A2 to BAAL.Other credit rating agencies soon followed suit. By end-May 1991, S&P's implied rating of India's long-term debt was further reduccd to BB+. As a result, India's access to external finance has narrowed substantially. Consequently, ONGC's resource mobilization efforts will have to be directed increasingly towards bilateral development assistance, multilateral and bilateral institutions as well as suppliers and export credit agencies (ECAs). The latter sources, which ONGC has tapped in the past only in a limnitedway, can still offer substantial amounts of tied long term credit.

3.26 Apart from the Bank's direct involvement in motilizing the resources for ONGC's investment program, the proposed project focuses on improving ONGCs overall project implermentation capabilities, including strengthening of relationships with export credit agencies and other international financial institutions. The financial covenants are designed to ensure that ONGCs overall financial viability will be maintained. The growing complexity of ONGCs overall future resource mobilization requirements (over and above the proposed project) as well as the need to continue its efforts to optimize its liability management, dictate that ONGC strengthen its capacities in this area. To that end, ONGC has agreed that it will retain a financial advisor who will develrp the necessary strategic resource mobilization and asset and liability management plans for ONGC and assist in their implementation, including the negotiation of the various cofinancing facilities envisaged in the proposed project.

IV. THE PROJECT

Background 4.01 The bulk of India's gas reserves is located in its Westem region, one of India's most industrialized areas. Close to 75% of total gas reserves are concentrated in the Bombay offshore area. About one-third of these reserves consist of associated gas. Unlike free gas, whose production can be controlled quite easily, the supply of associated gas depends on such factors as the rate of oil production, the geological characteristics of the reservoir and the age of the oil field. Most gas consumers prefer a stable and assured supply. When associated gas cannot be reinjected, oil companies tend to flare it, unless they are able to identify a market that Is willing to take whatever quantities of gas become available or even out fluctuating supplies of associated gas with supplies of free gas.

4.02 The Bombay High oil field is India's largest source of oil and associated gas. In 1989/90 it produced 20 million tons of oil per year and almost 30 million cubic meters (MMCMD) of gas per day. This corresponds to more than 60% of indigenous oil production and almost 7/0%of total gas production. ONGC did not anticipate that gas production would increase quite as rapidly, and did not make the necessary investments for bringing the additional gas supplies ashore. The steep increase in gas supplies is primarily the result of a drop in reservoir pressure, which was caused by delays in the implementation of measures, such as water injection, to maintain this pressure.

4.03 To slow the increase of oil imports ONGC has decided to implement a program that would increase the oil and gas production in the Bombay High oil field and simultaneously eliminate gas flaring. Under this program, ONGC is currently develuping additional oil production from the L-III reservoir in the south sector of the Bombay High oil field through infill drilling. This will require drilling of 78 production and water injection wells. In addition to the production and water injection wells, to be drilled through eight well platforms, the program will require additional process platforms with intra-field and trunk gas pipelines. ONGC estinmatesthat this will yield an additional 40 million tons of crude oil and 18 billion cubic meters (Bem) of associated gas. The program includes also similar investments to develop the -30 -

L-1l reservoir in the northern sector of the Bombay High oil field. This will be achieved by drilling 42 production and water injection wells. In addition to the production and water injection wells, to be drilled through five well platforms, ONGC plans to install a processing platform, with intra-field gas pipelines, as well as a gas feeder line to the Bombay High - Uran trunk pipeline. ONGC estimates that these wells will yield an additional 16.5 million tons of oil and 8 Bcm of associated gas. The Gas Flaring Reduction project includes those components of ONGC' wvelopmentprogram for the Bombay High oil field that are installed primarily for the recovery and transmission of gas that would otherwise be flared.

4.04 PNoJEcrDESI(;N. The basic design of the gas production and recovery components of the project is based on an optimization study for the Bombay High oilfield, which was carr;-d out by Engi- neers India l td. (EIL) in 1989. The design of the pipeline system is the result of extensive discussions with ONGC and the Gas Authority of India Ltd. The least-cost option which calls for taking all the gas that is being tlared in the Bombay High oilfield to t:le Bombay area market cannot be implemented due to the limited capacity of the Uran gas terminal which cannot be increased beyond 16 MMCMD. Construction of another terninal at Usar to process oil and gas is being studied. However such a terminal is likely to face stiff opposition from environmental groups. In addition, both ONGC and GAIL expect that land acquisition difficulties would extend the completion of the new terminal well beyond the date at which the proposed project would remain viable. Thus, ONGC decided to design a pipeline system that would take the additional gas from the Bombay High oilfield to the other available landfall point, Hazira. From Hazira the gas will be distributed through the Hazira-Bijaipur-Jagdishpur (HBJ) pipeline to consumers in Gujarat, Rajasthan, Uttar Pradhesh, Harayana and New Delhi. Annex 4.1 describes in more detail the rationale for the layout of the proposed additional pipeline.

Project Objectives 4.05 The principal objectives of the project are:

(a) to eliminate the flaring of associated gas in the Bombay High oil ficid, improve the management of the Bombay High Reservoir, in order to arrest the decline of oil production and optimize the ultimate recovery of hydrocarbons;

(b) to reduce energy shortages and improve efficiency of energy use in India's Western Region; and

Project Description 4.06 The project is designed to transport up to 25.3 MMCMD of additional gas from the Bombay High oil field to lJran and Hazira. These facilities will eliminate the flaring of gas in the Bombay High oil field and help to meet the growing demand for natural gas in the Bombay area and along the HBJ pipeline in Northwest India. The project includes an additional trunk gas pipeline from South - Bassein to Hazira and the expansion of the terminal facilities at Hazira. These two components will increase the existing transmission capacity from Bombay offshore fields, particularly Bombay High and South Bassein, from 32 to 61 MMCMD of gas and will make it possible to segregate the transmission of sweet and sour gas. To ensure that gas consumers in the Bombay area receive the volume of gas committed to them, the project also includes a pipeline from the south sector of the Bombay High oil field to the Heera oil field where it connects with the Heera - Uran trunkline. This additional pipeline will supplement gas deliveries to Uran by an additional 4 MMCMD. (Figures 1 and 2 in Annex 4.1 show the capacities of the various gas pipelines and the expected flows of gas through the pipeline system over the life of the project).

4.07 The project consists of the following components, described in detail in Annex 4.2: -31 -

(a) Construction of a process platform, SHG, in the southern sector of the Bombay High oil field with a processing capacity of 100,000barrels (bbl) of oil per day, 15 MMCMD of gas and 140,000bbl of water per day. The platform includes a 78 kilometer (km) pipeline with a diameter of 28 inchcs to the BPB platform at South - Bassein.

(b) Construction of a process platform, NQP, in the northern sector of the Bombay High oil field, with a processing capacity of 60,000bbl of oil per day, 6.8 MMCMD of gas and 90,000 bbl of water per day. The platform includes a 30 km pipeline with a diameter of 18 inches to the BHN - Uran gas trunk pipeline.

(d) Construction of a 142 km gas pipeline, (26 - 36 inches) from the existing process platform, ICP, in the southern sector of the Bomoay High oil field to the Heera - Uran trunk pipeline.

(e) Construction of a 255 km trunk gas pipeline (42 inches) from South - Bassein to Hazira.

(f) Expansion of the existing Hazira gas terminal.

(g) Engineering, project management and other implementation services.

(h) Implementation of a package of measures, in the Bombay High oilfield, required by proper reservoir management practices.

(i) Reservoir performance and management studies and training.

(j) Implementation of a package of measures to reduce the environmental risks and enhance the safety of offshore operations.

4.08 The project will substantially increase the availability of gas in the Bombay area, in Hazira (Gujarat) and along the HBJ gas pipeline, which brings gas from India's west coast to industrial areas in Rajasthan, Harayana, Uttar Pradesh and New Delhi. To offset a declire in the availability of associated gas, the project will give ONGC the flexibility to bring additional free gas from the South Bassein gas field ashore. This will provide consumers with an assured supply of gas, which will replace naphtha in fertilizer production, middle distillates in the generation of peak-load power and coal in base-load power generation. The project will also contribute to an increase of oil output in the Bombay High oilfield.

Implementation 4.09 ONGC will be responsible for the implementation of the project. During all phases of project design and implementation, ONGC will be assisted by Engineers India Ltd. (EIL). EIL is the largest and most experienced engineering firmnin the oil and gas production and processing field in India. EIL, in tum, has collaboration arrangements with experienced international engineering firms. ONGC requires that all its offshore structures and facilities, including pipelines, meet international standards and receive certificates to that effect from recognized certification companies. These services will be provided by Engineers India Certification Agency.

4.10 The organizational arrangements for the implementation of the project are shown in Annex 43. Because of the large size of the individual project components, ONGC is managing the implementation of the project in terms of four separate subprojects: (a) facilities in the northern sector of the Bombay High oilfield; (b) facilities in the southern sector of the field; (c) construction of the pipelines extending from platform ICP (in the Bombay High oil field), to the Heera oil field and from the South - Bassein gas - 32 -

field to the Hazira gas terminal; and (d) the expansion of the Hazira gas terminal. Fach of these subprojects will be headed by a project manager with a separate task force and support services. The subproject managers of project components (a), (b) and (c) will report to the Officer on Special Duty (OSD) (Engineering & Construction) (E&C) and that of (d) will report to the Group General Manager (GGM) (Hazira). OSD (E&C) and GGM (Hazira) will report to the Regional Director, Bombay Regional Business Center (BRBC)who will have the overall responsibility for the implementation of the project in BRBC.To ensure maximum coordination in the implementation of project components, subprojects (a) - (d), in the Bombay High oilfield, ONGC has agreed to appognt an officer (OSD) who acts as the overall project co- ordinator and who will be responsible for the implementation of these components. In addition, ONGC has agreed to establish Project Implementation Units for each of the four sub-projects.

4.11 Implementation of the four subprojects will be the respotisibility of ONGC's Regional Office in Bombay. With the implementation of the Bombav Offshore projects, phase I of the South Bassein Developrnent project (Ln.2241-IN),and the Western Gas Development project (Ln.2904-IN),the office has demonstrated its ability to effectively manage the implem'entation of large-scale offshore projects. Its management team has been exposed to all phases of offshore development. As a result, it has been able to put together a well-structured organization with staff sufficiently trained to implement this project.

4.12 To simplify procurement and reduce the risk of implementation delays, maximum use will be made of single responsibility turnkey contracts. The items that will be procured under the project have been grouped in 19 packages. With the exception of six packages for the expansion of the Hazira gas terminal and three packages for platform modifications, each package will be procured on the basis of a single responsibility turnkey contract. Under these contracts the responsibility of the contractor extends from detailed engineering to commissioning and final acceptance by ONGC. The single responsibility approach was chosen-as is the case with similar offshore and onshore work in India--because specialized contractors with thc necessary experience and resources offer the greatest chance for the expeditious execution of contracts in spite of weather and construction risks. (The single responsibility approach would have been impractical for the expansion of the Hazira gas terminal, tie platform modifications, the environmental component and the implementation of measures to improve the reservoir managemnentof the Bombay High oilfield, since implementation of these components requires close interaction with the management of existing facilities. ONGC would be in a better position than contractors to ensure the timely implementation of these components).

4.13 Annex 4.4 shows the major stages of project implementation. The Bank's staff u.:stimatesthat ONGC will be able to complete the project in five years. The estimate of the Bank's staff takes into account ONGC's experience with the implementation of similar projects. Delays in Government approvals, in particular environmental clearances, difficulties in obtaining land and procurement delays have been the main causes of slippages in project implementation in the pist. The complet.on time estimated by the Bank's staff is considered realistic, particularly in view of the advanced stage of procurement preparation. The Bank has reviewed the engineenng design of the bid packages and found tihemacceptable. Because of the extreme sensitivity of the economic viability of the project to delays in project implementation, ONGC has agreed to arrangefor ar 'iew of its procurement andproject implementa'ion organization, discuss the results of this reviewvwit the Bank and implement its recommendations.

Status of Project Preparation

4.14 The project is in an advanced stage of preparation. Conceptual and optimization studies, which form the groundwork for the project, and basic design and engineering have been reviewed by the Bank and found satisfactory. Also, bid packages for procuring the major project components have been completed and forwarded to the Bank. These documents are technically satisfactory. - 33 -

Environmental and Safety Issues 4.15 Offshore oil and gas operations are hazardous to the environment and the personnel involved. While the risks cannot be completely eliminated, they can be minimized. While the Governmenit has not yet adopted legislation that would govern safety concerns of oftshore operations, 0NGCd eals with these issues effectively through compliance with international safety standards. With regard to the proposed project, the Bank's environmental and safety'specialistfound that the recovery of gas and the transmission of gas to shore poses minimal environmental and safety risks. Construction of the platforms and the laying of the pipelincs will not result in any lasting disturbance of marine life. 4.16 ENVIRONMENTAl. AND SAFFIY LECISLAnON. India has no legislation that deals specifically with offshore safety. In 1985ONGC adopted a Recommended Code of Practice for its offshore operations. This Code is based on best practices adopted elsewhere. By following this Code, ONGC complies with relevant international safety standards and maritime regulations. ONGC observes all of the safety standards for offshore drilling and production platforms of the American Petroleum Institute and relevant rules of the American Bui eau of Shipping (ABS),Britain's Lloyd's Register of Shipping and Norway's Det Norske Veritas. Each platform is equipped with sufficient survival craft to accommodate all of the men at work at any time, In addition, India is a signatory to the Safety of Life At Sea (SOLAS)convention. T'he Mercantile Marine Department is responsible for meeting the norms established by SOLAS.

4.17 Legislation regarding the protection of the environment is contained in the Environment (Protection) Act of 1986. Under the Act, ONGC has agreed to comply with the spirit of the legislation. As part of this agreement, ONGC is required to obtain clearances for all of its projects from the Ministry of Environment and Forests (MOEF). Before clearing any new projects, MOEF now requires the preparation of environmental impact assessments, environmental management plans and disaster maniagement plans.

4.18 ONGC's ARRANGEM1N-MSFOR ENVIRONMFNT AND SAiFEY. In order to be able to complv with environmental and safety regulations, ONGC has set up a Safety and Environrnent Management Group (SEM).The primary objective of this group is to monitor compliance with regulatory and other requirements. Ihe Group provides technical advice on environmental and safety issues to line managers. The ultimate responsibility for the safety of personnel and environmental protection within each region rests with the Board member responsible for that region.

4.19 The SEM groups receive technical support from a number of Indian organizations. The Indian institute of Petroleum Safety and Environment Management (IPSEM; has been set up by ONGC to provide training in the areas of offshore safety and environmental protection. The Institute of Engineering and Ocean Technology (JEOT) has also been set up by ONGC to assist SEM Groups in the safety evaluations and risk assessments of oftshore operations. The National Environmental Engineering Research Institute (NEERI), is a public sector institute and, as such, part of the Council for Scientific and Industrial Research (CSIR).NEERI prepares all baseline environmental studies and environmental impact assessments for ONGC's offshore projects and operations.

4.20 ONGC's SAFETY RFCORD.The Bank's staff reviewed ONGC's accident statistics an.1 roundl that its performance in this area could be substantially improved. ONGC has agreed to carry out a safety auditfor its entire offshore operations, discuss the results with the Bank and implement the recommendations. With regard to the proposed project, ONGC has further agreed to carry out a safety enginee-ing study for the existing platforms that will be linked to the facilities to be constructed under the project, as well as a supplemental environmental assessment disaster study for all new and associated existing facilities. ONGC has agreed to retrofit existing platforms linked to the project, if necessa, y, to bring them in line with the recommendations of the safety study. The design of the new platforms and pipelines will include all safety engineering aspects as well as the recommendations of the supplemental disaster assessment study. - 34 -

4.21 PNoprcrRELATFI) CONSIDFRATnONS. NEERI has prepared an Environmental Impact Assessment report (EIA) for the proposed project components in the northem and southern zones of the Bombay High oilfield. The report has been reviewed by the Bank's staff, which agreed with its overall conclusions. These conclusions suggest that the environmental impact of the proposed project will be within acceptable levels, if ONGC observes the suggested safeguards. The report points out that there may be, in fact, a net improvement in the quality of the environment as a result of the substantial reduction of gas flaring. Key environmental and safety concems are highlighted in the following paragraphs:

(a) UIQUID Ei'FLUiENTS.Discharges of liquids from production platforms consist of produced water, sewage and deck drainage. Produced water is treated prior to discharge overboard. The treatment ensures; that the oil content falls within a range of 25 to 50 parts per million. Treatrment is monitored by the Central Pollution Control Board at a sufficient number of sampiing points. After treatment, the effluent is discharged at a depth of 40 to 50 meters, wihichensures dilution to about 20 parts per billion within one kilometer of the platform. Treatment plants are provided to handle sanitary water and sewage. These plants ensure that the treated sewage meets the standards stipulated by the US Coast Guard. Again, these discharges are monitored by the Central Pollution Control Board. Deck drainings are routed to the nroduced water treatment facilities.

(b) SOIIDWASTES. The only significant source of solid wastes on a production platform are kitchen wastes. These should be either ground and disposed of in the sea, or transported to the shore for disposal.

(c) NOISEAND VIBRAIION. Protection against the noise and vibration caused by equipment on the platforms will be addressed in the Bank's review of the design of the platforms, in particular the living quarters. The other major source of noise on an offshore platforn is the flare. By reducing the flaring of gas, the project will also eliminate a major source of noise on offshore platforms in the Bombay High oilfield.

(d) DiSRUv0ONOF MARIINE LIFE.. Construction of the platforms will initially disrupt the seabed conditions in their vicinity. The same is true for the laying of the high pressure gas trunklines. However, these disruptions will be neither severe nor permanent. Marine growth on offshore structures is likely to result in a localized increase in the range and quantity of miarine life.

(e) DISAS`TERENVIRONME.N`AL PRO.CrTION. The potential sources of major oil spills on a production platform are limited to large failures of the process equipnent or the oil/well fluid risers. In the event of a substantial process leak, the platform would be quickly shut down and the source of the leak isolated. In the event of a riser failure, the leak may continue for some time. ONGC is equipped to deal with oil spills of up to 400 tons of spilled oil per day. To this end, ONGC has deployed five multi-purpose support vessels in the Arabian Sea. Two of these vessels carry containment booms and oil skimmers. Additional equipment for containing oil spills is stored ashore. The Indian Coast Guard has the capacity to deal with oil spills of up to 300 tons per day. However, ONGC and the Coast Guard would not be able to cope with a major oil spill. Following the recommendations of the appraisal mission, ONGC agreed to prepare contingency plans for such an incident, wliich would involve support from international oil spill control centers. The necessary investments would be financed under the proposed project.

(f) LEAKAGEFROM GAS PUIELINES. Since the gas transported in the pipelines to be constructed under the project consists mainly of methane and does not have a significant concentration of hydrogen sulfide, even a large release of gas into the atmosphere will not have a significant -35 -

Table 4.1 Project Cost Estimate

Foreign Lxal TotJ Foreign L1al Total Foreign Costcomponents Exdwnge ----- Rs million-- -- USS milion--- Percent

Processplatform, NQP 4,516 1,084 5,600 209.0 50.2 259.2 81 Compressors,St C 2,612 627 3,239 125.0 30.0 155.0 81 Processplatform, SHG 5,001 1,200 6,201 230.0 55.2 285.2 81 Unepipe,SlGC-BPB 1,195 359 1,554 58.0 17.4 75.4 77 Laying,coating and wrapping,SHC-BPB 229 1,544 1,872 15.7 6.1 21.8 72 Platformmodifications 1,362 327 1,69 63.3 15.2 78.5 81 Linepipe,ICP-lleera 1,443 433 1,876 70.0 21.0 91.0 77 Laying,coating and wrappingICP-Hieera 2,067 496 2,563 97.0 23.3 120.3 81 Lirepipe,BPB-iazira 4,941 1,4U; 6,424 220.0 66.0 286.0 77 Laying,coating and wrapping,BPB-Hlazlra 2,899 696 3,595 129.3 31.0 160.3 81 ExpansionHazira gas terminal 6,130 4,850 10,980 2753 217.8 493.1 56 Reservoirmanagement, services and equipment 1,355 1,239 2,593 67.4 61.7 129.1 52 Engineeringand projectmanagement 159 477 637 7.5 22.5 3Q0 25 Studiesand training 43 13 55 2.0 0.6 2.6 77 Environmentalcomponent 304 139 444 14.7 9.8 24.5 60 Basecost (1991 prices) 34,357 14,966 49,323 1,54.2 627.7 2,211.9 72 Physicalcontingendes 3,436 1,497 4,932 158.4 62.8 221.2 72 Pricecontingencies 5,261 4,531 9,792 239.5 205.8 4453 54 Totalproject cost 43,054 20,993 64,047 1,982.1 8963 2,S78A. 69 Interestduring construction 4,341 2,165 6,506 204.1 101.8 305.9 TotalFinancing Required 47,395 23,159 70,554 2,186.2 998.1 3,184.3

Note:Baseline cost include customs duties of USS374.4 million equivalent ONGCcharges interest during constructixn tooperatons

impact on the environment. (Annex 4.5 contains a more detailed description of the environmental aspects of the project).

Project Cost 4.22 The project is estimated to cost US$ 2878 million, including physical and price contingencies as well as taxes and customs duties on imported materials and equipment of US$ 374.4 million (Table 4.1). A breakdown of year-by-year project costs appears in Annex 4.6. The proposed Bank loan of US$ 450 million represents 22.7%of the estimated foreig. exchange cost.

4.23 Estimated project costs are expressed in mid-1991 prices which have been derived from recent contracts and similar modification work. Physical contingencies of 10% of base costs have been includeJ. Local price contingencies have been estimated at 8.3% in 1991,6.6% in 1992,6.5% in 1993 and 1994 and 6.2% in 1995 and 1996. Foreign price contingencies have been estimated at 3.4% of the respective base costs pluS physical contingencies. Taxes and customs duties on imported goods and services have been estimated on the basis of average rates provided by ONGC. - 36 -

Table 4.2 FinancOnt Plan USSmillion

Sourceof Finance local Foreign Total Percent

World Bank 450.0 450.0 14.2 AsiainDevelopment Bank 300.0 300.0 9.4 Export-Import Bank of Japan' 350.0 350.0 11.0 Export/supplier credits 745.6 745.6 23.4 ONGC 996.1 340.6 1388.7 42.0

Total 996.1 2,186.2 3,1843 100.0

'GO'srequest for finarndrgis currentlyunder study by J-EXIM

Finars'ing Plan 4.24 The proposed project represents about 24%of ONGC's investment program for 1991-95. Unlike many of its other investmnents,69% of the total cost of the proposed project would be in foreign exchange. ONGC will have no difficulty meeting the local cost component (31% ot . al cost) from internally generated cash. Tre principal sources of foreign exchange for this project would include the World Bank, the Asian Development Bank, the Export-Import-Bank of Japan as well as export credit agencies and suppliers. However, since ONGC does not earn foreign exchange, it would have to cover the remaining foreign exchange costs through external borrowing or from the Government's free foreign exchange reserves. ONGC has requested the Bank's assistance in nobilizing the foreign exchange required under the proposed project.

4.25 The financing plan for the proposed project, which has been agreed with the Government and ONGC, is summarized in Table 4.2. A detailed financing plan for the proposed project is contained in Annex 4.7. This plan has been developed on the basis of an extei,sive analysis of the financing alternatives currently available to ONGC. Since the bulk of foreign exchange rquirements would have to be met from sources other than the Government or untied private loans, the procurement packages were designed to attract the maximum amount of cofinancing from suppliers and export c edit agencies. Based on the interest shown by the export credit agencies and suppliers, the Bank's staff estimates that about US$ 746 million or 34% of the total foreign exchange requirements could be met in this manner. To meet the remaining foreign exchange requirements, the Govemrnent decided to seek cofinancing from the Asian Development Bank (ADB)and the Export-Import Bank of Japan (J-EXIM).The ADB has included financial support for this project in its program for FY92.GOI's request for untied cofinancing is currently under study by J-EXIM.

4.26 The Bank plays a crucial catalytic role in arranging the financing for this project, at a time when India's credit rating has come under pressure. Taking into account the importance of this role and the amount of cofinancing the pr lject is likely to attract, a Bank loan of US$ 450 million equivalent is proposed. The loan, which will b madedirectly to ONGC on the Bank's standard termsfor India, will be guaranteed by the Government. The Government will charge a guarantee fee of 1% p.a. on the outstanding amount of the Bank loan. The foreign exchange and variable interest rate risks will be borne by ONGC.

4.27 Based on an assessment of the likely interest of cofinanciers in the various procurement packages and the Bank's interest in providing technical assistance, the following project components were selected for Bank financing: - 37-

(a) construction of the process platfornm,NQP;

(b) installation, coating and wrapping of the of the pipeline from SHG to BPB;

(d) procurement of equipment and services for the proper management of the Bombay High oilfield;

(e) the financing of the cost for engineering and project management; and

(f) studies and training. Table 4.3 Summary of ProcurementArrangements USSmillion

Procuemet Method ProjectComponents ICB Other N.A. " Total

Process platform, NQP 282.1 50.2 332.3 (261.0) (261.0) Compressors, SHG 163.4 b/ 30.0 193.4

Process platform, SHG 312.0 b/ 552 367.2

Linepipe, SHG-BPB 76.1 b/ 17.4 93.5

Laying, coating and wrapping, SIIG-BPB 23.7 3.8 27.5 (19.2) (19.2) Platform modifications 85.1 15.2 100.3 (78.8) (78.8) Linepipe, ICP-K-eera 91.8 b' 21.0 112.8

Laying, coating and wrapping, ICP-Heera 1292" 23.3 152.5

Linepipe, BPB-Hfazira 313.8 b/ 66.0 379.8

Laying, coating and wrapping, BPB-Hazira 180.5 ' 31.0 211.5

Expansion Hazira gas terminal 613.4 57.8 671.2

Reservoir management, services and equipment 161.3 161.3 (79.3) (79.3) Engineering and project management 40.6 40.6 (9.2) (9.2) Studies and training 33 33 (2.5) (2.5) Environmental component 27.7 "/ 3.5 31 2

Total 1,169.5 1,344.5 374.4 2,878 4 Bank loan (4383) (11.7) (450.0)

Note: Rgures in partheses are the respective amounts financed by the Bank ' Taxes and duties ' Export ad suppliers credits ADB procuremnentprocedures -38-

Procurement and Disbursements 4.28 Table43, which sumnmarizesthe procurementarrangements, shows that about US$1.2 billion worth of goods and serviceswill be procured in accordancewith the Bank'sguidelines for international competitivebidding. This is equivalent to about 41%of total projectcost. The Bank'sloan of USS 450 millionwill financeabout 38%of the cost of items procured under ICB.Procuremnent under limited IntemationalCompetitive Bidding (LICB), financed by supplers'or export credits, is expected to amount to about US$957million (for a descriptionof LICB,see Annex4.4). Consulting services will be obtained by ONOC in line with the Bank'sguidelines for the use of consultants.It is expectedthat the components financedunder an untied cofinancingfacility currently under study by the Export-ImportBank of Japan would be procured through ICBin line with World Bankprocurement guidelines. The procurementunder the proposed Asian DevelopmentBank loan v Id be carriedout under its guidelines. 4.29 The Bank'sloan will provide financingfor three major packages.Considering the small number of packages and their large amounts, prior Bankreview of all essentialprocurement documentation will be required. In view of the fact that timelyimplementation is criticalfor the viabilityof the project,ONGC has submitted the documentationfor all packages to the Bankfor review.For items to be financedby the Bank,the Bank'sstandard domesticpreference provisions will, at ONGC's option, apply for the evaluationand comparisonof bids. 4.30 Given the urgency to complete the proposed projectas scheduled,ONGC has started the procurementprocess for the process platformSHG, the compressorsand the linepipe for the pipeline connectingplatforn SHG with platformBPB. In addition,ONGC has incurred substantialexpenditures in the contextof implementingmeasures to improve the reservoirmanagement of the BombayHigh oilfield. Dependingon the pace with which these measuresare implementedand contractscan be finalized,up to US$45million of retroactivefinancing by the Bankmay be required. ONGC has requested the Bankto review all packages for which advance contractingmight apply. The appraisal missionhas made specific recommendationsto ONGC in order to bring the packagesin line with the Bank'sguidelines. ONGC nas revised the packagesaccordingly.

4.31 The phasing of the projecteddisbursements of the Bankloan is shown in detail in Annex4.8 and summarizedin Table4.4: Table 4.4 Phasing of Disbursements US$ million

Yelr I Yar 2 Year3 Yar 4 Yegr5 FY92 FY93 FY94 FY95 FY96

Annual 111.1 139.4 135.0 61.0 3.5 Cumulative 111.1 250.5 385.5 446.5 450.0

Source: Buik stff projectons 432 Disbursementof the proposed Bankloan is based on the assumption that the loan will becomeeffective by the end of the first quarter of FY92.It is expected that the loan will be completely disbursed by December31, 1995.While the disbursementperiod of five years is substantiallyshorter than would be indicated by the Bank'sexperience with similaroil and gas projects,the advanced state of projectpreparation and procurementmakes this a realisticassessment. ONGC and the Govemmentare fully aware that slippages in the implementationof the projectwould jeopardizethe viabilityof the project.ONGC has worked closelywith the Bankto minimizethe risk of implementationdelays and thus delays in the disbursement of the Bank's loan. Based on the projected schedule of expenditures a closing datefer the Bank's loan of December 31, 1995 has been established. - 39-

Table 4.5 Allocation of the Proposed Bank Loan

Category USSmillion Percentngeof Fxpnditures Financed

Process ' ilitiesand pipeline systems (a) equipment and materials 325.0 100%of foreign expenditures and IOOYof local expenditures (ex-factory cost) (b) erection/installation and rig hire 90.0 100%of foreign expenditures and 90% of local expenditures (c) supervision and specialized services 10.0 100%of expenditures Consultant serviees 5.0 100%of expenditures Unallocated 20.0 Total 450.0

4.33 To facilitate disbursements a Special Account would be established with an authorized allocation of US$25 million, which is equivalent to about four months of average disbursemrents. Disburse- ments for consultant services and training under contracts valued at less than US$ 100,000would be made on the basis of Statements of Expenditure (SOE). Documentation of SOEs would be retained by ONGC and made available for review by Bank supervision missions. All other disbursemrents would be made against full documentation. The Bank's loan will be disbursed against the categories outlined in Table 4.5.

V. FINANCIAL AND ECONOMIC ANALYSIS

Project Benefits 5.01 The proposed project consists of a slice of ONGC's investment program which aims at increasing oil output from the Bombay High oilfield. As an integral part of this project, the Gas Flaring Reduction project will finance investments that will allow ONGC to recover, compress, transport, and process gas onshore. The gas recovery and compression facilities serve two purposes, to increase oil output through 'gas lift' and to provide the necessary pressure for transporting gas to users onshore. Furthermore, the pipeline and onshore gas processing facilities that will be constructed under the project will make it possible to take gas from other offshore oil and gas fields, - South Bassein, Heera and Neelam, and Panna and Mukta - to onshore markets.

5.02 The investments under the proposed project will eliminate the flaring of about 12 MMCMD of associated gas and contribute to an increase of oil production by about 3 -4 million tons a year in the Bombay High oilfield. It is estimated that over the life of the project (1991 - 2010) an additional volume of about 64 billion cubic meters of gas will be produced which. at current gas prices of Rs 1,500 per 1000m3 and exchange rates, represents a financial value of US$ 5 billion. This additional gas will replace liquid petroleum products (mainly naphtha) in petrochemical and fertilizer industries, middle-distillates in peak-load power generation, and coal and fuel oil in industrial uses and base-load power generation. As such, the project will reduce India's petroleum import requirements and the consequent drain on foreign exchange; it will also reduce the demand for coal in the western region, the need of additional rail transport capacity for coal and the environmental pollution associated with the use of coal. The project will also make it possible for ONGC to increase oil production in the Bombay High oilfield. Over the life of the project these investments will add about 60 million tons of oil. Valued at US$20per barrel, this would represent a financial value of about US$8.2billion. -40 -

ProjectFinancial Analysis 5.03 Annex 5.1contains the detailed assumptions and Annex 5.2 the calculations of the financial rate of return of the project.This calculationis basedon the capital and operating costestimates contained in the projectcost tabic, including physicalcontingencies and local taxesand duties. The revenuesfrom sales of incrementalgas are valuedat Rs1,500 per 1000ml for the basecase. All inputs havebeen valued in constant1991 terms.

5.04 Table5.1 summarizes the financial internalrates of returnfor thebase case and the results of the :nsitivity analyses.

Table 5.1Financial Rate of Return:Sensitivity Analyses

Assumption InternaJRate of Return Percent

Base Case (Gas pnce Rs 1,500/100(0Xm) 17.5 Gas price 10% lower 14.6 Gas price 25% lower 9.8 Rcvenuei delayed by one year 14.0 Reveenuesdelayed by two years 11.7 Revenuesdelayed by three years 9.9 Capital costs 10%.higher 14.9 Capital costs 25% higher 11.5 (Capital cost including. I IBJ upgrade and pi ice Rs 2,250 per I (CUml 22.9

.)x)urceBank staff estcmates

5.05 The sensitivity analysesshow that the financial rate of return is quite sensitiveto implernen- tation delavs suggestingthe needfor efficient projectimplementation (para.4.13).

Project EconomiicAnalysis 5.06 For the economicanalysis, natural gas hasbeen valued on the basisof the fuel which it replaces.For the purposesof projectevaluation, it has beenconservatively assumed that all gasreplaces fuel oil, the lowest valued replacement.Even where gasreplaces coal in power generationor industrial uses,the economiccost of coal,either imported or supplied by indigenouscoal iields is roughly at par with the costof imported fuel oil.

5.07 Annexes5.3 and 5.4show the detailodassumptions and calculationsof the economicrate of return of the project.The projectcost estimates are in constant1991 dollars, net of taxesand duties.The standardconversion factor of 0.8has been applied to the costof the local componentof the project to br. ng it to the level of border prices in India. Physicalcontingencies of 10%of the basecost estimatehave also beenincluded. CIF costshave beenused in calculatingthe costof the foreign exchangecomponent.

5.08 The operating costsare basedon ONGC'sexperience with similar installationsand represent overall about 2% of the estimatedcapital cost.This appearslow for estimatesin the offshoreoil industry but can be explainedby the comparativelyhigh proportion of pipeline investmentsfor which repair and maintenancecosts are not as high as for platform and other investments.ONGC estimates that 1% of the capital cost is appropriate for pipeline repair and maintenance.For all other Investmentsthe correspondingpercentage is 3% Annex5.1 showsthe detailcd calculationof the operatingcost of the project. -41 -

5.09 The project benefits (natural gas) have been valued at equivalent fuel oil prices expressed in constant 1991 terms. Fuel oil prices were projected on the basis of crude oil price projections issued by the Bank's International Commodity Markets division. The detailed calculations of the prices for the fuel oil equivalent for gas in India are shown in Annex 5.2.

5.10 The output created by the project consists of about 64 billion cubic meters of natural gas of which 29 billion would have to be flared without the project. Marketia. .ofthis incremental gas will be carried out through the terminials in Hazira (in the State of Gujarat) and LJran(in the Bombay area). The flow of incremental gas through Hazira requires strengthening of the HBJ gas pipe line. The cost of these additional investments are included in the cost/benefit stream of the economic rate of return calculation. The annual incremental production of gas will start in 1994 with a mnodest3.6 MMCMD of gas due to the capacity limitations of the Uran terminal. In 1996additional gas supplies are expected to increase to 24.6 MMCMD. From then on, supplies will decline due to the gradual exhaustion of the Bombay High oilfields. Additional finds are expected to make up for the decline in gas supplies from this major oilfield shortfall.

5.11 When converting to natural gas there are further economic benefits in the formnof reduced storage and handling costs, reduced maintenance costs as well as lower pollution. Additional benefits result from the increased thermal efficiency of natural gas relative to liquid fuels. Although the mnagnitude of these savings varies from industry to industry, their total impact can be substantial. These benefits were not included in the benefit-cost analysis.

5.12 As menrionrt.dabove, the project contributes also to an increase of oil output from the Bonibay Hiighoilfield, which amounts to about 60 million tons of oil over the 19 year 'life-time' of the project. Again, the value of this contribution of the project was not taken into account in the evaluation of the economic rate of retLrn.

5.13 Without these additional benefits, the proposed project would yield an economic rate of return of 30%, As mentioned in paragraph 5.05 with respect to the financial rate of return, the econonmic return is equally sensiti e to slipoages in project implementation. A delay in project implementation by one year would reduce the rate of return to about 24%, by two years to about 20%. Any further delay would be likely to render the project nonviable.

5.14 The sensitivity analysis made resulted in the following rates of return:

Table 5.2 Economic Rate of Return: Sensitivity Analyses

Assumptions Internal Rate of Return Percent

Base Case 30.3 Gas orice10% lower 26.7 Gas price 25% lower 21.0 Revenues delayed by one year 24.3 Revenues delayed by two years 20.5 Revenues delayed4 by three years 17.7 Capital costs 10% higher 27.1 Capitalcosts 25% higher 23.0 Volume 6% higher (365 instead of 345 days) 32.3

Source Bank staff estimates -42 -

Project Risks 5.15 The projectfaces three najor risks: (i) delays in the implementationof the projectwhich would quickly reduce its viability; (ii) delays in the offtakeof the additional gas that will be made availablethrough the project; and (iii) the possibilitythat ONGC will not be able to raise the foreignexchange required for the project.This risk is aggravatedby the fact that India's credit worthinesshas sufferedre- cently. 5.16 To minimizethe risk of implementationdelays, ONGC has agreed to award the construction of najor items,such as platforms and submarine pipelines,on the basis of a seriesof contractsunder single responsibility.In addition, ONGChas worked dosely with the Bank to streamlineits organization and managementfor the implementationof projects.The bidding documents for all major componentsof the projecthave been reviewed by the Bank.(para 4.14). 5.17 The risk of delays in the offtakeof the gas will be significantlyreduced through the Government'sdecision to set up a specialmonitoring committee in the Departmentof Petroleumand Natural Gas that will review quarterly the progress in implementingthe proposed projectas well as the projects that will utilize the additional gas supplies.The quarterly reports of the monitoringcommittee will be submitted to the Bankfor review together with recommendationsin case of any slippage in project implementation.The Bankwill have an opportunity to review the implementationof these recommendations. 5.18 To minimizethe risk that difficultiesin the financingof the foreignexchange components delay the project,the Bankhas engaged in extensiveconsultations with ADBand J-EXIMand has worked closelywith ONGC and the Governmentto ascertain the availabilityof financefrom export credit agencies and suppliers.The Government'srequest for untied co-financingfrom J-EXIMis currentlyunder study by J-EXIM.In the unlikelyevent that J-EXIMis unable to participatein the financingof the project, the Bank will assist ONGC in mobilizingcredit from other export credit agencies. 5.19 While technicalrisks are higher for offshorethan for onshore projects,ONGC has accumulated considerableexpertise in carrying out projectsof this kind. In addition, all major projectcomponents will be carried out by experiencedcontractors on a turnkey basis. Thus, the proposed projectposes no significanttechnical risks.

VI. AGREEMENTSAND RECOMMENDATION

6.01 AGREEMENS.The followingagreements have been reached:

(a) With the Government that it will: (i) implementa gas pricing policy which links domesticgas prices to intemationalprices of fuel oil and discuss, with the Bank,any revisionsof this pricing policy (para. 2.31- 2.32); (ii) set up a body in the Departmentof Petroleumand Natural Gas to monitor,on a quarterlybasis, the implementationof oil and gas field developmentsand revisegas production plans accordingly;this body would monitor,also on a quarterly basis, the -43 -

progress in constructionof plants and other facilities(pipelines, gas processng facilities.etc.) required for the projectedofftake of gas. The body will issue a quarterly report, listingany deviation from the plans of gas producers and potential consumers and containing recommendationsfor steps to be taken to ensure the efficientuse of projectedgas supplies. Copiesof these reports would be submitted to the Bankfor review (para. 2.15); (iii) submit annual reports to the Bankindicating changesin gas allocationsand their imputed or net-backvalues (para. 2.19).

(b) With the Oil and Natural Gas Commissionthat it will: (i) review annually with the Bankits investmentprogram and the implicationsof this program on its financialposition (para. 3.22); (ii) naintain its current ratio at 1.2tines or higher, its debt-servicecoverage ratio at 1.5 timesor higher, and its debt-to-equityratio at no more than 1: 5 (para. 3.23); (iii) have its annual accountsaudited by an independent auditor acceptableto the Bank within nine months of the end of the fiscalyear and provide the Bankwith unaudited financialstatements (incomne statements, funds flow statementand balancesheet) within six monthsof the end of the fiscal year (para. 3.11); (iv) retain the servicesof a financialadvisor for mobilizingforeign exchange resources (para. 3.26); (v) establish Project ImplementationUnits for each of the four sub-projects,and appoint an overallcoordinator (OSD) for the purposes of the Bankproject (para. 4.10); (vi) carry out a review of its procurenent and projectimplementation organization, discuss the resultsof this review with the Bankand implementits recommendations (para. 4.13). (vii) carry out a safety audit for its entire offshoreoperations, discuss the results with the Bankand implementthe recommendationsof the audit (para. 4.20); (viii) carry out a safetyengineering study of existingplatforms linked to facilitiesthat will be constructedunder the project,discuss the results with the Bankand implementthe recommendationsof the study (para. 4.20); 6.02 The followingare conditionsof effectivenessof the proposed loan: (i) announcementinviting domestic and foreignoil companiesto participate in a fourth round of bidding for offshoreand onshore parcels selectedby GOI for exploration (para. 3.08); (ii) obtaining of the environmentalclearance for all componentsof the proposed project (para. 4.13);and (iii) establishingof a body in the Departmentof Petroleumand Natural Gas which would monitor the implementationof gas supply and utilizationplans (para. 2.15).

6.03 RECOMMEW4DATION.On the basis of the projectjustification and the agreementsreached during negotiations,the proposed projectwould be suitable for a loan of US$450million equivalent to the Oil and Natural Gas Commissionfor a period of 20 years, includingfive years of grace, at the Bank'sstandard variable interest rate. The loan would be guaranteed by the Govemmentof India.

-45 -

INDIA Annex 1.1 GAS FLARINGREDUCTION PROJECT Page-T6m Energy Balances, 1980-81to 1988-89

Trends in availability and consumption of commercial energy, 1980-81to 1988-89 Milijo ton esof oil equiwtnt

Fiscal Gross Conmrion Net Othrr No"- Years eavilabzity tlosses awilability AgricultureIndustry Trensport RtsidentiWene"usew energy uJs

1980-81 92.623 23.859 68.764 1.625 36.861 17.443 5.637 1.901 5.297 1981-82 101.411 26.567 74.844 1.624 40.607 17.787 6.258 2.042 8.526 1982-83 109.023 28.552 80.471 1.861 44.607 18.758 6.820 2.127 6.680 1983-84 114.944 31.261 83.68. 1.687 46.265 19.655 7.250 2.214 6.412 1984-85 121.510 34.997 86.513 2.131 46.595 20.309 8.038 2.341 7.099 1985-86 131.425 38.028 93.397 2.309 50.059 21.719 8.773 2.488 7.969 1986-87 141.187 40.927 100.260 2,807 53.423 22.789 9.532 2.677 9.032 1987-88 149.241 47.654 101.587 3.630 51.261 24.476 10.375 2.953 8.892 1988-89 163.606 52.621 110.985 3.861 56.214 26.055 11.532 3,684 9.639

Source:Compled from energy baldnce -46 -

INDIA Annex 2.1 GAS FLARING REDUCTIONPROJECT Page 1 ofT2 Gas Production Projections

1. GASPRODUCrION. While associated gas production is controlle by the rate of oil production, frec gas can be used as required up to the capacity limit of the wells, pipeline system and processing plants. The gas caps overlying the oil cannot be drawn on until the oil has been exhausted, otherwise the amount of oil recovered will be diminished. In order to project India's gas production, it is necessary to make certain assumptions regarding construction and implementation of development programs to be carried out by ONGC and GAIL. Since there are no facilities for storage of natural gas in India, apart from the limited amount which can be accommodated by building up pressure in the pipelines (line-pack- ing"), and given that India is a net importer of oil, it must be assumed that all oil fields will be produced at their maximurn efficient rate and that any associated gas produced in excess of local gas demand in the producing regions will continue to be flared. A further corollary to the lack of gas storage is that production and consumption will be equal. The follo..ing specific assumptions were made:-

Bombay Offshore - The gas flaring reduction program will proceed as planned.

- The gas oil ratio (GOR)of the Bombay High oilfield will be reduced to 400 cubic meters of gas for eacti cubic meter of oil produced (v /v), that is a GOR of 400:1 v/v will be maintained at all wells.

- Other oil fields in the area will have a GOR maintained at or below 400:1v/v.

- Discovered fields in the area will sustain gas production of 52 MMCMD through year 2010.

Westem Region - Oil field GOR will be maintained below 500:1v/v.

- Free gas (which can be connected to the HBJ pipeline) will not be put on production until 1997.

- Discovered fields will sustain gas production of 16 MMCMD.

- Rajasthan gas production begins in 1995 fcr local market.

Assam - Discovered fields will sustain gas production of 11 MMCMD.

Tripura - Gas production begins in 1993 for supply to local markets.

2. Potential gas sales that can be sustained from existing known reserves are of the order of 93 MMCMD, even though actual producing capacity may initially exceed this level. Future discoveries of gas are probable but, being unquantifiable, have not been taken into account. Future large discoveries may cause substantial changes in transport and marketing requirements, depending on their physical location. Table I summarizes the projected gas out put from oil and gas fields in the Western region and t;-e Bombay High oilficid. These projections are conservative and only production from known fields was taken into consideration. -47-

INDIA Annex 2.1 GAS FLARING REDUCTIONPROJECT Page 2 of 2 Gas Production Projections

Table 1 Gas Production in India's Western Region and Bombay High, 1991 to 2010 Million cubic meters per day

---- AswciatedCas ----- Free as Yeaa Bombay Ileera Neelam Patina& Total South South BombayPanna Mid Other Total Tota High Mukta Associatedassein 2Bassein' High SI South knobm Fra Gas Gas Tapti structures Gas Pr'd'n

1991 16.0 1.1 17.1 7.5 7.5 24.6 1992 16.0 1.5 17.5 9.7 9.7 27.2 1993 14.8 1.0 15.8 13.8 13.8 29.6 1994 19.3 0.7 0.7 20.7 15.3 15.3 36.0 1995 19.3 0.5 1.2 2.3 23.3 12.7 12.7 360 1996 26.8 0.4 1.2 3.8 32.2 2S.0 3.8 28.8 61.0 1997 24.2 0.3 1.6 4.2 30.3 25.0 4.2 1.5 30.7 61.0 1998 21.2 0.3 1.9 3.9 27.3 25.0 2.4 3.0 3.3 33.7 61.0 1999 19.9 0.6 2.0 3.5 26.0 25.0 3.7 3.0 33 35.0 61.0 2(00 18.3 0.5 2.0 3.0 23.8 25.0 5.3 3.0 0.6 3.3 37.2 61.0 2001 16.9 0.5 1.7 2.4 21.5 25.0 7.3 3.0 0.9 3.3 39.5 61.0 2002 15.3 0.4 1.6 1.6 18.9 25.0 9.2 2.5 2.1 3.3 42.1 61.0 2003 13.9 0.3 1.2 1.2 16.6 25.0 11.5 22 2.4 3.3 44.4 61.0 2004 12.6 0.3 1.0 1.1 15.0 25.0 14.1 1.2 2.4 3.3 46.0 61.0 2005 11.3 0.3 0.9 1.1 13.6 25.0 16.7 2.4 3.3 47.4 61.0 2006 9.5 0.3 0.9 0.9 11.6 25.0 16.7 2.4 3.3 2.0 49.4 61.0 2007 8.7 0.3 0.7 0.8 10.5 25.0 15.8 2.4 33 4.0 50.5 61.0 2008 7.9 0.2 0.7 0.7 9.5 25.0 15.8 2.4 33 5.0 51.5 61.0 2009 7.6 0.2 0.5 0.7 9.0 25.0 16.5 2.2 3.3 5.0 52.0 61.0 2010 7.0 0.1 0.4 0 9 8.4 25.0 17.3 2.0 3.3 5.0 52.6 61.0

Notes: ' Net gas availabilty after int-mal use of gas and taking into account compressor and pipeline constraints. 2South Bassein production based on maximum production capacity of 25 MMCMD I Additional production capaaty from SouthBassein requir&eto meet delivery commitments to gas consumers Source: ONGC and Y ssion estimates -48 -

INDIA Annex 2.2 GAS FLARING REDUCTION PROJECT Pag 1 o(f1 Gas Flaring in Major Gas Producing Regions

Million cubic merTsper day

28~~0 Elomba j

2.5UU a (_ ~~~~~~~~.1_r| U)1_

§ Guj~~~~~~ad ras ssmZ

1 .0 (F) 4.5~~~~~~~~~~~~~~~Rrda (U-)

si~~~~~~~~~~~~~~~~~~~Uiie _ gast-

| _00 00_00 Calutt 00 -49 -

INDIA Annex 2.3 GAS FLARINGREDUCTION PROJECT riageT-F4 Projected Gas Utilization

Table 1 Utilization (Commitments) of Gas in t'ie BomnbayMarket, 1991 to 1995 Million cubic meters per day

Sector Consu4mer 1991 1992 2993 1994 1995

Fertilizer: Rashtriya Chem. & Fert., Trombay 1.80 1.80 1.80 1.80 i0 Rashtriya Chem. & Fert., Thal 3.00 3.00 3.00 3.00 3.00 Deepak Fert. & Petro-chem. Ltd. 0.30 0.30 030 0.60 0.60

Subtotal fertibzer 5.10 5.10 5.10 5.40 5.40

Power: Tata Fiectric Company 1.50 1.50 1.50 1.50 1.50 Maharashtra SEBUran 3.00 3.00 3.00 3.00 3.00 Maharashtra SEB Uran extension 1.50 1.50 1.50 1.50

Subtotal pow.er 4.50 6.00 6.00 6.00 6.00

Industry: Maharashtra GasCracker 0.60 0.60 0.60 0.60 0.60 BharatPetr./llindustan Pctr. Ltd. 0.05 0.05 0.05 0.05 0.05 BharatElectronic Ltd. 0.03 0.03 0 03 0.03 0.03 ONGC: C2/C3 1.15 1.15 1.15 1.15 1.15 ONGC: LPG 1.00 1.00 1.00 1.00 1.00 HeavyWater Project 0.15 0.15 0.15 0.15 0.15 Grasim 0.75 0.75 0.75 0.75 lindustan Copper Ltd. 0.01 0.01 0.01 KalyanmSteel 0.75 0.75 Nippon Denro 1.00 1.00 GAIL: LPC 0.45 0.45 Hindustan OrganicCo. 0.15 Medtist 0.01

Subtotal 2.98 3.73 3.74 5.94 6.10

Other Bombay city dcstributon G.;0 0.50 0.80 1.50

Total commitments 12.58 14.93 15.34 18.14 19.00 Uran terminal capacitv 12.50 12.50 12.50 16.00 16.00 Expected offtake 12.50 12.50 12.50 1600 16.00

Source: GAIT. and mission estimates -50 -

INDIA Annex 23 GAS FLARING REDUCTIONPROJECT Pa2gei2of4 Projected Gas Utilization

Table 2 Bombay Area Gas market: Status of Projects to Utilize Gas, 1990 Million cubic meers per day

Existing New Cas Govt. Gas Financing Consumer Alloc- Approved Contract Arranged Sector Consumer Commitments'ations Proects Signed Remrks

Fertilizer: RashtriyaChem. & Fert.,Trombay 1.80 Yes RashtriyaChem, & Fort.,Thai 3.00 Yes DeepakFort. & Petro-chem.Ltd. 0.60 Yes

Power: TataElectric Company 1.50 Yes Maharashtra SEBUran 3.00 Yes MaharashtraSEB Uran extension 1.50 Yes No Yes Plannedconumnissioning 1992

Industry: MaharashtraGas Cracker 0.60 Yes BharatPetr./Hindustan Petr. Ltd. 0.05 Yes BharatElectronic Ltd. 0.03 Yes ONGC:C2/C3 1.15 No ONGC: LPG 1.00 No I leavy Water Project 0.15 Yes (rasim 0.75 Yes No Yes Ilindustan CopperLtd. 0.01 No No No Kalvani Steel 0.75 Yes No Yes Private. Land acquired. Nippon Denro 1.00 Yes No Yes Private. Landacquired. GAIL: LPG 0.45 No No No I lindustanOrganic Co 0.15 No No No Modtist 0.01 No No No

Other: BombavCity I)istribution 1.50 No No No

lotal 12.88 6.12

Notes " otai off take is generalIyi rmtne with totalconmnitments, because of fall backdemand Source-GAIL. - 51 -

INDIA Annex 23 GAS FLARING REDUCTION PROJECT Pag 3 o Projected Gas Utilization

Table 3 Utilization (Commitments) of Gas in the Gujarat Market and along the HBJ pipeline, 1991 to 1995 Million cubicmetm pr7day

Sector Consumer 1991 1992 1993 1994 1995

Fetilizer Krishak Bharati Coop. 3.30 3.30 3.30 3.30 3.30 National Fert. Ltd., Bijaipur, MP 1.80 1.80 1.80 1.80 180 Indian Farmers and Fert., Aonla,UP 1.80 1.80 1.80 1.J0 1.80 Indo Gulf, Jagdishpur, UP 1,80 1.80 1.80 1.0 1.80 Chambal Fert. Gadepan-Rajasthan 1.80 1.80 Tata, Barbala, Ul 1.80 1.80 Bindal Agro, Shajahanpur, UP 1.80 1.80 Indian Farmers and Fert., Aonla,UP 1.80 1.80 National Fert. Ltd., Bijaipur, MP 1.80 Subtotal 8.70 8.70 8.70 15.90 17.70

Power: NTPC, Auraiya, UP 2.25 225 225 2.25 2.25 NTPC, Anta, Rajasthan 1.75 1.75 1.75 1.75 1.75 NTPC, Dadri, UP 0.50 3.00 3.00 3.00 3.00 DESU, Indrapasta St. 0.60 0.60 0.60 0.60 0.60 NTPC, Kawas 2.25 225 NTPC, Anta, Rajasthan 0.25 0.25 NTPC, Faridabad, Ilaryana 2.00 DESU, Bawana 2.00 Subtotal 5.10 7.60 7.60 10.10 14.10

Industry: Essar, Gujarat 0.50 0.50 0.50 0.50 0.50 LPG, ONGC Hazira 0.30 0.30 0.30 0.30 0.30 LPG, Bijaipur, MP, GAIL 0.50 1.00 1.00 1.00 1.00 Reliance Ltd., Petrochemicals 0.50 0.50 0.50 Heavy Water Project 0.10 0.10 0.10 C2/C3 (GAIL, Auraiya) 0.20 2.40 2.40 C2/0, (GAIL, Hlazira ) 1.40 1.40 2.10 Indian Oil Corp., Koyal, Gujarat 1.10 1.10 1.10 Essar Export 0.90 0.90 Liquid Fuel Replacement 0.90 0.90 LPG GAIL, Hazira extension 0.30 LPG (location to be decded) 1.00 Usha Rectifier, Jagdishpur, UP 0.80 Subtotal 1.30 1.80 5.10 9.10 11.90

Other: GAIL (smaU business customers) 1.00 1.00 1.00 1.00 1.00 Corr.pressor fuel 0.50 0.50 0.80 1.00 1.00 Surat dty distribution 0.30 0.30 030 Subtotal 1.50 1.50 2.10 2.30 2.30

Total commitments 16.60 19.60 23.50 37.40 4600 Hazira terminal capacity 20.00 20.00 20.00 20.00 2.00 Expected offtake 12.50 14.70 17.60 28.00 34.50

Source,GAIL and missionestizmates - 52 -

INDIA Annex 2.3 GAS FL1 ¶ING REDUCTION PROJECT 15go Projected Gas Utilization

Table 4 Gujarat and HBJ Market: Status of Projects Utilizing Gas, 1990 Million cubic metersper day

Exist Gas New Govt Gas Con nts Oiftake Gas Appr. Contract Fm. Sector Cnusumer 1990/91 Alloc's PrFj. Signed Arr'd Remarks

Fertilizer: Krishak Bharati Coop. 3.30 3.30 National Fort Ltd., Bijaipur, MP 1.80 1.55 Indian Farmers and Fert., Aonla,UP 1.80 1.55 Indo Gulf, Jagdishpur, UP 1.80 1.55 Chambal Fert, Gadepan-Rajasthan 1.80 Yes Yes Yes Constr. started Tata, Barbala, UP 1.80 Yes Yes Yes Constr. started Bindal Agro, Shajahanpur, UP 1.80 Yes Yes Yes Constr. started Indian Farmers and Fert., Aonla,UP 1.80 No No No Appr. pend. 8th Plan National Fort. Ltd., Bijaipur, MP 1.80 No No No Appr. pend. 8th Plan Power NTPC, Auraiva, UP 2.25 2.30(combined NTPC offtake) Price dispute. NTPC, Anta, Rajasthan 1.75 No Price dispute. NTI'C, Dadri, UP' 3.00 No KfW Price dispute. DESU, Indrapasta St. 0.60 Yes No NTPC, Kawas 2.25 Yes No WB Sched. comm. 92 to 94 NTI'C, Anta, Rajasthan 0.25 Yes No No Sched. comm. 94 to 95 NTP'C, Faridabad, liarvana 2.00 Yes No No Sched. comm. 94 to95 DESU, Bawana 2.00 No No No Industry F:ssar,Cujarat 0 50 0 50 L1PG,C)NIC I iazira 0.30 0.30 L.1'(, Bijaipur, MP. GAIL 1.0( RclKanceLtd, P'etrochemicals 0.50 Yes No No I lca, N Water Project 0.10 Yes Yac No (2/C3 (GAIL, Auraiya) 2.40 No No No C2/C3, GAIL, I lazira) 2.10 No No No Indiani (.Il Corp, Koyali. Gularat 110 Yes No Yes Under implementation ENsar EXport 0.90 No No No lIquLid Fuel Replacemen: 0.90 No No No LP(; GAIL I iazira extension 0.30 No No No L PG (location to be decded) 1.00 No No No U sha Rectifier, Jagdishpur, UP 080 Yes No No Other (AIL. (small business customers) 1.00 1.00 na. Compressor fuel 1.00 n.a. Surat Citv distribution 030 Yes Yes No Total 1810 12 05 27s90

Notes Comrnilmrnti are considerablvin excessof terminalcapacity However,estimated offtake ir takenonly at about 75% of commitments. Moreover. additi,na 'upphies fr(m the Guiarat onshore fields are possible Source GAIl .53 D

INDIA Annex2.4 GAS FLARINGREDUCTION PROJECT Page 1 of 1 Gas Prices

Prices of Gas and Altemative Fuels in Majo1r Sectors,1991

Price aR per 1OOm3) 4000-

Not-backvalues Rs 2200 - 3000 3000 Net-back values Rs 2500- 2700

------~~~~~~~~~~~~~~~~~~~~~------

2000 ~~~Gasprice along HBJ (Rs 2350) e Nt-akvls 2000- Net-backvalues IRs 1300- 1500

------~~~~------Gasprice at landfallpoints (Rs 1500) OR 10001 Petro- dhemials Power Fertilizer Industry Naphtha Coal SubsidizedNaphtha Fuel-il Rs3632 Rs2446 Rs2242 Rsl713 0-1 8.70 38.85 24.10 10.91 Gas commitments (MMCMD)

Note.AU prici in thisfigue weexpraed in termsof theirthermal equivalents of 1000m3of gas

1. The figure above provides a comparisonof the value of natural gas in major end-uses,the manufactureof petrochemicalsand fertilizer,power generation and industrial uses. The 'replacement value' of natural gas is given by the price of the fuel whichgas could potentiallyreplace 'at the margin',-- naphtha in the petrochemicalindustry, coal in power generation,(subsidized) naphtha in the fertilizer industry and fuel oil industrial uses of gas. In addition to these replacementvalues for natural gas, the figure above shows ranges of net-backvalues of natural gas and the pricesof gas at landfall points as well as along the HBJgas pipeline. The netbackvalues provide an indication of the value of gas in a particular industry. It has to be kept in mind that thesenet-back values are plant and thereforelocation-specific; at best, they serve as an indicator of the maximumprice users would be willingto pay for gas. 2. The conclusionthat can be safelydrawn from the informationpresented in the figure above is that gas sold at landfall prices provides an attractive alternativefuel in all major end-uses. Along the HBJpipeline, someusers may find gas at the currently proposed prices unattractive,and may be unwill- ing to switch to gas. However, since the prices of alternativefuels (naphtha, coal, fuel oil) will most likely change as will transport charges for these fuels,the demand for gas along the HBJwill depend on relative fuel prices at specificlocations. -54 -

INDIA Annex 3.1 GAS FLARING REDUCTION PROJECT Pag I of I Oranization Chart of the Oil and Natural Gas Commission

ExcuLC hmittZ (CmorteMampgaeot)IoeaMora

ISertary to Commlulson :

ExcudtiveDiector (Seunity & Vglne

_Member Member MemlerMember Ma*Mer (Dr/IIiing) (Operation) 1k(Tednkl) (Penonnd) (Fmance | (Part-lme)

P ~ l ~CuhpIl ;l GNuP_ IGNuP [ Gimp_ t- l Gmupr~~~~~~~~~~~~~~~~~(prtTtw |(Nlt-ill)

i 'I l l ~~~~~~IDCena aRdt 01 DL; D lor DiEMag ~~mana Eag Oan (Ntlwm RBC CSmAthm , l 1, W v) | 1, ~~~OAarbs)IT |R IC| Grap GCmup

330dr.'ir GI Puida Ga. I . . .

d d | l |G~~~~~~~~~~~~~COpl G.nfa IMa 1nIaaim) II IIIEC l ~~~~~~~iflnll (Adn l

|GupGmt |

R|P Gp.)

RaamamGp.)

aAttutfa of DmbpwerA -t~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~ -55 -

INDIA Annex 3.2 GAS FLARING REDUCTION PROJECTr Summary of ONGC's Accounting Practices

In fiscal year 1986,ONGC changed its accounting practices to bring them into line with international oil industry practice. The results for 1981to 1985have not been restated and are therefore not fully comparablewith the accounts for the later years. The Comptroller and Auditor General of India observed that until 1989, the "SuccessfulEfforts Method of Accounting" had not always been correctly applied. These problems have now been corrected.

2. Until 1985it was ONGC's policy to write off exploration and development costs as follows:

* ExpLORAmoN.Geological and geophysical survey costs are expensed in the fiscal year in which they were incurred. All exploratory drilling costs were initially capitalized and year's expenditure was amortized equally over 15 years. In case of unsuccessful efforts, the license was surrendered and net amortized costs were expensed against income in three equal annual installments. In case an area was declared successful, amortized costs were transferred to producing properties.

ouPRoDucNCPRoPERnEs. The oil and gas producing properties included unamortized exploratory drilling costs and costs incurred on development of the producing field. These properties were created when regular production was started from the field regardless of the level of productionand were depreciated equally over ten years. Subsequent development drilling costs were depreciated in a manner where total costs were charged against income during the remaining ten year period. Development costs after the tenth year were charged against income of the year.

3. Following the practices of most international oil companies, ONGC changed its accounting practices to the "Successful Efforts Method of Accounting" in 1986. Accordingly:

(a) geological and geophysical survey costs and exploratory drilling costs (net of amortization) in areas declared unsuccessful and surrendered have been expensed in the year of account;

(b) exploratory drilling costs (net of amortization) in respect of areas yet to be determined as successful or abortive, have now been capitalized as "Wells-in-Progress" and

(c) all accumulated exploratory drilling costs and development costs for successful fields, including related facilities, have been capitalized. These costs have been taken net of amortization, depletion and depreciation already charged until previous years (without disturbing the past adjustments) and have been expensed following the "Unit of Production Method" by individual field or basin. The unit rate has been worked out taking the net cost as of April 1, 1985and year's addition with reference to recoverable reserves as of january 1, 1986. The recoverable reserves have been limited to A, B, and C-1 categories of reserves.

- RESEARCH AND DEVELOPMENr coCs other than on Capital Assets are charged against income as incurred. - DEPRECATION. Plant and equipment and other capital items are stated at cost and then depreciated on diminishing balance method at the rates set forth in the Income Tax -56-

INDIA Annex 3.2 GAS FLARINGREDUCTION PROJECT Page 2 of 2 Summary of ONGC's Accounting Practices

Act, 1961,except the Research and Development Equipment which is depreciated on straight line method on five equal annual installments. INvEwroRiEs.The stocks of crude oil from C1'F point onwards in saleable condition, and that of LPG and NGL in storage tanks, are stated at direct cost. Gas stocks in pipeline are not taken note of as it is not possible to measure such stocks. Inventories of stores and spares and assets for replacement are stated at cost. FoREICNCURRECY TRANSACnONS. All expenditure incurred and liabilities undertaken in the form of loans drawn and/or other liabilities are provided at the exchange rate prevailing on the date of the transaction. These liabilities are recogni7ed, on the last day of the accounting year, at the mean of the buying and selling rate of exchange prevailing on that date. The difference arising out of such adjustments and also changes in the value of cash balance and other adjustable advances held abroad are adjusted to the relevant head of account wherever feasible, otherwise to the Profit and Loss Account. LONGTERM DERTS. The practice of considering the portion of the Long Term Debts maturing for payment in the ensuing year as a current liability was discontinued after March 31, 1988. CoRPoRATETAXFS. Taxes are levied on income determined after providing for amortization and depletion in accordance with the provision in the Agreement with the Government under Section 42 of the Income Tax Act, 1961. For Corporate Tax purposes, total depreciation charged, whether allocable to production and transporta- tion activities or to exploration and development activity, is considered as an item of expendituire against year's income.

Note:All yearsrefer to Indian fiscalyears starting on April I -57-

INDIA Annex 3.3 GAS FLARING REDUCTION PROJECT Pa-geT6T ONGC Sales and Revenues, 1981 to 1990

Fisci year endingMarch 31 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990

Summary of (net) volumes sold: Crude oil, offshore (mill. tons) 4.8 7.3 12.3 16.9 19.6 19.8 20.6 19.7 20.7 20.9 Crude oil, onshore (mill. tons) 4.2 5.2 5.3 5.7 6.0 6.5 7.0 7.5 7.9 8.8 Total crude oil 8.9 12.4 17.6 22.6 25.5 26.3 27.7 27.1 28.5 29.7

Natural gas, offshore (MMCM) 292 514 1,000 1,485 2,050 2,518 4,265 4,952 5,852 7,438 Natural gas, onshore (MMCM) 680 716 751 738 740 791 777 921 1,060 1,172 Subtotal natural Vas 972 1,230 1,857 2,223 2,790 3,308 5,042 5,873 6,932 8,610 LPG(mill. tons) 0 73 161 196 242 320 450 502 680 718 NGL (mill. tons) 0 0 25 38 52 68 138 239 379 591

Revenues (Rs mill.) Crude oil 3,466 11,764 21,537 31,422 35,525 38,180 48,037 49,492 53,706 63,169 Natural gas 502 807 1,363 1,842 3,077 4,162 7,263 9,659 11,899 14,318 LPG 0 127 295 367 442 587 84 508 1,944 1,592 Other revenues 550 788 661 1,097 1,305 950 131 1,414 2,175 2,248 Total revenues 4,518 13,485 23,856 34,728 40,350 43,879 56,274 61,073 69,724 81,327

Average revenues Crudeoil (Rs per ton) 389 946 1,225 1,393 1,392 1,454 1,737 1,826 1,882 2,127 Natural gas (Rs per 1O0Oml) 517 656 734 829 1,103 1,258 1,440 1,645 1,717 1,663 LPG (Rs per ton) 1,734 1,830 1,879 1,830 1,831 1,872 1,012 2,858 2,217

Note: Other revenues include: Pipeline revenues, NCL sales, receipts from contcts, etc. -58-

INDIA Annex 3.4 GAS FLARING REDUCTION PROJECT Page 1 of I ONGC Income Statements, 1981 to 1990

F ik yur iduwMsrd31 1981 1982 1983 1984 1985 1986 1987 198 1989 1990

Revenues Oil rvewnues 3,466 11,764 21,537 31,422 35,525 38,180 48,037 49,492 53,706 P4,169 Naturel reg enues 5W 807 1363 1,842 3,077 4,162 7,263 9,659 11,899 14,318 Other revenues 550 915 956 1,464 1,747 1,537 974 1,922 4,119 3,840 Total revenue 4,518 13,485 3,856 34,728 40,350 43,879 56,274 61,073 69,724 81,327 Royalties, exdee ces and sks tax 858 2,735 4,379 9,049 9,762 12,781 21,773 24,597 28,110 37,215 Total revenues retained 3,660 10,750 19,477 25,679 30,588 31,098 34,501 36,476 41,614 44,112 Expenses Cashoperatlng ctob 732 1,224 1,630 1,985 2,969 3,342 3,929 4,614 5,012 6,481 Other expenditures 1 247 180 621 1,224 987 1,688 875 4,8& 2,428 Depreciation 984 1,282 2,822 2,592 4,289 2,178 2,103 3,342 2,946 3,027 Depletion 430 683 1,151 2,160 2,617 1,466 1,923 2,064 2,466 4,50 Amortization 372 721 992 1,360 1,887 2,717 2,594 4,412 4,614 6,468 Total Operating Expenses 2,718 4,157 6,775 8,718 12,976 10,690 12,237 15,307 19,900 22,907

Operating income 942 6,593 12,702 16,961 17,612 20,408 22,264 21,169 21,714 21,205 Less: Interest2 476 862 873 884 1,338 1,580 1,214 746 769 997 Corporate Taxes 1,975 4,900 8,020 7,450 5,960 6,205 5,347 4,930 3,970 Net Operating Income 466 3,756 6,929 8,057 8,824 12,868 14,845 15,076 16,015 16,238 Dividends 204 214 274 309 326 343 360 403 514 549

Net Income Retained 262 3,542 6,655 7,748 8,498 12,525 14,485 14,673 15,501 15,689

Ratios:

NormnalOperating Ratio (Sr.ss revenues) 60 31 28 25 32 24 22 25 29 28 Operating ratio (revenues retained) 74 39 35 34 42 34 35 42 48 52 Return on total equity 16 49 48 37 31 32 27 21 19 16 Return on net average flxed assets 36 39 31 28 31 28 23 21 19 Return on capital employed 9 25 28 24 21 22 20 17 16 14 Dividend as percentof total equity 3 2 2 1 1 1 1 1 1 1

Notes: "indude yearend revaluation vnet interet payment .59 -

INDIA Annex 35 GAS FLARING REDUCTION PROJECT Page lofl ONGC Sources and Applications of Funds, 1981 to 1990

Rsmillim

FiwMlyrmigMn* 31 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 sour" Operating income 951 6,619 13,008 17,736 18,277 21,070 23,344 22923 24,483 25,076 Additions (deduwo1ns) Depreciation 984 1,282 2,822 2,592 4,289 2,175 2,108 3,342 2,946 3,027 Depletion 430 683 1,151 2,160 2,60 1,466 1,923 2,064 2,466 4,503 Amortization 572 721 992 1,360 1,887 2,717 2,594 4,412 4,614 6,48 Others (nct) 14 129 81 205 (39) 189 (702) 50 129 375 Year end revaluation 247 180 621 1,224 987 1,688 875 4,862 2,428 Net internal cash generation 2,951 9,681 18,234 24,677 28,245 28,607 30,950 33,666 39,500 41,877

Borrowings Domesticborrowings 1,119 559 9 432 60 80 43 22 15 - For. curr.loansonlontbyGOI 349 2,142 1,000 1,150 684 930 760 1,600 1,000 1,350 lnt.cap. narket borrowings by ONGC 1,025 801 4,027 980 1,663 2,809 13,733 7,865 8,401 16,117 Suppliers/buyers credits ONCC 310 2,464 634 2,347 79 0 43 546 Subtotal total borrowings 2,493 3,812 7,500 3,196 4,754 3,898 14,536 9,530 9,962 17,467 Governnmentfunds 55 Total Sources 5,499 13,493 25,734 27,873 32,999 32,505 45,486 43,196 49,462 59,344

Applications Acquisitionof Capital Assets 2,729 5,729 9,169 9,461 11,251 11,555 11,560 10,306 12394 17,889 Exploration& Devt.Expenditure 1,530 2,376 4,420 5,524 5,466 5,808 7,398 8,652 10,897 13,106 Totalcapital expenditure 4,259 8,105 13,589 14,985 16,717 17,363 18,958 18,958 23,291 30,995 Long-terminvestment and PSUloans 3,895 1,003 128 298 1,445 9,180 13,088 5,589 Debtservice: principal repayments 475 417 1,112 1,269 1,894 2,496 11,050 5,356 2,888 8,806 Interest 485 888 1,179 1,659 1,993 2,242 2,294 2,500 3,538 4,868 Subtotaldebt service 960 1,305 2,291 2,928 3,887 4,738 13,344 7,856 6,426 13,674 Corporatetax 1,975 4,900 8,020 7,450 5,960 6,205 5,347 4,930 3,970) Dividends 204 214 274 309 326 343 360 403 514 549 Increase(decrease) in workingcapital 68 1,884 752 617 4,457 3,758 5,201 1,428 1,184 4,650 lncrease(decrease) in intangible assets 8 10 33 11 34 45 (27) 24 29 (83) Totalapplications 5,499 13,493 25.734 27,873 32,999 32,505 45,486 43,196 49,462 59,344

Debtsrvice coverage 3.1 5.9 5.8 5.7 5.3 4.8 1.9 3.6 5.4 2.8 Selffinancing ratio 45 56 104 94 75 83 40 149 172 81 Net workingcapital 698 2,901 3,576 4,205 8,791 12,512 17,571 18,942 19,987 24,609

Notec Variadonin workingcapital may not appearconsistent with balance sheets, due to accountingtteatment of fixedaset addition,the curret patlmnof long-tam debts andof gatulty,which is not consideredby ONGCas a curnt liabilty. -60-

INDIA Annex 3.6 GAS FLARING REDUCTION PROJECT Page 1 of 1 ONGC Balance Sheets, 1981 to 1990

Rs million

FiJlymr.iRgIMarcul31 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990

Cunent Assts: Cohb &Bank 31 151 168 92 96 337 884 5 1,025 2,065 Debtos (net of provisions) 563 2p26 3,216 2,506 4.046 3,979 5,041 62.62 8,338 16,954 Inventories 2,2W5 3,037 4,00 466 5,910 8,8 10,811 11,104 11,640 12,166 Other current asse 1,343 3,689 9,873 18,264 28,318 30,305 27,803 27,055 24,960 29,726 Subtotal Ament asts 4,193 8,903 17,262 25,528 38,370 43,41 44,539 44,526 45,963 60,911

Net flxed ansts Property, plant andequipment 4,561 4,988 8,780 12,181 13,239 20,894 24,450 22,966 21.6 24,424 Producng property 1,I67 2,476 3,66 4,C13 533 9,851 15,149 21,711 30,.95 39,834 Capitalworks in progres 232 719 1,.51 2.650 3,729 1,342 2,982 3,154 2,512 4,555 Othr fixed aeebs 1,983 5,028 5,129 6,770 9,673 9,114 7,519 7,949 11,491 12,040 Unalloated capital expenditure 1,795 2,271 4,785 6,731 8.014 10,807 14,146 17,317 19,934 19,064 Subtotal 10,211 15,482 24,091 33.145 40,188 52,006 64,246 73,117 86,358 99,907

Long-terminvestments 250 250 4,145 4,168 4,296 4,921 6,693 15,199 26,447 30,156 Loansto :.SUs 980 980 653 327 1,000 2,840 4,720 Intangibleassets 248 395 424 234 1,149 352 405 666 695 3,860 Total ssets 14,902 25,030 45,922 S4,055 84,963101,425 116,210 134,508 162,303 199,554

Liabilities andequity Current liabilities: Currentportion of long-termdebt' 417 712 1,274 1,9% 2,149 3,005 2,353 2,681 Provisionfort x andgrstulty 896 2,305 7,203 15,283 22,783 21,768 20,064 18,097 17,147 21,146 Othercurrent liabilities 2,180 3,7Q0 6,483 6,040 6,796 9,211 6,904 7,487 8,829 15,156 Subtotalcurrent liabilities 3,495 6,717 14,960 23,319 31,728 33,964 23,321 28,265 25,976 36,302

Long-term debt (unsecured& deferred) 5,511 8,864 14,857 16,883 20,894 22,398 27,356 32,037 46,571 s7,728

Total equity Capital 3,428 3,428 3,428 3,428 3,428 3,428 3,428 3,428 3,428 3,428 Reserves& surplus 2,468 6,021 12,677 20,425 28,933 41,615 56,105 70,77h 86,328102,096 Subtotaltotal equity 5,896 9,449 16,105 23,853 32,361 45,043 59,533 74,206 89,756105,524 Total liabilities and equity 14,902 25,030 45,922 64,055 84,963101,425 116,210 134,08 i62,303 199,554

Currentratio 1.2 1.3 1.2 1.1 1.2 1.3 1.5 1.6 1.8 1.7 Long-term debt-equityratio 0.9 0.9 0.9 0.7 0.6 0.5 0.5 0.4 0.5 0.5 Accountsreceivable (days) 45 55 49 26 37 33 33 38 44 76

Note: IPracticeof showingcurent portion of long Wm debtsa acwrrnt iabtlids has bon dlacotntinuedsice 1969. -61 -

INDIA Annex 3.7 GAS FLARINGREDUCTION PROJECT Page 1 of 3 Performance Parameten

ONGC: Average Wellhead Cost of Natural Gas, 1982 to 1990 Rs perlOm'r0

Fisdyear endingMarch 31 Onshore Onshore Offsho Offshore Avne AwFr RieentiwnPrice Curre"t Constant CurCnt Cnstnt Curnt Contat Current Contsnt Pries Prices Prics pris Pric prim Prices Prim

1962 326 326 759 759 507 509 1983 367 350 545 520 474 452 1984 409 362 553 490 50 446 1985 781 650 614 511 658 54 1986 595 474 482 384 508 405 1,400 1,116 1987 777 586 384 289 444 335 1,400 1,055 1988 1,249 870 423 295 547 381 1,400 975 1989 2,570 1,666 583 378 886 574 1,400 907 1990 2,124 1,307 668 411 859 529 1,400 862

Notes: Constantprices haw beenexpresd in 191I/8 tms Source:ONGC

ONGC: Average Wellhead Cost of Crude Oil, 1962 to 1990 Rspertcm

Fisl yer endingMarch 31 Onshore Onshore Offshore Offsho Avrge Average RetentionPrice Curret Constant Currn Constant Current Cout t Cuet Constant' Prices Prices Prices Prims Prices Prics Prices Prics

1982 201 201 326 326 2Th 273 968 968 1983 264 252 341 325 317 302 968 923 1984 392 347 294 260 319 283 968 857 1985 458 381 43O 358 436 363 968 806 1986 356 284 269 215 291 232 968 772 1987 401 302 275 207 307 231 968 729 1988 403 281 281 196 315 219 968 674 1989 553 358 321 208 385 250 968 627 1990 608 374 386 238 453 279 968 596

Not: 'Prices a-eexpresd in constant1981/C2 terms Soume:ONCC -62 -

INDIA Annex 3.7 GAS FLARING REDUCTION PROJECT Page 3 of 3 Performance Parameters

ONGC: Proved Developed and Undeveloped Reserves and Balance of Recoverable Reserves, 1985 to 1989 ' Oil in miion toes anrdgas in bWIlim bic mtew

CaklA r yars 1985 1986 1987 1988 19f Totals 027 Gas OCi V GCsGM 0R c 0 G 0 Gos

Beginning of the year 450.96 408.77 505.03 424.57 52525 465.41 583.18 500.27 66555 56728 450.96 408.77 Revision of upgrading/resting 60.25 7.48 25.09 12.92 67.68 16.24 16617 28.50 6.91 9.45 176.10 74.59 Coanges due to developnent drlling 1.42 0.14 (5.94) 24.07 (1.23) 035 5.05 1.00 4.80 2.22 4.10 27.78 Extensions and discoveries 19.66 14.51 29.34 14.15 20.06 27.42 89.70 49.35 49.79 37.56 20657 142.99 Production 27,26 6.33 28.27 10.30 28.60 9.15 28.55 11.84 31.13 14.59 143.81 52.21 End of the year 505.03 424.57 52525 465.41 563.18 50.27 665.55 567.28 695.92 601.92 695.92 601.92 Memo items: Raerves-to-productlon ratio 18.5 67.1 18.6 45.2 20.4 54.7 23.3 47.9 22.4 41.3

Not: 'Proved rneservesae the etimated quantiti of l and g which geooil and gi tng data den -tratedwlthr reonable cwtanty to be recverable in future years from known resavois under edsting economicand oprating nditione

Average cost of drnlling, 1981 to 1Q90%

Cnshm Offsore Exlrptoy Development Average Fiscalywr endingMarch 31 Costper meter Costper meter Costpr mter Costper meter Costper meter Rs. US$ Rs. US$ Rs. US$ Rs. USS Rs. USS

1981 4,790 607 12,584 1,594 9,002 1,141 4,417 560 7,216 914 1982 2,975 333 15,896 1,780 7,153 801 7,718 864 7,452 835 1983 3,703 385 16,645 1,729 8,563 891 P205 852 8W346 867 19B4 5,593 542 16,841 1,633 12763 1,238 8,418 816 10,132 983 1985 5,216 ' 9 17,348 1,45 14,402 1,212 7,777 654 10,655 896 1986 6,505 532 16,496 1,348 12,957 1,059 6,220 508 9,497 776 1987 5,925 463 17,496 1,368 13,519 1,057 5,07G 396 9,112 713 1988 6,513 502 17,050 1,315 14,389 1,110 5,524 426 9,513 734 1989 6,720 415 16,027 989 16,027 989 6,720 415 9,790 604 1990 6,348 357 18,610 1,046 9,631 541

Note: 2 Drilling ct are the average costs of exploratory and development drilling, Including depredation, trnportation of rip, and drilling and production testing. Source: ONGC -63 -

INDIA Annex 3.8 GAS FLARING REDUCTIONPROJECT Page 1 of T ONGC's Investment Program, 1991 to 1995

Milio Rupes (at1991 Prim)

Fscl yar endingMarch 31 1991 1992 1993 1994 1995 1991-95

Ongoing Pject Accelerated Production Plan Bombay High 74 32 106 Heera Phase 11Oi development 2,319 100 931 3,350 Gas lift Bombay High 1,278 497 178 1,953 BH 22 Ollfield development (near Bombay High) 95 60 84 240 BH 25 Oilfield m.velopment(near Bombay High) 119 60 26 205 Uran Gas Fractioiing Plant (C-C3 extraction) 335 65 400 Hazira Gas Sweetening Plant If 402 246 176 823 Cambay Basin Petroleum Project 285 190 ; '9 653 Additional oil recovery Bombay High South 182 28 21U Additional oil recovery Bombay HfighNorth 230 136 32 396 2 Jack-up rigs (offshore dril'ing) 135 135 Regional computers 61 61 Assam area captive power plant 33 13 45 Land development driling rigs 33 12 45 South Bassein- Phase 11residual drilling 126 126 Gandhar I Development (Cambay Basin) 456 198 168 822 B131Devel

Development Schemes Panna field (Bombay offshore) 408 1,250 2,472 2,749 2,000 8,880 Neelam field (Bombayoffshore) 325 2,500 5,710 3,100 3,296 14,930 Mukta Field (Bombay offshore) 80 100 3,745 4,295 4,000 12,220 L 11(oil only) 118 2,822 648 3,588 Llil (oil only) 2,495 3,898 1,502 1,001 8,896 Gas Flaring Reduction Project 1,278 15,492 17,843 12,531 47,145 CandharIf Development 303 400 2,275 2,144 80 5,201 Ravva Development 464 265 289 428 1,736 3,181 Crude Desaiter(Cambay) 20 iS0 240 70 480 Kerosene Recovery Unit (Hazlra) 6 50 200 274 530 Natural gas liquids refoener 0 500 733 733 733 2,700 Cambay onshore oil pIpeline 4 4 42 50 BPB Hazira Pipeline 3,240 3,240 6,480 Usar oi terminal 10 10 20 ICP- Heera Pipeline 5 5 10 Total development schemes 1,609 9,110 37,866 33,839 25,387 107,811

Other Capital Acquisition 5,575 6,137 1,490 1,450 1,348 16,000 Grand total Capital Acquisition 13,447 17,004 41,191 35,29 26,735 133,665

Surveys 1,429 1,306 1,040 1,030 1,050 5,854 Exploration Drilling 10,704 10,104 5,320 4,040 4,700 34,868 DevelopmentDrilling 5,314 6,513 4,000 4,350 2,510 22,687 SubtotalExploration and Development 17,447 1,922 10,360 9,420 8,260 63,409 Resarch and Development 600 934 740 710 520 3,504 Grnd Total 31,494 35,860 52,291 45,419 35,S15 200,578 -64-

INDIA Annex 3.9 GASFLARING REDUCTION PROJECT g'eToF ONGC Revenue Projections,1990 to 1995

FiywretdingM arch31 1990 1991 1992 1993 1994 1995

Summary of net volumes sold Crude oil, offshore (mill. tons) 20.9 20.3 20.4 19.7 24.5 29.2 Crude oil, onshore(mill. tons) 8.8 9.1 10.7 12.0 13.5 14.3 Subtotalcrude oil 29.7 29.4 31.1 31.8 38.0 43.5

Natural gas,offshore (MMCM) 7,48 8,250 9,100 12,717 15,892 17,187 Natural go, onshore(MMCM) 1,172 1,625 2,070 2,810 3,319 3,319 Subtotal naturl gas 8,610 9,875 11,170 15,527 19,211 20,506

LPC (1000tons) 718 725 775 821 859 859 NGL (1000torns) 591 740 800 800 800 800 C-2,C-3 (1000 tons) - 60 315 450 570 570

Revenues(Rs million) Crude oil 63,169 62080 65,735 67,088 80,357 92,000 Natural gas 14,318 16,519 18,654 25,939 32115 34,310 LPG 1,592 1,544 1,650 1,748 1,829 1,829 NCL 1,116 1,338 1,446 1,446 1,446 1,446 C-2,C-3 240 1,261 1,801 2,282 2,282 Other revenues 1,132 2,nlo 2,096 1,535 1,745 1,939 Totalrevenues 81,327 83,730 90,842 99,557 119,774 133,806 Average'price Crudeoioff hore(Rsperton) 2,118 2,113 2,113 2,113 2,113 2,113 Crudeoil onshore(Rsperton) 2,110 2,113 2,113 2,113 2,113 2,113 Naturalgas offshore(Rs per 1000ml) 1,673 1,695 1,695 1,695 1,695 1,695 Natural gasonshore (Rs per 1000m 3) 1,479 1,560 1,560 1,560 1,560 1,360 LPG(Rs per tan) 2,213 2,129 2,129 2,129 2,129 2,129 NGL (Rs perton) 1,888 1,808 1,808 1,806 1,806 1,808 C-2,C-3 (Rs per ton) 4,003 4,003 4,003 4,003 4,003

Note: Otherrevenues include:Pipeline revenues, NGL saes, receipt from contacts etc. - 65 -

INDIA Annex 3.10 GAS FLARING REDUCTION PROJECT Page-1 of i ONGC Income Statements, 1990 to 1995

Rsmvillton

Fiscalyeat eidingMarch 31 1990 1991 1992 1993 19'4 199I

Revenues Oil revenues 63169 62080 65735 67088 80357 92000 Natural gasrevenues 14318 16519 18654 25939 32115 34310 Otherrevenues 3840 5132 6453 6531 7302 7496 Totalrevenues 81327 83730 90842 99557 119774 133806 Royalties,excise cess and salestax 37215 37416 40043 45073 51822 58754 Totalrevenues retained 44112 46314 50799 54484 67952 75052

Operatingexpenses Manpower 582 799 798 921 1079 1260 Materials 1638 2078 2229 4046 5758 7248 Services 4n85 4399 4796 4270 6076 7649 Researchand development 176 169 375 352 363 385 Yearend revaluahon 2428 8781 5198 4420 6572 6061 Depreciation 3027 3375 3782 4034 3691 3361 Depletion 4503 5307 6161 5577 7175 9080 Amortization 6468 6332 6553 6419 7865 6493 Total operating expenses 22907 31240 29892 30038 38579 41537

Operatirig income 21205 15074 20908 2U47 29373 33515 Interestincome 3871 3662 5663 6387 6194 6510 Interestpaid 4868 5684 7361 9868 13080 15802 Less. Intere-t (net) 997 202t2 1698 3481 6886 9291 Corporatetaxes 3970 3015 4182 4889 587; 6713 Net operatinginconme 16238 10037 15029 16076 16612 17i320 Dividends 549 1055 1145 1284 1432 1;84 Net incomerctained 15689 8982 13883 14792 15180 15937

Ratios Operating ratio (grossrevenues) (percent) 28 37 .33 30 32 I1 Operatingratio (revenuesretained) (percent) 52 67 59 55 57 55 Returnon total equity (percent) 16 11 13 14 15 16 Retirn oi net averagefixed assets(percent) 19 11 13 12 12 12 Returnon capitalemployed (percent) 14 9 11 10 10 10 Divid,-ol 'pI fwrrent of total equity (percent) 1 1 1 1 1 1 -66-

INDIA Annex 3.11 GAS FLARING REDUCTION PROJECr Page 1 of 1 ONGC Sources and Application of Funds, 1990 to 1995

Rs mitlho

FilpyendingMarch 31 1990 1991 1992 1993 1994 1995

Sources Operating income ncl.interestincome) 25,076 18,736 26,571 30,834 35,567 40,M5 Additions (deductons): Depredation 3,027 3,375 3,782 4,034 3,691 3,361 Depletion 4,503 5,307 6,161 5,577 7,175 9,060 Amortization 6,468 6,3. 6,553 6,419 7,865 6,493 Others (net) 375 Year end revaluation 2,428 8,781 5,196 4,420 6,572 6,061 Net Intemal cash generation 41,877 42,531 48,264 51,283 60,871 65,019 Borrowings Foreign currency loans onlent by COI 1,350 1,004 1,321 6,669 /,275 5,52 ExportcreditsandotherFCborrowing 16,117 13,378 13,584 27,703 29,146 23,555 Subtotal total borrowings 17,467 14,382 14,905 34,372 36,421 28,607 Total soumrces 43,227 56,913 63,170 86,655 97,22 93,426 Applications Total capital expenditure 30,995 31,494 37,848 57,472 52,227 42,940 Long-term investment and PSU loans 5,589 19,062 6,894 (1.843) 3,014 8,874 Debt service: principal repayments 8,806 5,121 3,071 9,007 15,616 13,279 Interest 4,868 5,684 7,361 9,868 13,080 15,802 Subtotal debt service 13,674 10,805 10,432 18,876 28,696 29,081 Corporate tax 3,970 3,015 4,182 4,889 5,875 6,703 Dividends 549 1,055 1,145 1,284 1,432 1,584 Inaease(decrease) in working capital 4,650 (8,518) 2,668 4,978 6,048 4,445 Increase (decrease) in intangible assets (83) Total applications 59,344 56913 63,170 85,655 97,292 93,626 Debt service coverage 2.8 3.7 4.2 2.5 1.9 2.0 Self fLnancingratio (percent) 81 ;79 100 36 45 78

ONGC's Foreign Exchange Requirements, 1991 to 199S USSmillion

2500 9 1 9flaring1pro9 |Lll - Lillproect 2000 Othercapital expenditure_ _CGshoperating cost1 DebtserviceI I 1500 1000

0 -99 1992 1993 1994 1995 -67-

INDIA Annex 3.12 GAS FLARING REDUClION PROJECr Pa-ge1onf1 ONGC Balance Sheets, 1990to 1995

Rs miliw

Fiw yar endmg Marc 31 1990 1991 1992 1993 1994 1995

Assets Current s Cash and bank 2,065 2,234 2,460 2,877 3,982 4,963 Debtors (net of provisions) 16,954 6,467 6,781 6,824 8,232 9,309 Inventories 12,166 13,966 1452 9 21,5M 25,522 28,402 Other current assets 29,726 29,726 31,668 33,748 35,941 38,170 Subtotal current assts 60,911 52,393 57,457 64,950 73,677 80,844 Net fixed assets Property, plant and equipment 39,825 39,967 44,027 52,951 61,067 6S,502 Producing property 39,834 47,991 58,077 80,729 1E3,041 115,407 Unallocted and work ir. proges 20,248 23,429 35,636 45,504 48,572 54,776 Subtotal 99,907 116,387 137,741 179,184 212,679 236,685

Long-term investments 30,156 49,218 56,112 54,268 57,282 66,157 Loans to public sector undertakings 4,720 4,720 4,720 4,720 4,720 4,720 Intangible assets 3,860 3,860 3,860 3,860 3,860 3,860 Totalassets 199,554 226,578 299,890 306,982 3529 392,265 Liabilities and equity Currentliabilities: Provision for tax and gratuity 21,146 21,146 22,542 24,007 25,567 27,152 Other current liabilities 15,156 15,156 16,156 17,206 18,325 19,461 Subtotal current liabilities 36,302 36,302 38,698 41,213 43,892 46,613

Long-term debt (unsecured & deferred) 57,728 75,771 92,802 122,587 149,965 171,353 Total Equity: Capital 3,428 3,428 3,428 3,428 3,428 3,428 Reserves&surplus 102,096 111,078 124,961 139,754 154,934 170,871 Total equity 105,524 114,506 128,389 143,182 158,362 174,299 Total liabilities and equity 199,554 226,578 299,890 306,982 352,219 392,26S

Current ratio 1.7 1.4 1.5 1.6 1.7 1.7 Long-term debt-equity ratio 0.5 0.7 0.7 0.9 0.9 1.0 -68-

INDIA Annex 3.13 GAS FLARING REDUCTION PROJECT Fage I of 2 Assumptions to the Financial Projections

General

1. Figures may appear not to add up due to rounding. All years relate to Indian fiscal years ending March3 1. The financial projections do not take into account the transfer of assets from ONGC to GAIL, which is anticipated to take place during 1991. The overall etect on ONGCs financial position is, however, expected to be neutral.

2. The exchange rates and price escalation rates used in the financial projections are as follows:

ExchangeRa,es and Inflation Rates 1991 1992 1993 1994 1995

Exchange rates (I USSequivalent) Rs 19.4 20,8 21.8 23.0 24.1 Domestic inflation (percent) 8.3 6.6 6.5 6.5 6.2 International inflation (percent) 3.4 3.4 3.4 3.4 3.4

Source:Bank staff projections

For the year end revaluation of long term debt in currencies other than the US Dollar, exchange rates prevailing on December 31, 1990 are assumed to depreciate against the Rupee at the same rates as the US Dollar.

Income statements

3. Projected sales of crude oil and gas are based on ONGCs production forecasts, taking into account ongoing and planned development schemes. For the purpose of the financial projections projected revenues assume the same producer prices for crude oil and gas as those prevailing in FY91(Annex 3.9) throughout the projected period. The level of royalties, excise cess and sales tax has also been assumed constant.

4. Cash operating expenses are based on ONGC's budget estimates and take into account requirements for increased production and intlation.

5. Deprdciation, depletion and amortization assume the continued application of ONGC's current accounting policies (Annex 3.2) at rates permissible under the income tax act.

6. Average interest receipts were assumed at an average of 10.5%of ONGC's long term investments and ISU loans. Interest paid represent ONGC's projected annual interest payments on its long term debt

7. Corporate tax liability was assumed as 20% of operating income. In line with past practices dividend payments were assumed as 1% of total equity. -69 -

INDIA Annex 3.13 GAS FLARINGREDUCTION PROJECT FageToT Assumptions to the Financial Projections

Fund Flow Statements

8. New borrowings take into accountthe proposed projectfinancing plan. Foreigncurrency loans onlent by Govemment assumea 15%interest rate with a 5 year grace period and 15 year overall maturity. New export credits were assumed at a 10%interest rate with annual repaymentsof 10%of the amnountoutstanding at the end of each year. 9. Detailsof ONGC'splanned capital expenditureare given in Annex 3.8. The amounts have been adjusted for inflation and fixedasset additions are based on ONGC'scurrent accountingpractices. It should be noted that the proposed investmentprogram was based on ONGC and Bankestimates and not all expenditureshave been approved by the Government. Balance sheets 10. Current assets: Averagelevel of cash and bank balanceswas assumed at 30%of cash operating costs. Debtorsassume a credit period of 21 days for crude oil, 15 days for LPGand NGL sales and 30 days for natural gas. The level of inventorieswas assumed at 12%of net fixed assets.Other assets were assumed to increasewith domesticinflation. 11. Current liabilitieswere assumed to increasewith inflation. 12. Increasesand decreasesin long term investments weredetermined by the levelof total sources availableafter taking into accountworking capital requirements,debt serviceand capital expenditure. -70-

INDIA Annex4.1 GAS FLARINGREDUCTION PROJECT PageTof 4 Layout Optimization of the Pipelines to be Constructed

1. While the design of the processplatforns and related gathering fluid lines for the Bombay High field is fairly standardized,the layoutcn-eptualization of the gas trunk pipelinesrequires some attention to the optimum route in relation to potential gas markets. The principal factors that were taken into account in the decision of the layout of the proposed gas pipeline system included reviewof the recoverablereserves, market growth rate, consumptionpattern and problemsassociated with the development of the infrastructure. The review of the BombayHigh, South Basseinand surrounding fields poten- til indicatesthat the projectwould sustain the delivery of 30 to 35 MMCMDof gas for the next 20 years In addition, new offshoregas reservesare being identifiednorth of the Bombayoffshore field towards the Gulf of Cambay. The conceptualizationof the proposed pipeline systemas well as the flow capacityof the processingfacilities have, therefore,taken into accountthe issue of whether the gas should be taken to the Bombayarea or to the northern part of the country along the HBJgas pipeline. After a careful reviewof the gas demand projections,market constraintsand pattern of consumption,it is proposed that the project would bring gas to both the Bombayarea and Hazira as wel as areas along the HBJpipeline. 2. The Bombayarea market,where gas is mainly used as industrial fuel, is a supply constrained market with long lead times for developmentof the necessaryadditional gas supply infrastructure. This market will continue to be dependent on the Uran terminal for the next 8 to 10 years. The supply shortfall is, however,expected to be substantiallyreduced with the expansionof the terminal which will be undertaken soon under a separateproject. The terminal, whichis now supplying 12 MMCMD,will be expanded to its maximum capacityof 16 MMCMD.As the demand is projectedto grow further, ONGC is proposing to the Governmentthe constructionof a new terminal to increasethe supply by 10 MMCMDof gas. With regard to the market along the HBJgas pipelinewith a current consumption of about 15 MMCMDas feedstockfor fertilizers,the demand has been less than anticipated. There is, however,a perceptibleshift occurring in the previouspolicies of gas allocationand pricing that have up to now hindered greatergas utilizationalong this pipeline. The demand for gas along the HBj is now proiectedto grow at a fairly rapid and higher rate than for the Bombayarea. Power generationis expected to entail a big increasein gas use. Other markets, includingpetrochemicals, are also being developed. Variousprojections indicate that overallgas demand along the HBJpipeline would increaseto 40 MMCMDby 1995-96. 3. The quantity of additional gas to be supplied to the Bombayarea market would be limited to the maximum capacity(16 MMCMD)of the Uran gas terminal. To meet this additional quantity, the existingUran - Heera gas pipeline would require to be extended to the BombayHigh field. It is only through this extension,the ICP-Heeragas pipeline,that the supplyof the Bombaymarket can be increased and the current gas flaring substantiallyreduced. Sinceno gas compressionwould be required, the constructionof this line would have to be undertaken as soon as possiblein order to be completed simultaneously with the expansion of the Uran terminal. Such a line, for which the precise route would be determined by the detailed engineeringdesign, could also be used for the transport of the BombayHigh gs cap at a later date as well as associatedgas from any of the recentdiscoveries made in the Bombay High field area. Furtmore, the line would optimize ONGC'scontingency response capabilityshould the existingold line need to be repaired. With regard to the mnarketalong the HBJgas pipeline, it becomes necesary that a new pipelinebe built between BombayHigh and Hazira. The pipeline construction would consistof two wgments,from BombayHigh to South Bassein(SHG-BPB) and then to Hazira. Subeequently,the capacity of the Hazira gas terminal would need to be expanded. -71 -

INDIA Annex 4.1 GAS FLARINGREDUCTION PROJECT Pe 2 of 4 Lay-out Optimization of the Pipelines to be Constructed

4. The projectoptimization design carriedout by ONGCs consultantEIL has been reviewed by the Bankand found acceptable. It is a preliminaryengineering design based on an exhaustivestudy of all pertinent factors and data related to gas recoverablereserves and utilizationplans. The sizing and broad specificationsof the projectfacilities including the pipeline system layout have been determined followinga carefulevaluation of availablealternatives. The detailed engineeringdesign would be carried out by the contractorto be selected for the constructionof the projectcomponent. The current preliminary design is sufficientlyflexible to allow configurationdesign adjustmentsto be recommendedby the detailed engineering design. Figure 1 shows the schemnaticlayout of the existinggas pipelinesand those that will be constructedunder the project. Figure2 shows the expected flowsof gas through the pipeline system in the Westernoffshore region. -72 -

INDIA Annex 4.1 GAS FLARING REDUCTIONPROJECT Pdge 3 of4 Lay-out Optimization of the Pipelines to be Constructed

Figure 1 Layout of the Pipeline System

L,egeiid

o Existingplattorrn Pl tform to be constructed under the project 0- 00 Existing pipeline ' peline to be.Pi constructed under the project .. . 3',0~~M-' :0 .,lptz 0

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_~~~~~~Q

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to to Noeaomn pnXsuoDaq °1 saulpdd M,*~C o uopezadIdCK M oo Mt o~~~~~~~~~~~~~~~~~~~~~~uei )NfOEd rc MteS -t~~~~~~~~~~~~~~~~~~~~~~~araro~~~~~~~~~~~~~~'s p r a galDla3fitt u tI 9 km1 a Mtu zolannt

Il 90 I OWm O

C-otael NilNrvu IDId OL-0 v V oUU to m

Cl Nil~~ ~ ~ ~ ~~~ E - 74 -

INDIA Annex 4.2 GAS .LARING REDUCTIONPROJECT Pag I of Detailed Project Description

Background

1. ONGC has decided to implement a najor investment program aimed at enhancing oil production in the Bombay High oilfield. This oilfield, which is about 160 km west-northwest of Bombay and in the Arabian Sea, accounts for about two thirds of the country's current oil production of about 32 million tons a year. The field was discovered in 1974 and put on production in 1976. The program consists of further development of proven oil and gas reserves of the field's only producing reservoirs, L- III and L-II. It is part of a long-tern development scheme, which has been carried out in time phased sequences to allow a better delineation and understanding of the field's priarry producing mechanism.

2. L-III REsRvoiR.This reservoir accounts for about 90% of the field's total oil-in-place reserves of about 1500 million tons. It extends within the entire field area at an average depth of 1300 m. An East- West sedimnentarydiscontinuity divides the field into two sectors, the North and the South. About one third of the L-1I1oil reserves is located in the North and two thirds in the South. Oil production from L-III North started in 1976 and reached a plateau rate of 6.25 million tons per year in 1980. It started to decline in 1987. In 1990 it produced about five million tons per year. The decline in production was largely due to the shutting of several welkl as a result of delays in implementing the pressure maintenance and gas-lift programs. By the end of 1990, the cumulative production from L-l1 North had reached about 68 million tons of oil and 21 billion cubic meters of gas, representing about 18%of the initial in-place reserves. Oil production from L-lI1South started in 1980 and reached a level of about 13 million tons per year in 1983 and maintained between 13 and 15 mnilliontons per year thereafter. By the end of 1990, the cumulative production from L-III South had reached about 113.5 million tons of oil and 28 billion cubic ineters of gas, representing about 12% of the initial in-place reserves.

3. L-il REsERvoIR.The L-II reservoi:, which accounts for slightly less than 10%of the field's total oil reserves, is located only in the northern part of the field at an average depth of 950 m. It has a limited oa column thickness of 25 to 30 m. It remained undeveloped because ONGC devoted its efforts to first develop the L-III reservoir. Its performance, however, has been conclusively tested by some 20 production wells. Some of these wells have been producing oil since 1981. Its production rate has reached one million tons per year of which two thirds comes from four horizontal wells drilled over the past four years. The L-Il reservoir will now be developed and is expected to sustain a production level of about 1.5 million tons per year of oil and two million cubic meters of gas for the next 10 years.

Program for Enhancing Oil Production From the Bombay High Oilfield

4. A feasibility study, carried out in 1987 and 1988by ONGC with the assistance of the French oil company CFP Total, indicatea that the Bombay High production can be substantially increased and its overall decline delayed by developing the westem and southem peripheral areas of the L-1lIreservoir in the South and the L-II reservoir in the North. The L-III reservoir development, the largest program, would consist of construction of eight well platforms with the drilling of 78 infill wells, a process platform, a water injection platform, an interconnecting gas pipeline system and two trunk gas pipelines, one to the Hazira Gas Terminal (located about 260 km north of Bombay in the southem part of the Gujarat State) and the other to the Heera field (located about 70 km southwest of Bombay in the Arabian Sea) where it would be connected to the existing Heera-Uran gas pipeline which is currently supplying about 1.5 MMCMD of -75 -

INDIA Annex42 GAS FLARINGREDUCTION PROJECT Page2 of 8 Detailed Project Description

Figure 1 NQP Proce" Piatform Flowsheet

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gas from Heera to the Uran Oil and Gas Terminal(about 15 Jr. southeastof Bomnbay)for the Bombayarea narket. rae L-IIIprogram is expected to increasethe production by about 40 milliontons of oil and 18 Bcmof gas during the 1B95-2010period. The L-11reservoir development will cons.;t of constructionof five well platforns with the drilling of 42 infill wells,a process platformand an inter-connectinggas pipeline system. The L-IIvrogram is expected to increasethe production by at least 16.5 milliontons of oil and 6 Bcmof gas during the 1995-2010period. 5. To accommodatethe additional production,ONGC is expanding the gas processingcapacity of the Uran terminal frn.n 12 to 16 MMCMD,ar.d that of the Hazira gas terminal from 20 to 41 MMCMD.The expansion feasibilityand environnental impact studies for the Hazira terminal are expected to be submitted for Governmentapproval within the first quarter of 1991.Furthermore, cor.- structionof an additional oil and gas terminal with a first phase processIngcapacity of 10 milliontons of oil pei,year and 10 MMCNMDof gas is being studied by ONGC's consultant,Engineers India Ltd. Accord- -76 -

INDIA Annex 4.2 GAS FLARING REDUCTION PROJECT Page3oB Detailed Project Des3ription ing to ONGCs current plans, this terminal will be built at Usar, some 40 km south of Uran. It would increase the gas supply of the Bombay area from 16 to 26 MMCMD. lmplementatio*. of the entire program, including construction of the terrninals, is planned to take seven to eight years. DL velopment of the Bombay High L-IIIand L-ll reservoirs along with construction of related gas pipeline systems and expansion of the Uran and Hazira terminals is expected to be completed during the first five years of the development program.

Project Proposed Project

6. The project proposed for Bank financing would provide support for those components of the Bombay High development program that are required to eliminate the flaring of associated gas. The project would enable ONGC to recover an additional 7 to 8 MMCMD of gas over and above the 12 to 14 MMCMD of gas that are currently being flared. The project consists of

*Construction of a process platform, SHG, in the southern sector of the Bombay High oil field with a processing capacity of 100,000barrels (bbl) of oil per day, 15 MMCMD of gas and 140,000bbl of water per day. The platform includes a 78 kilometer (km) pipeline with a diameter of 28 inches to the BPBplatform at South -Bassein.

- Construction of a process platform, NQP, in the northern sector of the Bombay High oil field, with a processing capacity of 60,000bbl of oil per day, 6.8 MMCMD of gas and 30,000 bbl of water per day. The platform includes a 30 km pipeline with a diameter of 18 inches to the BHN - Uran gas trunk pipeline.

* Modifications of existing platformns.

* Construction of a 142 km gas pipeline, (26 - 36 inches) from the existing process platform, ICP, in the southern sector of the Bombay High oil field to the Heera - Uran trunk pipeline.

* Construction oz a 255 km trunk gas pipeline (42 inches) from South - Bassein to Hazira.

* Expansion of the existing Hazira gas terminal.

* Engineering, project management and other implemnentationservices.

* fmpiementation of a package of measures, in the Bombay High oilfield, required by proper reservoir management practices.

* Reservoir pcrformance and management studies and training.

* Implementation of a package of measures to reduce the environmental risks and enhanri .he safety of offshore operations.

7. CONSTRUCnONOF NQP PROCESsPLATFORM. This is to be a two-deck, six leg platform with a processing capacity of 60,000barrels of oil per day, 6.8 MMCMD of gas b ' 90,000barrels of water per day. The platform will be installed in the northern part of the field in abo_. 64 m ,ater depth and con- -77-

INDIA Annex 4.2 GAS FLARING REDUCTIONPROJECT FgWo Detailed Project Desaiption

Figure 2 SHG Process Platform Flowsheet

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(12 No.) stgs(y.1*11~ separa..onflareto be- locatedwater treatat- about t,750 g, m d,away . on a:tripod, fr se fireprotection' e t oil rpumping, adglycolo,e: c te sio, high p

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tolemetry, telecontrol and helideck. The platform construction will include supply and installation of three gas turbine driven centrifugal compressors, each designed for 2.2 MMCMD corpression capacity at 8 to 10. k

INDIA Annex 4.2 GAS FLARING REDUCTION PROJECT Page 5 of 8 Detailed Project De3cription

well fluid lines along with a gas pipeline to connect the platform to the Bombay High-Uran trunk gas pipeline.

8. CONSTRUCMONOF SHG PROCESSPLATFORM. This is to be a two-deck, eight leg platform with a processing capacity of 100,000barrels of oil per day, 15 MMCM'. of gas and 140,000barrels of water per day. It will be installed in the southem part of the field in about 70 m water depth and connected by a bridge to the existing SHP and SHQ processing platforms It will have facilities for oil, gas and water separation, water treatment, gas dehydration and compression high pressure ilare to be located at about one kilometer away on a tripod, fire protection, oil pumping, telecommunications, telemetry and telecontrol. The platform construction will include supply and construction of the interconnecting well fluid lines, installation of seven gas compressor modules and construction of a gas pipeline to connect the platform to the BPB platform in the South Bassein gas field. The gas compressor modules and the line pipes will be procured separately from the platform.

9. CONSrRucIONOF GAS COMPRRSSORMODUxES. Seven gas turbine driven centrifugal compressor modules will be built by specialized manufacturers and supplied to the SHG platform contractor for installation. Each module will be designed for 2.5 MMCMD compression capacity at 8 to 10.5 kg/cm2 suction and 134 kg/cm2 discharge pressures. The primary objective of these compressors will be to provide sufficient pressure to transport the gas through a 330 km submarine pipeline to the Hazira Terminal. A small quantity of the cornpressed gas will be distributed and circulated in the oil producing wells to improve their productivity through gas lift mnechanism.

10. MOI)IrICArIONOF E)asnNG PLATrFORMs. In order to fully integrate the platforms NQP and SHG into the existing process scheme, some of the existing process platforms will need to be upgraded. Separa- tion facilities will be overhauled and their capacity increased as more gas and water are being produced together with the oil from the ageing reservoirs. Acoditionallines with pipeline scraper launchers and receivers w ill be built between the new and existing well platforms. Piping configuration will also be reviewed and s:me lines changerl. Structural reinforcement will be required for some of the oldest platforms. Existing living quarters will be expanded to accommodate the personnel of the new platforms. The modifications will be c3rried out under the NQP and SHG platform construction contracts on four well platforms (NO, NW, NHi,and N6) and four process platforms (NQD, NQO, NQG, and NQF) in Bombay High North, eight wclUplatforms (SY, SW, SY, IL.,1K, SS, II and IH) and four process platforms (SHP, SHID,SCA, and SHQ) in 13ombavHigh South and one process platform (BPB)in South Bassein. The work to be carried ouit under this component will consist of three subcomponents:

(a) Procurenment,coating and laying of 77.9 kilometers of well fluid lines in the north and south sectors of the Bombay High oilfield;

(b) Modification of the following existing weil platforms so that they can handle additional well fluids: NA, NB, NM, N2, NL, IB, ID, SM, EB, SI, SC and SA; and

(c} Modification of the following existing well platforms: BHN, NC, BHS.SCA and iCP. Modifi- cations would involve the production separators, produced water conditioners and flare systems. - 79 -

INDIA Annex 4.2 GAS FLARING REDUCTIONPROJECT Page oT Detailed Project Description

11. CONSnRUCrIONOF INTERCONNECFINGAND TWUN.KPIPELINES. To optimize the field oil and gas gathering system and bring the associated gas to shore, new interconnecting and trunk submarine gas pipelines will be built under the project. The interconnecting pipelines will consist of well fluid lines from the process platforms to the well platforms and two gas lines from the process platforms to the trunk gas lines. About four well fluid lines will be built in the North (from NQP, NQO and NQG complex to NH 8.5 km, NO 3.6 km, NW 7 km and N6 11 km) and three in the South (from SHG, SHP and SHQ complex to SY 8 km, IL 8 km and IH 15.5 km). The two gas lirneswill consist of (i) a 30 km long, 18 inch diameter pipeline with a flow capacity of six MMCMD (from the platform NQP to the Bombay High-Uran trunk pipeline) and (ii) a 78 km long, 28 inch diameter pipeline with a flow capacity of 15 MMCMD (from the platform SHG to the South Bassein gas field). The construction of these lines aJong with the well fluid lines will be carried out under the NQP and SHG platform construction contracts.

12. ICP-HEFRAPIPL:LINE. To take all associated gas to shore, two new trunk gas pipelines will be built under the project. The ICP-Heera Trunk pipeline, also called the South Loop, will stretch 142 km from the ICP platform in the Bombay High field to the HRG platform in the Heera field, where it will be

Figure 3 Hazira Gas Terminitl Expansion Flowsheet

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INDIA Annex 4.2 GAS FLARING REDUCTION PROJECT Faeof 8 Detailed Project Desaiption

connected to the 26 inch size, 85 km long Heera-Uraa gas trunik pipeline. Its size has not yet been determined, but will be between 26 and 30 inches for a gas flow capacitv of about 9.5 MMCMD. It will be connected to the SHG process complex by a 22 inch size, 11 km long line. It will supply gas to the Uran terminal for the Bombay area market. Its construction will complete the South Loop for which the first section, Heera-Uran, was completed in July 1990 under a separate Bank financed project (Western Gas Development Project, Loan 2904-IN). The new line will carry about 3.5 MMCMD from Bombay High South to Uran as soon as its extension is complete. Its design will also optimize contingency response capabilities of ONGC should the 15 year old Bombay High-Uran trunk gas pipeline become idle for service and repair. The risks of disruption of the existing pipeline system have been assessed under a project previously called the Western Offshore Integrated Development Prosect (WOIDP). The WOIDP, as originally designed. has been abandoned. However, several of its key components have been integrated into the new developmnentprogram.

13. BPB- HAaiA PIWPLINE.The second trunk gas pipeline, BPB-Hazira, will stretch some 255 km from South Bassein gas field (about 65 km west of Bombay in the Arabian Sea) to a landfall point near Umrat (about 235 km northeast of South Bassein and 240 km north of Bombay in the southern part of the State of Gujarat) and then to the Hazira gas terminal (about 20 km north of Umrat). It will be built along the existing South Bassein - Hazira gas pipeline. Its size has not yet been determined but will be between 36 and 42 inches for a gas flow capacity of about 20 to 25 MMCMD. It will connect with the SHG-BPBgas line and transport about I MMCMD of associated gas from the Bombay High oilfield and 5 MMCMD of sour gas from the South Bassein field and nearby fields such as Panna to the Hazira gas terminal.

14. The size selection for both pipelines, ICP-Heera and South Bassein-Hazira, will determine whether the gas to be transported should be "wet" or "dry." A wet gas contains some hydromarbon liquids (condensate), which will undergo some degree of condensation during transport depending on the composition of the gas, transient temperature and pressure conditionrsin the pipeline. For the same volume, a wet gas requires a slightly larger pipeline size than a dry gas from which most of the condensate have been removed. In the present case, condensate removal will require complex treatment with additional offshore platform space and facilities such as refrigeration units, condensate handling and other equipment, which could, as in the case of existing gas pipelines, offset the incremental cost of larger pipeline sizes. ONGC will consider the least cost option on the basis of an ongoing engineering study. All interconnecting and trunk submarine pipeline routes will be in well known areas. Most of the pipelaying corridors have been surveyed under pievious construction activities and do not present any implementation difficulties.

15. EXPANSION OF HAnRAGAS TERMINAL. In order to be utilized efficiently and sdfely, natural gas delivered to consumers must meet certain requirements and specifications. Untreated or unprocessed natural gas contains many hydrocarbon compounds and a few non-hydrocarbon compounds. Some of them are of considerable value (LPGs and NGLs), while others are contaminants that render the gas un1 suitable for most commercial uses (water, hydrogen sulfide and carbon dioxide). In the case of Bombay High gas, the water content is controlled through dehydration carried out on the field's process platforms. The removal of certain hydrocarbon components to meet hydrocarbon dewpoint specifications is carried out at the Hazira terminal. The Hazira terminal is also designed to remove carbon dioxide and hydrogen sulfide, which are found in high concentration in South Bassein and Panna gas fields. The hydrogen sulfide is a poisonous gas that could be a serious hazard to the environment if it is not treated properly. -81 -

INDIA Annex 4.2 GAS FLARING REDUCTION PROJECT TNaeR of6 Detailed Project Desaiption

16. The Hazira Gas Terminal has been built in phases. The first one for a capacity of 10 MMCMD of gas from South Bassein field was financed by the Bank under a loan that closed on December 31,1988 (South Bassein Gas Development Project - Loan 2241-IN). It was completed and commissioned in July 1988. The second phase, to increase the terminal's capacity by another 10 MMCMD of gas also from South Bassein, is almost complete. This second phase is also financed by an ongoing Bank project (West- em Gas Development Project, Loan 2904-IN). Presently, the terminal is processing about 15 MMCMD (five from Bombay High and the remaining from South Bassein). Sour gas from South Bassein is pro- cessed to remove hydrogen sulfide, which is converted into sulfur. The sweet gas is dehydrated and then its heavier hydrocarbon components removed. Gas liquids are fractionated to extract LPGs and NGLs. The lean gas is piped to consumers along the Hazira-Bijaipur-Jaghdishpur (HBJ) pipeline.

17. The proposed third phase expansion of the Hazira Gas Terninal will increase its processing capacity from 20 to 41 MMCMD. The new facilities to be designed for a 21 MMCMD capacity will be similar to the existing ones. They will consist of two slug catcher units (one for sweet gas and the other one for sour gas), one gas sweetening train, one sulfur recovery train, one gas dehydration unit, four dew point depression trains and four condensate fractionation trains. The size of the sweetening, sulfur recovery and dehydration units will have a processing capacity of five MMCMD of sour gas, which will come from the South Bassein and Panna fields. The liquid hydrocarbon recovery from the proposed expansion will be 192,000tons per year of LPG and 360,000 tons per year of NGLs. Additional plant utilities and offsite facilities, such as power generation, cooling water, product storage and product loading terninal will also be required.

18. E.VI\ONoMhN-rAl.COMPONFNTr. Following the appraisal mission's review of environmental and safety issues emerging from ONGC's offshore operations, ONGC requested financing for

(a) a safety assessment of its offshore operations and the proposed oil and gas terminal at Usar;

(b) staff training in safety and environmental engineering;

(d) an expansion of ONGC's current capacity to combat oil spills;

(e) enhancing ONGC's capdbility to monitor the impact of its operations on environmentally sensitive areas, in particular the marine ecosystem;

(f) the implementation of an environmental monitoring program of all of ONGC's operations; and

(g) strengthening ONGC's capability to deal with the risk of fires through the desigrnof efticient flare systems and risk assessment studies.

19. RESERVOIRMANAGEMSENT COMPONENT. The rapid increase of gas flaring is, to a large extent, due to the delay in water injection and other measures that proper reservoir management practices would require. ONGC requested financial support for a study of the Bombay High reservoir, which should recommnenda number of steps to optimize hydrocarbon production and arrest the decline of oil output from this field. This component will provide financial support for equipment, materials and services needed for the workover and rehabilitation of designated oilwells. a a

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INDIA Annex 4.4 GAS FLARING REDUCTION PROJECT Page I of Project Implementation Schedule

VFY90/9flj FY91 /92 FY92/93 FY93/94 |FY94/95 199 1991 199 199 1994 199

NQP Process Patform . Complex

S_ Comp ors h Q . . e m - - - -

SHC ProcessPlatform Complex

South Zone Linepipe

South ZoneLin pipe

,H._S - I- Well Rlwdlines & Mlatform W 00 Modifications (North and SouthBombyHg)jI---

ICP-HeeraLinepipe6 - -

ICP-Heera Lifneipt?aa' i Coating and Wap -

BPB-HaziraLinepipe

BPB-iHaziraLinepipe Coat, I VA4apand Conauci n

HaziraTerminal Expansion

Ky to symbols I ssueof IFB 4 Awardof conbad 4 Bidsubmission sense"l PNe-Constrdon Activities O Reviewof bid evaluation a Cnstruction Activites - 84 -

INDIA Annex 4.4 GAS FLARING REDUCTION PROJECT Page 2 of 3 Project Implementation Schedule

Inr'tat ionfor Openingof Review Awardof Compt ionof Major procurementpackages Bids to be PriceBids of Bid Contract Contract Issued Ewavutiom

Process platform, NQP Jun-01-91 Jan-01-92 Jan-17-92 Mar-29-92 Apr-30-94 Compressors, SI IG Jun-01-90 Jul-10-91 Jul-24-91 Oct-01-91 Aug-30-93 Process platform, Si IG May-01-91 Nov-30-91 Dec-15-91 Feb-01-92 Mar-30-94 Linepipe, SiCHBPB Apr-25-91 Aug-30-91 Sep-15-91 Nov-11-91 Oat-01-92 Laying, coating and wrapping. Si IG-BPB Mar-29-91 Sep-20-91 Oct-0691 Nov-20-91 Apr-20-93 Platform modifications Dec-01-91 Jun-08-92 Jwi-23-92 Sep-01-92 Feb-28-94 Linepipe, ICP-Hleera Nov-15-91 May-19-92 Jun-04-92 Aug-22-92 Apr-30-93 Laying, coating and wrapping, lCP'l ieera Feb-10-92 Aug-25-92 Sep-10-92 Nov-25-92 Mar-31-94 Linepipe, BPB-1Hlazira Sep-01-91 Mar-12-92 Apr-18-92 May-30-92 Jw-31-93 Laying, coating and wrapping, BPB-Ilazira Jun-01-92 Nov-10-92 Dec-17-92 Feb-28-93 Dec-31-94 Expansion of }lazira gas terminal Aug-01-91 May-01-92 Jun-01-92 Aug-01-92 Jan-30-95

Source: ONGC

Limited International Competitive Bidding (LICB)

1. LICBis a procedure which will be followed by ONGC in procuring of certain project componienits,e.g. linepipe, the process platform SHG and other items, which the Bank will not finance and for which export and suppliers credits would be required. This procedure is neither new nor uncommon; it is more often used in relatively more developed countries. Bids under this procedure are often referred to as "price & terms" bids. However, LICBhas not yet been used i;] conjunction with Bank-supported projects in Inidia. Essentially, LICBis a resource mobilization technique used in cases where there are indications of strong supplier interest and where the prospective borrower finds it convenient to leave the resource mobilization responsibility with the suppliers. It is a practical way to mobilize resources in situations where the actual source of supply would become known only after the bid(ding and where, at the same titne, the borrower has reasonable evidence that the major part of prospective suppliers would be in a position to provide the requisite financing from, or with the guarantee of, the official sources, such as Export Credit Agencies (ECAs). The Bank will not firance any portion of the LICBs.

2. There are two main features of LICBwhich distinguish it from international competitive bidding, as generally defined by the procurement guidelines of multilateral development institutions: (i) Under LICB, the bidders are required (as opposed to being given an option), in addition to quoting the price, to offer financing at certain mninimumterms and conditions, specified beforehand; and (ii) The responsive bids under LICBare evaluated on the basis of the quoted price and the offered terrns of financing. Customarily, this process entails the evaluation of bids on the basis of their present value, calculated by applying a pre-announced discount factor(s).

3. The main advantage of LICB for the borrower is (external) resource mobilization under competitive conditions, whereby the risk of price distortions in minimized. A possible disadvantage of LICBis the risk of elimination of otherwise competitive bidders who cannot furnish the requisite financing. It is therefore necessary to use LICBjudiciously. In the case of the proposed project, two aspects of * 85 -

INDIA Annic . 4.4 GAS FLARING REDUCTIONPROJECT age 3 of3 Project Implementation Schedule

LICBunderwent particular scrutiny by ONGC as well as by the World Bank: (i) supplier interest in the procurement of project items -eferred to in para. : above; and (ii) availability of credit to ONGC from the prospective supplier countries. Extensive screening of the prospective suppliers as well as of those ECAs, which are considered to be the most likely source of credit under the subject LICBconfirmed the existence of keen interest in the project among suppliers, and the availability of sufficient amounts of export credit, or export credit insurance cover.

4. As regards suppliers' interest in bidding for the delivery of project items envisaged for procurement under LICB, evidence was obtained through the tenders issued by ONGC in 1990 for the supply of line pipe and equipment for the SHG Complex and for the ICP-Heera Pipeline, on which occasion about half a dozen suppliers from Western Europe, North America and Japan submitted their bids. Most of those bidders also indicated that they would be in a position to furnish credit. Subsequently, the World Bank also contacted a number of ECAs from the countries where the items envisaged for LICB were likely to originate. In all cases, indications were received of ONGC's eligibility for export credit. On that basis, the procurement under LICB in an estimated amount of about U&M957million was deemed feasible.

5. One of the key issues that a prospective LICBuser has to resolve relates to the minimum terms and conditions of financing which the (responsive) bidders would be required tc furnish. Under the circumstances, given the length of the period required to depreciate the LICB-procured items and the type of financing that appeared available for the purpose, ONGC decided to define the minimurmiacceptable tenns of financing under LICBas the most favorable terms and conditions available to India under the OECD Export Credit Arrangement (the so-called "OECD Consensus"). For projects of a long-term nature, the Consensus terms would imply a minimum repayment period of 8.5-10 years, commencing a certain period, e.g. 6 months, after installation of equipment, thus effectively resulting in Icans with final maturity in excess of 10 years. The applicable interest rate, which would be determined on tUE basis of a matrix of export credit rates which is revised by the Consensus members every 6 months. Fokexample, on January 15, 1991, the matrix rate for Consensus export credits to India, with mraturity over 8.5 years and up to 10 years, was 9.2 per cent per annum. As an alternative to this rate, ONGC could choose Commercial Intei t Reference Rates given that the Consensus allows the borrower to seek commercial rates for various currencies in cases when those are lower than the Consensus matrix rate. Customarily, the financing under the Consensus would cover 85 % of the value of goods furnished.

6. In order to ensure the mobilization of resources under LICB,ONGC will require all the participating bidders to furnish evidence of the availability of the stipulated credit at the time of bid submission (or, alternatively, at prequalification, in the event that it should be used as a part of the bidding process). Such evidence should be in the form of expressions of interest from ECAs or other financial institutions, indicating that the stipulated credit would be available at requisite terms and condiitions or better, in the event that the given bidder is actually awarded the contract.

7. As indicated above, such bids would be evaluated on the basis of their present value, which would be arrived at by applying a predetermnineddiscount factor(s). -86 -

INDIA Annex 45 GASFLARING REDUCTION PROJECT Page 1 of 3 EnvironmentalAspects

1. The project is expected to have a major positiveenvironmental impact. The recoveryof a substantialquantity of natural gas that is currentlybeing flared will substantiallyimprove the environment. In addition, the recoveryof flared gas along with the incrementalgas to be produced under the projectwould displacea substantialquantity of fuel oil being used in various smalland medium industries in the Bombayareas where industrial and populationconcentration is already confrontingpollution problems. Similarly,the power generationprogram to be supplied with natural gas along the HBJpipe- line under the projectwould also displacecoal. This would improve air quality by reducing air pollutants caused by the use of coal such as ash, sulfur dioxide,carbon monoxide, nitrogen oxide and carbon dioxide.

2. Whilethe use of natural gas comparedto that of other fossilfuels is highly beneficialto the environment, its developmentand production entail some environmentaland safety hazards. To cope with these hazards, the industry has developeda seriesof guidelines,which are compiledand updated by internationalagencies (Anetrican Petroleum Institute, American Bureau of Shippin& Uoyds Shipping Register,and Det Norike Veritas). In most countries,thesc guidelinesare adjusted to the country'sspecific situation and enforced through nationallegislation or other regulations. In this regard, ONGC has adopted a RecomrnendedCode of Practiceand applies the Indian EnvironmentProtection Act of 1986for its oil and gas operations. All projectsare subject to a Govemnmentenvironmental clearance (Ministry of Environment and Forests) which requires a satisfactory environmental impact assessment with environmental management plans and disaster management plans.

3. ONGC's safety and environmental guidelines and regulat.ons as well as ONGC observance were evaluated by Bank consultant and staff and found satisfactory. The Bank consultant has also carried out a comprehensive review of the safety and environmental issues associated with the proposed project. It was found that the occupational safety of field personnel has substantially improved over the past 12 months; while no major environmental issues have emerged fhom the review, there is, however, a poten- tially adverse impact inherent in the project's implementation activities particularly with regard to development drilling, construction of the process platforms, construction of the gas pipelines and expansion of Hazira terminal.

4. FATALAcaDENr RAm1 The number of fatal accidents related to the Bombay offshore activities has oeen relativelyhigh over the past five years (1985:1;1986:2; 1987:1; 1988:3 of which 1 onshore and 1 for ONGC's contractors; 1989:5 of which 3 for ONGC's contractors; and 1990:0).Of the 12 fatal accidents three were man over-board accidentsand three were related to drilling activitiesincluding a well blow- out during drilling. In viewof the steep increaseof fatalitiesin 1988-89,ONGC adopted several measures to enhance the level of safety awarenessand emergencypreparedness. One of the measures is a risk analysis and safetyaudit of production platforms.Engineers India Ltd. with the back up of an external consultingfirm have been carrying out this work since July 1989.These measures were discussed with Bankstaff, which found them satisfactory. The fact that there were no fatalitiesin 1990seems to point to the effectivenessof the steps taken by ONGC.

5. DEv ELrrDRILLING. While development drilling is not a projectcomponent, several wells will be drilled within the project area to increase oil and gas production. The potential risk to the environment of offshoredrilling is largelydue to the increaseof drilling wasteand the effectsof well blowouts. Drillingwaste consistsmainly of drilling fluids (drillingand chemicals),residual substancesand drill - 87 -

INDIA A 4ir GAS FLARING REDUCTION PROJECT Pagr 2 i,f 3 Environmental Aspects

cuttings (various rocks recovered while drilling the wells). ONGC does not use oil based drilli;g ritid.ls which are a major source of 2 ollution. It uses water based drilling fluids which are continuously condi- tioned (using solid control equipment and adequate treatment) and recovered at the end of each cycle. Drill cuttings are washed and discharged into surface waters. Well blow outs with oil and gas 'iischarge while drilling represent another major danger to the environment. To minimize this dagr.er, L)NC,( use's drilling rigs with field proven mechanical integrity and blow out preventers with rermotecontrol systems Drilling equipment is operated by experienced crews often provided by international contractors.

6. In the unlikely event of a blow-out with oil discharge, the oil spill would not exceed 4(X) tons of oil per day. This estimate is based on the production average of the wells in the area. For this purpose, ONGC has five multi-purpose vessels of which two are equipped with booms and oil skimmers with an oil spill recovery capacity equivalent to a well blow-out discharge. Additional facilities are available with the Indian Coastguard for a recovery capacity of about 300 tons per day. It should be noted that for larger oil spills, ONGC can avail the services of established worldwide oil spill control centers

7. CONSTRUCnONOF nfE PROCESS :I`.ATFORMS.Construction and installation of process platfornl; entail no environmental risks, except very limited disturbances of the sea floor during location sampliln. and platform siting. As the main functions of the platform are oil, gas and water separation, gas cornlpft1 sion and water treatment the Lnvironmental risks may occur after the platforms are put into productiot, from effluents generated from produced water or leaks of oil and gas. For this purpose the platfonrmswill be equipped with adequate water treatment facilities particularly for removal -f any oil or grease. Moni- tors to activate warning signals wotuld be installed wherever there is a risk of leaks. Accidental oil and gois spills will be minimized through appropriate operating and maintenance practices that were fotiundto tho adequate.

8. RE4EDIAL MEASURES FR EXSTINNG PlAIFORMS. A review of the environmental and safety related equipment and practices on the existing platforms of the Bombay High fields will be carried out ,is part of the proposed project. In addition to the safety audit being carried out, the modifications planinied tor the existing platforms will take into account the latest environmental and safety regulations In this regard, the high pressure gas riser of NQO platf'orm, located beneath the iiving quarters would be relo cated on platforms with no living quarters such as NQP or NQG. This approach will be followed in the future in simnilarsituations.

9. CONSTRUCION OF THEGAS PIPEUNTES. Construction of offshore pipeline also does not cntail anv significant environmental risks except very limited disturbances of the sea floor. The linepipe would be taken to sea on barges and welded on a derrick-lay large and then allowed to sink and rest on the sea floor within 60 to 70 m water depth. All pipelines planned under the project would be along a previously surveyed route that is flat, avoiding boulders and any other obstructions that require blasting. To minimize or eliminate shifting on the sea floor, the pipe would weighted with a heavy concrete outer coating. To trinimize the risk of environmental pollubon after the pipeline is put into service, all materials usedi for construction would be carefully inspected. The welding would be inspected by X-ray techniques and hydrostatic tests. The risk of corrosion would be minimized by using adequate cathodic protection methods. The pipeline would be equipped with automatic shut-off valve devices and metering systems to give continuous comparison between input and output on all lines. This allows operators to discover leaks immediately. -88 -

IND;A Annex 45 GAS FLARING REDUCTIONPROJECTI age3 Environmental Aspects

10. EXIPANSIONOF tHEHAZJIA GASTERMINAL. The construction of additional facilities at Ha_ira entails no environmental risks. Some disturbances would, however, be generated from dust during the site preparation and noise during the construction. Since the terminal is located in an uninhabited area, these disturbances wouldi have very limited environmantal implications. When the additional facilities are put into service, there would be, however, an increase in the environmental risks since similar facilities are already operational within the terminal. These risks relate mainly to gaseous and liquid effluents. Gaseous effluents could originate principally from the gas process itself, valves, compressors, storage and loading facilities. The design of the terminal would be such that these effluer.ts would be collected by vapor recovery, ventilating systems. The fact that the additional facilities would process 5 MMCMD of sour gas to be constructed at Hazira with gas desulfurization and sulfur recovery equipment would significantly reduce the amount of sulfur that would otherwise be released into the atmosphere. With regard to liquid effluents, three types of pro zess treatment would be provided, namely for rain water, sanitary waste and process waste. Rain water would be collected in surge ponds and treated to remove any oil and suspended solids. It will then be filtered and used in cooling systems or disposed of. The sanitary waste would be treated in specially designed units. Process waste would be collected in tanks and treated for removal of any oil and suspended solids. A-r flotation units would be used for removal of emulsified oil. Recycling systems inci.u ;ng biological treatment would also be installed In addition, good maintenance and inspection practices would be an effective approach to keep the terminal as leakproof as possible INDIA GAS FLARINGREDUCTION PROJECT Detailed Project Cost

usS miallw

Fii yQr mdi Mwrc 31 FY92 FY93 FY94 FY95 FY96 ToWl njrd cog itm Fuur Lem Towt Fwapg Lalw Totd Fcmx Lowt Tot Fp LOWt Totwl Fmgu Lt Tow Famp Lat cut

Prcm platform,NQP 8.4 2.0 10.4 627 15.0 77.7 104.5 25.1 1296 33.4 8.0 41.5 0.0 0.0 0.0 209.0 50.2 259.2 Cnp_ soHs.SG 6.3 1.5 7.8 100.0 24.0 124.0 18.8 4.5 23.3 0.0 0.0 0.0 0.0 0.0 0.0 125.0 30.0 155.0 Proe plform, SHG 4.6 1.1 5.7 69.0 16.6 85.6 103.5 24.8 128.3 52.9 12.7 65.6 0.0 0.0 0.0 2300 55.2 2852 Lineppe, SG-BBB 8.7 26 11.3 49.3 14.8 64.1 0.0 0.0 0.0 0.0 0-0 0.0 0.0 0.0 0.0 58.0 17.4 75.4 Layin cating wid wnppg, SHG-BPB 0.3 0.1 0.4 13.0 5.0 18.1 2.4 0.9 3.3 0.0 0.0 0.0 0.0 0.0 0.0 15.7 6.1 21.8 Plaformnbdificans 1.3 0.3 1.6 25.3 6.1 31.4 28.5 6.8 35.3 8.2 2.0 10.2 0.0 0.0 0.0 63.3 15.2 78.5 Linpipe, ICP-Heema 10.5 32 13.7 59.5 17.9 77.4 0.0 0.0 0.0 0.0 0-0 0.0 0.0 0.0 0.0 70.0 21.0 91.0 IAyf atng and wrapping ICP-Hewa 1 9 0.5 2.4 43.7 10.5 54.1 51.4 12.3 63.7 0.0 0.0 0.0 0.0 0.0 0.0 97.0 23.3 120.3 linepipe,W P azia 0.0 0.0 0.0 22 0.7 2.9 99.0 29.7 128.7 118.8 35.6 154.4 0.0 0.0 0.0 220.0 660 286.0 laying,uidng and wrapping, UBHazkra 0.0 0.0 0.0 6.5 1.6 8.0 58.2 14.0 72.1 58.2 14.0 72.1 6.5 1.6 8.0 1293 31.0 160.3 Expanon Hazira gs termnal 0.0 0.0 0.0 68.8 54.5 123.3 82.6 65.3 147.9 82.6 65.3 147.9 413 32.7 74.0 275.3 217.8 493.1 Raesroi managemnyt, savis and equpment 35.0 31.5 66,5 32.4 30.1 62.5 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 67.4 61.6 129.0 EngIneei ad proat _ t 1.7 5.0 6.6 2.2 6.5 8.7 2.6 7.9 10.5 0.7 2.0 2.7 0.4 1.1 15 7.5 22.5 30.O Shxluinandtraing 0.0 0.0 0.0 1.0 03 1.3 1.0 03 13 0.0 0.0 0.0 0.0 0.0 0.0 2.0 0.6 2.6 ElnvIrommeti component 4.9 33 82 4.9 33 82 4.9 33 82 0.0 0.0 0.0 0.0 0.0 0.0 14.7 9.8 24.5

ne cot (199 prices) 83.5 51.0 134.5 540.5 206.7 7472 557.3 195.0 7523 354.8 139.7 494.5 4&1 35.3 83.5 1,564.2 627.7 2211.9 Physcal ontnengdes 83 5.1 13.4 54.0 207 74.7 55.7 19.5 75.2 35.5 14.0 49.4 4.8 3.5 83 158.4 62.8 '212 Prkxontingindes 6.4 8.7 15.0 62.7 5Z2 114.9 87.7 66.4 154.1 71.0 60.0 131.0 11.8 18.5 30.3 239.5 205.8 4453

Total prect coot 962 64.8 163.0 657.2 279.6 936A8 700.7 280.J 981.6 461.3 213.7 675.0 64.7 57.4 122.1 1,962.1 8963 2,87.4 Taxes and asoms duties 12.4 125.8 1363 89.6 102 374.4

Noee Total bne wot incdudes twoes and cusaous dute Vfii -90-

INDIA Anniex4.7 GAS FLARING REDUCTION PROJECr PI1rg Project Financing Plan

1. The following table shows the financing plan for the proposed project:

Proposed Financing Plan us$ "dalo

PrOJ1 ComCants Foin LoW Totl World ap ADB Export ONGC ONGC Cost Cost Cost 1ank Untied CreditsForgn Lal

Processplatfor. VQP 261.0 713 3323 261.0 713 Compre-sors,SHC 152.5 40.9 193.4 129.6 22.9 40.9 Processplatform, SHG 288.2 79.0 367.2 245.0 43.2 79.0 Linepipe,SHG-BPB 70.2 23.3 93.5 59.7 10.5 23.3 Laying,coating and wrapping,SHG-BPB 19.2 8.3 27.5 19.2 8.3 Platformmodifications 78.8 21.5 1003 78.8 21.5 Linepipe, ICP-Heera 84.7 28.1 112.8 72o 12.7 28.1 LAying,coating and wrapping,ICP-Heera 120.0 32.5 152.5 120.0 32.5 U.nepipe,BPB-Hazira 281.6 98.2 379.8 239.4 42.2 98.2 Laying,coating and wrapping,BPB-Hazira 165.4 461 211.5 165.4 35.4 46.1 ExpansionHazira gas terminal 350.4 320.8 6712 350.0 0.4 320.8 Reservoirmanagement, services and equipment 80.6 80.7 161.3 79.3 1.3 80Q7 Engineeringand projectmanagement 9.2 31.4 40.6 9.2 31.4 Studiesand training 2.5 0.8 33 2.5 0.8 Environmentand safety 17.9 13.3 31.2 14.6 3.3 13.3 Total 1962.1 896.3 2878.4 450.0 350.0 300.0 745.6 136.5 8963 Interestduring construction 204.1 101.8 305.9 204.1 101.8 Total 2186.2 998.13,184.3 40.0 350.0 300.0 745.6 340.6 996.1

Note:Export credit assumed as PS% of foraign exchange cost with balance from ONGC

2. The financing plan was developed in consultation with the Government and ONGC, taking into account external resource availability constraints outlined in para. 3.25. Given the large foreign exchange requirements - US$2.2billion - and the fact that a more extensive use by ONGC of private source borrowings did not appear feasible at this time, it was agreed that a combination of cofinancing sources would be required to make this financing plan viable.

3. ExroRrCREDrr. The effort was first made to maximize the use of official export credits, - a source so far least used by ONGC - comprising direct export credit extended from export credit agencies (ECAs) to ONGC, buyer credit offered by ECAs to ONGC, and/or credit to ONGC offered by suppliers with the backing of their respective ECAs (and, possibly, with somneparticipation from the commnercial banks supporting the suppliers). Following a request by ONGC for assistance in mobilizing the cofinancing, the Bank contacted a number of ECAs to ascertain the availability of credit and/or export credit insurance to India. These contacts confirmed that an adequate volume of export credit would be available to finance suitable procurement packages, e.g. linepipe. Based on inquiries made by ONGC, in some cases also by the Bank, it was also established that most potential linepipe suppliers would be willing to provide credit. 3ome suppliers indicated that they were prepared to arrange the financing of larger procurement packages, such as platforms. ONGC decided that it would seek suppliers' and export credits for items such as linepipe, compressors and the process platform SHG. -91 -

INDIA Annex 4.7 GAS FLARINGREDUCTION PROJECT Fage2 Project Financing Plan

4. In order to ensure that the envisaged USS 745.&million in parallel cofinancing would be forthcoming, ONGC intends to limit the bidding for the kind of packages ihdicated above to bidders offering financing at most favorable terms and conditions applicable to India under the OECD Arrange- nent on Officially Supported Export Credits ('the Consensus"), or better. The export credits extended to ONGC under the Consensus could have repayment terrns of up to 10 years and fixed interest rates. All responsive bids would be evaluated with prices and terms taken into account. (For evaluation procedure, see Annex 4.4). The Bank will continue to assist ONGC in mobilizing cofinarcing from these sources.

3. THE Ex -lm[2T BANKOF JAPAN (1-EXIM). In order to secure additional cofirancing, the Government applied in March 1991 for an untied facility from J-EXIMin the amount of US$350million equivalent. J-EXIMis currently studying this application. If accepted, the untied J-EXIMloan would provide parallel cofinancing for the expansion of the Hazira gas terminal. Procurement would be carried out under World Bank procurernent euidelines.

6. THEASIAN DEvELoPmFNr BANK(ADB). The envisaged cofinancing from ADB would finance the procurement of the laying, coating and wrapping of the ICP-Heera and UPB-Hazirapipelines. ADB would also finance the environmental component included in the project. Bank staff participated in ADB's preparatory work for the participation in the proposed project, which has been included in ADB', FY92 lending program for India. ADB has informed the Bank that they expect Board approval for their participation in the proposed project in the first quarter of 1992.

7. THEWoRLD BANK. The prcposed Bank loan has been allocated to several procurement packages. Some of those are crucial and among the most complex components of the project, such as the process platform NQP the component dealing with reservoir management. Others, such as 'pltform modifications', are not suitable for export credit and, in isolation, of little interest to other cofinanciers. Finally, components like Engineering and Project Management, and Studies and Training are considered important for the Bank to be able to adequately play its supervising role and to provide techtical assistance.

8. The total amount of US$ 340.6 million in foreign exchange resources (including US$204 million in interest during construction), which ONGC is expected to provide is sizeable. However, considering that this residual amount would be required over a longer period and that additional cofinancing sources are still being explored, it is viewed as manageable by ONGC. - 92 -

INDIA Annex 4.8 GAS FLARINGREDUCTION PROJECT FagIeTofTT Estimated Schedule of DLsbursemcnb

US$ million

IBRD Amount Cmulhti7e Pertnagc Fikl Yar Quarter rwi AmountofLam

1992 1 34.9 34.9 7.8 11 46.9 81.8 18.2 111 14.4 96Y2 21.4 IV 14.9 111.1 24.7 1993 1 26.5 137.6 30.6 11 31.5 169.1 37.6 111 36.4 205.5 45.7 IV 45.0 250.5 55.7 1994 1 36.6 287.1 63.8 11 41.6 328.7 73.0 III 29.6 358.3 79.6 IV 27.2 385.5 85.7 1995 1 20.0 405.5 90.1 11 16.0 421.5 93.7 III 13.0 434.5 96.6 IV 12.0 446.5 99.2 1996 1 3.5 450.0 100.0

Cumulative and Quarterly Disbursements US$ million

Quarterly disbursement Cumulative disbusement 50 SW

40 uve 400

11 | | |/ ~~~disburuent/

30 l B dad 300

20 20D

10 100

PY91 FY92 PY93 FY94 FY95 FY96 FY97 FY98 IBRDfisa year *93 -

INDIA Annex 5.1 GAS FLARINGREDUCTION PROJECT a-geI fl Assumptions Underlying the ProjectFinancial Analysis

Capital Costs The capital costs are based on ONGCs and the mission'sesti- mates of the costof the variousproject components For the purpose of calculatingthe financialrate of return of the project these costs have been convertedinto their equivalent in 1991US Dollars. They include physicalcontingencies of 10%of the base cost of the projectcomponents, taxes and duties estimated to average26% of the cost of items to be imported under the project. The cost of upgrading of the HBJpipeline to accommodatethe increasedavailability of gas has not been included.

OperatingCosts The operatingcosts are based on ONGCs experiencewith the operation of sirnilarinstallations. The annual expenditureshave been calculatedas follows: * Repairsand Maintenance:

(i) 1%of the capital cost of the pipelines

(ii) 3% of the cost of all other capital iterms

* Insurance:

0.2%of capital cost,excluding the costs of wellsand pipelines IncrementalPersonnel Cost Rs 6250per staff/month for 20 staff

* Overhead

US$2 million Averageoperating costs amount to about 2%of capital cost.

Gas Price The currentlyprevailing price for gas is Rs 1400per 1000m 3 (at land fall points) and Rs 2250per 1000nis (along the HBJpipeline). These prices will be revised,as soon as the Govemmentdecides to adopt the gas pricing policyproposed by the Bureauof Indus- trial Cost and Prices. A decision to implementthis pricing policy is a conditionof the nroposed loan. Implementationof this policy would raise &Lsprices to Rs 1500per 1000m' to gas producers, i.e. ONGCand OIL. The financialassessment of the projectis based on Rs 1500per 1000m'. -94 -

INDIA Annex 52 GAS FLARINGREDUCTION PROJECT Page 1 of 1 Project Financial Analysis

Capiw Opering Inaremente Irem ntMl Prim TotI Net cst Yearendrng Marct 31 Costs Experse Vdume Cas VouwCeGas US$Mpe n&fits BemIs US$ milli& USS miniort MMCMD MMCM 1000 Ms US$ miuilt USS mOim

1991 85.7 0.0 0.0 1992 55.3 85.7 0.0 (55.3) 1993 676.8 85.7 0.0 (676.8) 1994 b91.1 28.5 3.6 1.242 85.7 106.4 (613.1) 1995 470.3 37.9 3.3 1,139 85.7 97.5 (410.7) 1996 91.8 39.7 24.6 8,487 85.7 727.0 595.5 1997 39.7 22.4 7,728 85.7 662.0 622.3 1998 39.7 19.1 6,590 85.7 564.5 524.8 1999 39.7 17.4 6,003 85.7 514.2 474.5 2000 39.; 15.3 5,279 85.7 4522 412.5 2001 39.7 13.3 4589 85.7 393.1 353.4 2002 39.7 10.9 3,761 85.7 322.1 282.4 2003 39.7 9.1 3,140 85.7 268.9 2292 2004 39.7 7.7 2,657 85.7 227.6 187.9 2005 39.7 6.4 2,208 85.7 189.1 149.4 2006 39.7 5.9 2,036 85.7 174.4 134.7 2007 39.7 5.8 2,001 85.7 171.4 131.7 2008 39.7 5.7 1,967 85.7 168.5 128.8 2009 39.7 5.7 1,967 85.7 168.5 128.8 2010 39.7 5.9 2,036 85.7 174.4 134.7 Total 1,985.3 62,825

Results: Internal rate of return (FIRR): 17.5% NPV at 10% 517.7 NPV at 12% 369.3 NPV at 20% (103.8) NPV at 25% (245.8)

Note:Capital cost excludes the upgrading of theHBJ go pipeline,but indudes additonal investmnents required to expandthe capacityof the SouthBassein ps field Incrementalvolume in MMCMis basedon an average offtake of 345days -95 -

INDIA Annex 5.3 GAS FLARING REDUCTION PROJECT Page 1 of 3 Assumptions Underlying the Project Economic Analysis

Background

1. The aim ot the economic analysis is to judge whether there are enough benefits to justify the commitment of resources for the investments to eliminate the flaring of gas in the Bombay High oilfield. As described in Annex 4.2, the proposed project is part of a larger investment program (LI!-LIIIproject) aimed at increasing oil output from the Bombay High oilfield. To recover the gas that is currently flared as well as the additional gas that will become available as a result of the increase of oil output from the LII-LIIIproject, ONGC needs to expand the capacity of the infrastructure for the recovery, transport and processing gas in the Westem offshore region. Without these investments gas flaring would increase dramatically.

Table I Assumptions for the Economic Analysis

Yearending March 31 Do, ic International ExchangeRates 0,i Price, Fud 0i Natoml Gas, Inflation Infation Percenti Percent Rs pe US$ USS per barrel USS per ton Rs per 1000m

1990 8.8 6.3 17.5 25.4 151.1 2642 1991 8.3 3.4 19.4 23.8 142.3 2488 1992 6.6 3.4 20.8 20.3 123.1 2153 1993 6.5 3.4 21.8 18.3 112.2 1962 1994 6.5 3.4 23.0 19.1 116.6 2039 1995 6.2 3.4 24.1 19.8 120.4 2106 1996 6.2 3.4 25.1 20.6 124.8 2182 1997 6.1 3.4 25.9 21.5 129.7 2268 1998 6.0 3.4 26.6 22.5 135.2 2364 1999 6.0 3.4 27.3 23.5 140.7 2460 2000 6.0 3.4 28.0 24.4 145.6 2546 2001 6.0 3.4 28.0 24.3 145.0 2536 2002 6.0 3.4 28.0 24.0 143.4 2508 2003 6.0 3.4 28.0 23.8 142.3 2488 2004 6.0 3.4 28.0 23.5 140.7 2460 2005 6.0 3.4 28.0 23.3 139.6 2441 2006 6.0 3.4 28.0 23.3 139.6 2441 2007 6.0 3.4 28.0 23.3 139.6 2441 2008 6.0 3.4 28.0 23.3 139.6 2441 2009 6.0 3.4 28.0 23.3 139.6 2441 2010 6.0 3.4 28.0 23.3 139.6 2441

Notm. Weighted averagefob pnce of petroleum exports from Ol'EC countries, 1991 US Dollas Fudeloilprie, cif Bombay,1990 US DoLlars c Conresponding inland value of natural gas replacing fuel oil 1991Rupees per 100 ma

2. A review o; various alternatives for the recovery and transmission of gas carried out by Engineers India Ltd. (Annex 4.1) has established that the proposed investments represent the least cost means for eliminating gas flaring and transporting gas for use on shore. Hence, the costs and benefits are defined not with respect to the next best alternative, but in relation to 'not doing anything at all', the 'without project situation'. ONGC does have the option to limit the LII-LIII project t" investments necessary for increasing oil output and continue the flanng of gas. The approach is to L.rImate the incremental -96 -

INDIA Annex 5.3 GAS FLARINGREDUCTION PROJECT Fgo3 Assumptions Underlyungthe Project EconomicAnalysis

cost and benefitstreams associatedwith the proposed projectand compute the economicindicators of the project,the net present value at the opportunitycost of capital for India (12%),and the economicinternal rate of return (EIRR).The analysis period consistsof th' constructiontime and the operating life of the projft. Table I summarizes the main assumptionsthat were used in the economicanalysis EconormicCosts 3. The financialflows were convertedto economiccosts by (i) netting out duties and other dom 2stictransfers; tii) expressingthe importcontent at c.i.f.prices; and (iii) applying shiadowprices to don.estic components. A standard conversionfactor of 0.8 was applied to all domesticcosts. 4. The costs include the required investmentsfor the recoveryand transmissionof associated gas in the BombayHigh oilfield. The increasein gas supplies will require an expansion of the current capacity of the HBJ gas pipeline from 22 to 33.5 MMCMD. While this expansion is not part of the project, its costs were included in the economic analysis. Similarly, the additional gas pipeline from South Bassein to Hazira will be used for the transport of gas from the South Bassein gas field as soon as associated gas supplies from the Bombay High gas field are exhausted. The cost of expanding the capacity of the South Bassein gas field were included in the economic analysis of the projet. EconomicBenefits

5. Table I summarizes the assumptions that were used in the assessment of the economnic benefits from the project. Although components of this project contribute to the objective of ONGC's larger investment program (LII-LIll project) aimed at increasing oil production in the Bombay High oilfield, only the volumes of gas that will be recovered and brought to markets onshore were taken into ac, sunt in the economic analysis of the project. Similarly, the cost of the various components that serve both the increase in oil uutput and the recovery of gas were apportioned to their respective outputs. The volumes of gas and oil are shown in Table 2.

6. Natural gas has been valued on the basis of the fuel which it replaces, delivered at the point of use. For the purposes of the economic project evaluation, it has been conservatively assumed that all gas replaces fuel oil, the lowest valued replacement. International prices of fuel oil were projected based on the Bank's projections for crude oil prices, and adjusted for international transport to arrive at a cif value at Bombay. Gas used at landfall points and along the HBJ pipeline has been valued at the thermal equivalence of fuel oil cif Bombay.

7. The use of natural gas yields additional economic benefits in the form of reduced storage and handling costs, reduced maintenance costs as well as lower pollution. Further benefits result from the increased thermal efficiency of natural gas relative to liquid fuels and coal, which typically result in a 5% to 30% increase in benefits depending on the use and type of bumer. These additional benefits are particularly large where gas replaces coal. Although the magnitude of these savings varies from industry to industry, their total impact can be libstantial. As a result, the project benefits as currently measured, using, direct thermal equivalenc . gas for fuel oil, tend to underestimate the benefits of this project to the Indian economy. -97-

NDIA Annex 5.3 GAS FLARINGREDUCTION PROJECT Page3of Assumptions Underlying the Project Economic Analysis, 1991 to 2010

Table 2 Volumes of Gas and Oil Produced lInder the Project

YeandingMarch 31 Incremenegas suppliew OiaPr FuelOa GasPriwe Incr. Oa Hazira Uran Price6 Suppik s' MMCMD MMCMD USS/bbl USS/t"o Rs/l 000 m3 Mill. tons

1991 23.8 142.3 2488 1992 20.3 123.1 2153 0.6 1993 18.3 112.2 1962 C.6 1994 3.6 19.1 116.6 2039 2.3 1995 33 :9.8 120.4 2106 4.8 1996 21.2 3.4 20.6 124.8 2182 5.0 1997 19.3 3.1 21.5 129.7 2268 4.8 1998 16.3 2.8 22.5 1a5.2 2364 4.2 1999 15.0 2.4 23.5 140.7 2460 4.0 2000 12.8 2.5 24.4 145.6 2546 3.9 2001 10.5 2.8 24.3 145.0 2536 3.7 2002 7.9 3.0 24.0 143.4 2508 3.4 2003 2.9 23.8 142.3 2488 3.2 2004 . L.6 23.5 140.7 2460 2.8 2005 6.1 03 23.3 139.6 2441 2.5 2006 5.9 23.3 139.6 2441 2.4 2007 5.8 23.3 139.6 2441 2.2 2008 5.7 23.3 139.6 2441 2.0 2009 5.7 23.3 139.6 2441 1.8 2010 5.9 23.3 139.6 2441 1.7

Notes: Weightedaverage f.o.b. price of petroleumexporw front OPEC countries Fuelprice, c.i.f. Bombay tGa price atlardfl points in Indiaat parwith the valueof importedfuel oil Increasein oiloutput due to the Lll-LIllproject

Values of Incremental Gas and Oil Production, 1991 to 2000 USS milliopt

MRS~~~~~~~~~~~~~~~~'.N

Gas Oil~N -98-

IND.A Annex 5A GAS FLARINGREDUCTION PROJECr FBe 1 f1 Project EconomicAnalysis

Capi& 3pewing h,vrSMt, Ivwre,,tul Prix TOW kt wet Costs Expewu Vod.C. Voi. C- US$Per Baajts Benfts Yr US$miU,ou US$milism MMCMD MMCM I00 3 US$mion US$miim

1991 128.1 0.0 0.0 1992 43.9 110.8 0.0 (43.9) 1993 613.3 101.0 0.0 (6133) 1994 686.4 269 3.6 1,242 104.9 130.3 (582.9) 1995 426.7 35.4 3.3 1,139 108.4 123.4 (336.7) 1996 75.1 369 24.6 8,487 112.3 953.1 841.2 1997 36.9 22.4 7,728 116.7 902.2 8653 1998 369 19.1 S,590 121.7 801.7 764B 1999 36.9 17.4 6,003 126.6 760.0 723.1 2000 36.9 15.3 5279 131.0 691.6 654.7 2001 36.9 13.3 4,5 130.5 599.0 562.1 2002 36.9 1Q9 3,761 129.1 485.3 448.4 2003 369 9.1 3,140 128.1 402.1 365.2 2004 36.9 7.7 2,657 126.6 3363 299.4 2005 36.9 6.4 2, 125.6 2773 240A 2006 36.9 5.9 2,036 125.6 255.7 218.8 20O7 36.9 5.8 2,001 125.6 251.3 214.4 2008 36.9 5.7 1,967 125.6 247.0 210.1 2009 36.9 5.7 1,967 125.6 247.0 210.1 2010 36.9 5.9 2,036 125.6 255.7 218.8

Total 1,845.3 62,825

Results: Internal rate of return (EIRR): 30.3% NPV at 12% 1,3112 NPV at 20% 462.0 NPV at 25% 183.6 NPV at 27% 103.8 NPV at 37% (98.7)

Note:Capital cost indude upgrading the HBJ 3s pitpne and addit3nal ineats requiredfor inacing the cap.dty of the South Baeirn pasfied. Incemnentalvolume in MMCMis baed on anaverage offitake of 345 days -99 -

INDIA Amiexa61 GAS FLARINGREDUCTION PROJECr Pifl Project File

(Filedin the Asia Infomation Center) The Energy Sector Eighth Five-YearPlan, 1990-1995,Planning Commission,draft, November,1990 Indian Petroleum& Natural Gas Statistics,1988-89, Economics & Statistics Division, Mnir of 1tro- leum and Chemicals,Department of Petroleum& Natural Gas, Governmentof India, New Dehi The Marketfor Gas Report of the Committeeon Pricingof Natural Gas, Departmentof Petroleumand Natural Gu New Delhi, May 1990

Gas Use Policy, Department of Petroleum and Natural Gas, New Delhi, October 1990 Report of the Sub-groupon Demand Projectionsand RefiningCapacity, Working Group on Petroleumfor the Eight Plan, PlanningCommission, November, 1989 The Oil and Natural Gas Commission EighthFive-Year Plan, 1990-1995,Report of the Sub-groupon Exploration,Development and Production of Oil and Gas (IncludingGas Utilization),Planning Commission, draft, November,1989 ONGC, Annual Report, 1989-90 Oil India Ltd. AnnualReport, 1989-90

'he Project Environnwntaland Safety!ssues in ONGC'sOffshore Operations, prepared for the World mankby S.Shaw (Technica,London, United Kingdom),November 1990 WestemOffshore Gas Reserves,note prepared by ONGC,January 1991 FeasibilityReport for the ICP - Heera and SHG - BPBGas Pipelines,prepared by ONGC,January 1991 -100-

INDIA Annex 62 GAS FLARING REDUCTION PROJECr Page1 of 2 Supervision Plan bank Supervision Inputs Into Kev Activities

1. The staff inputs shown in the table below are in addition to regular supewvisionrequire- ments for the review of project implementation progress reports, procurement, financial statenmnts and sector issues. An average of 36 staff-weeks per year will be required.

Bank Staff Inputs for ProjectSupervision

Aptroximate Actjivt Anticiated Skil Inpst hi dates Requnremmts staff web

3/91-10/92 Review of IFB documentation and bid evaluations Engneermng 20 Assistance in finalizatioji of project financing pln Co-Financng 12 Review of ONGCs proiect implementation and procurement organization Procurement 8 Management/Economics 20

9/91 Supervision Mission Review of project management arrangements Engineering 6 Review of procurement progress Procwement 6 Review of project financing arrangements Economics 4 Finalize TOR for reservoir study Financial analysis 4 Review implementation of revised gas pricing and gas utilization policies Rcview of unaudited financial statements for 1990-91 Review of ONGCs investment program Review of gas marketing plans

2/92 Supervision Mission Review of ONG('s new procurement procedure Fngineeirng 6 Review of gas projects status Procurement f Review of project implemenation Economics 4 Review of gas marketing plans

9/92 Supervision Mission Review of pro)ect implementation progress Engineering 6 Review of reservoir stidy implementation progress Procurement 6 Annual review of investment program Economics 4 Review of gas marketing plans Financial analysis 4

1993-95 Two supervision missions per year Engineering 6 Economics 4 Financial analysis 4

1996 Project completion report (PCR) preparation Engineering 6 Economics 4 Financial analysis 4 - 101 -

INDIA Annex6.2 GASFLARING REDUCTION PROJECT Page 2 of2 Supervision Plan

Borowers Contributions tc Supervision

2. ONGC and the Governmentof India will be requested at negotiationsto teke the following stepsin order to facilitatesupervision of the proposed project:

(a) ONGC - to appoint a i'roject Coordinatorto supervise the implementationof the project; (b) ONGC - to submit quarterly reports on the progress of projectimplementation. The format and contentof the report will be agreed with ONGC during negiotiations;

(c) GOI (througha monitoringcommittee of the Departmentof Petroleumand Natural Gas) - to submit quarterly reports which will review the status of implementationof ONGC'sgas projectsin addition to projects whichare scheduled 3outilize gas. The formnatand content of the report will be agreed during negotiations;

(d) ONGC - to subm.t annual, unaudited financialstatements, consisting of incomneand fund flow statementsand balance sheet,within six monthsof the end of the fiscalyear, i.e. by September30 each year;

(e) ONGC - to submit annual, audited financialstatements within nine months of the end of the fiscalyear, i.e. by December31 each year. Theseaccounts would includeseparate audit reports for the projectspecial-account and for withdrawalsagainst statements-of-expenditure.

MAP SECTION

I IBRD22892 INDIA GAS FLARING GUJARAT REDUCTIONPROJECT 0 2

PROJECTCOMPONENTS: * PROCESSPLATFORMS

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