AJ ~L3 y5 , L_ /!\JDocument of

The World Bank

F'OR OFFICIAL USE ONLY

Report LNo. 9305-lN

STAFF APPRAISAL REPORT

INDIA

GAS FLARING REDUCTION PROJECT

MAY 31, 1991

Transport and Energy Operations Division

Country Department IVAsia Region

This document has a restricted distribution and may be used by recipients only in the nerformance oftheir official duties. Its contents may not etherwise be disclosed without World Bank authorization.

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CURRENCY EQUIVALENTS

(As of January 15, 1991)

Currency units = Rupees (Rs)One Rupee = US$ 0.051 (approx.)

One US Dollar = Rs 19.43

MEASURES AND EQUIVALENTS

I Million cubic meters of gas = 37 million cubic feet of gas= 6,*n500 barrels of oil= 890 mt of oil= 1,940 mt of (Indian) coal

ABBREVIATIONS AND ACRONYMS

ADB - The Asian Development Bankbbl - barrelsBcFm billion cubic metersBICP - Bureau of industrial Costs and PricesCIL - Coal india Ltd.ECA - export credit agencvEll. - Encgineers India Ltd.GAIL - Gas Authority of India Ltd.GOI - Government of IndiacOR - gas/oil ratioHBJ - Hazira-Bijaipur-Jagdishpur gas pipelineICB international competitive biddingIOC - Indian Oil Corporation Ltd.1-EXIM - The Export-Import Bank of Japankgoe kilograms of oil equivalentkm - kilometerLICB - limited international competitive biddingLNG - liquefied natural gasLPG - liquefied petroleuim gasNGL - natural gas liquidsMMCMD - million cubic meters per dayMMCM - million cubic meters per yearMOEF - Ministry of Environment and Forestsmt - metric tonMW - megawattOIL - Oil India Ltd.ONGC - Oil and Natural Gas Commission

FISCAL YEAR

April 1 - March 31

i F)OR OFFICIAL USE ONLY

INDIAGAS FLARING REDUCTION PROJECT

Loan and Project Summary

Borrower. Oil and Natural Gas Commission (ONGC)

Guarantor India, acting by its President

Amount: US$450.0 million equivalent

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

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

Project Description: The objectives of the project are:

(a) to eliminate the flaring of about 12 million cubic mneters of associatedgas per day (MMCMD) in the Bombay High oil field and improve themanagement of the Bombay High reservoir in order to arrest thedecline of oil production and optimize the ultimate recovery of hydro-carbons;

(b) to reduce energy shortages and contribute to greater efficiency ofenergy use in India's Westem Region; and

(c) to promote a greater participation of private oil companies in India's oiland gas sector.

The project is designed to recover about 25.3 MMCMD of additional gasfrom the Bombay High oilfield. The infrastructure facilities that will beconstructed under the project will make it possible for ONGC to transportup to 29 MMCMD of additional gas supplies from offshore fields in theWestern region to the Hazira gas terminal in the State of Gujarat and toUran, near Bonmbay. The project, which has been designed consistent withenvironmentally sound principles, includes:

* erection of two process platforms;

* construction of three submarine pipelines: i.e. (i) a 28 inch pipeline fromthe southern sector of the Bombay High oilfield to the South Basseingas field, (ii) a 42 inch ripeline from the South - Bassein gas field to theHazira gas terminal, .. i (iii) a 30 inch pipeline from the southernsector of the Bombay sHiL., oil field to the Heera oil field where itconnects 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 oftheir official duties. Its contents may not otherwise be disclosed without World Bank authorization,

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additional gas supplies. This will nearly double the current capacity ofthe terminal.

• the provision of support for a reservoir study of the Bombay Highoilfield. The aim of this study is to optimize oil and gas productionfrom this, India's largest oilfield, and reduce the chances for the recur-rence of excessive gas flaring. In parallel, the project will providesupport for the training of ONGCs technical staff.

* the provision of support for the implementation of a package of mea-sures required to achieve proper reservoir mnanagement practices in theBombay High oilfield.

* the provision of support also for ONGCs ongoing efforts to reduce therisk of environmnental damages from its offshore drilling operations andto improve the overall safety of thewe operations.

Project Benefits: The investments under the proposed project will increase indigenous oilproduction by about 4 million tons per year and eliminate the flaring ofabout 12 MMCMD of gas. The resulting increase in gas supplies will reduceimports of naphtha, which would be otherwise required for the manufactureof fertilizer, and of middle distillates for peak load power generation. Thiswill save India about US$350 million of foreign exchange annually (from1995/96 onwards) that would otherwise be required for the import of thesefuels. The total net present value of the investment is approximately US$1.3billion.

Project Risks: The project faces three major risks, i.e. (i) delays in the implementation of theproject which would sharply reduce its viability, (ii) delays in the offtake ofthe additional gas that will be made available through the project, and (iii)the possibility that ONGC will not be able to raise the foreign exchangerequired for the project. To minimize the risk of implementation delays,ONGC has agreed to award the construction of major items, such as plat-forms and submarine pipelines, on the basis of a series of contracts undersingle responsibility. In addition, ONGC has w-srzd closely with the Bankto streamline its organization and management for the implementaticn ofprojects. The bidding documents for all but two of the major components ofthe project will have been reviewed by the Bank before the loan becomeseffective. The risk of delays in the offtake of the gas will be signiticantlyreduced through the Govemment's decision to set up a special monitoringcommittee in the Department of Petroleum and Natural Gas that will reviewquarterly the progress in implementing the proposed project as well as theprojects that will utilize the additional gas supplies. The quarterly reports ofthe monitoring committee will be submitted to the Bank for review togetherwith recommendations in case of any slippage in project implementatioi..The Bank will have an opportunity to review the implementation of theserecommendations. To minimize the risk that difficulties in the financing ofthe foreign exchange components delay the project, the Bank has workedclosely with ONGC and the Govemment to ascertain the availability offinance through export credit agencies and suppliers' credits.

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

Proce platform, NQP 209.0 50.2 2592Compresor, SHG 125.0 30.0 155.0Proces platfDorm, SHC 230.0 55.2 285.2Unepipe, SHGBPB 58.0 17.4 75.4Co4dng and wrapping,SHG-BPB 15.7 6.1 21.8Platform modifiacdons 63.3 15.2 78.5Unepipe, ICP-Heera 70.0 21.0 91.0Laying coting a*nd wrapping, ICP-Heera 97.0 23.3 120.3iUnepipe, BPB-Hazira 220.0 66.0 286.0Laying, coahlng and wrapping, BPB-Hazira 129.3 31.0 160.3Expmnson Haim p terminal 275.3 217.8 493.1Resrvoir nanagement servic and equipment 67.4 61.7 129.1Engineering and proet management 7.5 22.5 30.0Studies and trining 2.0 0.6 2.6Environmental component 14.7 9.8 24.5

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

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

Total Financing Required 21862 996.1 3,184.3

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

Financing Plan: Srav of Finaer L1x Forei8p Totl Percent

-- US$ ilo

World Bank 450.0 450.0 14.2Asian Development Bank - 300.0 300.0 9.4Export-Import Bank of Japan ' 350.0 350.0 11.0Export/supplier credits - 745.6 745.6 23.4ONGC 998.1 340.6 1388.7 42.0

Total 998.1 2186.2 3184.3 100.0

GOf's request for financng is currenly under study by J-EXIM

Estimated Disbursements: IBRD Fisa Year Year 7 Yer 2 Year 3 Yer 4 YearrSFY92 FY93 FY94 FY95 FY96

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

Economic Rate of Retumr 30%

iNDIAGAS FLARING REPUCTICN 4 PROJECT

Table of Contents

Eage No.

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

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

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

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

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

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

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Financing Requirements ...................................... 27

IV. THE PROJECT ................... 29

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

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

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

VI. AGREEMENTS AND RECOMMENDATION ..................................... 42

ANNEXES

1.1 Energy Balances, 1980-81 to I 388-89 ..................................... 452.1 Gas Production lrojiections ...................................... 462.2 Gas Flaring in Major Gas Producing Regions ...................................... 482.3 Projected Gas Utilization ..................................... 492.4 Gas Prices ..................................... 533.1 Organization Chart of the Oil and Natural Gas Commissice ................................................. 543.2 Summary of ONGC's Accounting Practices ................................................. 553.3 ONGC Sales and Revenues, 1981 to 1990 ................................................. 573.4 ONGC Income Statements, 1981 to 1990 .................................................. 583.5 ONGC Sources and Applications of Funds, 1981 to 1990 .................................................. 593.6 ONGC Balance Sheets, 1981 to 1990 .................................................. 603.7 Performance Parameters .................................................. 613.8 ONGC's Investment Program, 1991 to 1995 ......................................... 633.9 ONGC Rcvenue 7rojections, 1990 to 1995 .643.10 ONGC Income Staternents, 1990 to 1995 .653.11 ONGC Sources and Application of Funds, 1990 to 1995 .663.12 ONGC Balance Sheets, 1990 to 1995 .673.13 Assumptions to the Financial Projections .............................................. 684.1 Layout Optimization of the Pipelines to be Constructed .............................................. 704.2 Detailed Project Description .............................................. 744.3 Project Management Organisation .............................................. 824.4 Project Implemcrnt3tion Schedule .............................................. 834.5 Environmental Aspects .................... 864.6 Detailed Project Cost .................... . 894.7 Project Financing Plan ................... 904.8 Estimnated Schedule of Disbursements ................................ 92

iiiPage No.

5.1 Assumptions Underlying the Project Financial Analysis ............................................. 935.2 P'roject Financial Analysis ............................................. 945.3 Assumptions Underlying the Project Economic Analysis ............................................. 955.4 Project Economic Analysis................. ....... 986.1 Project File ..................... . 996.2 Supervision Plan ...................... , 100

Map: No. 22892

INDIA

G;AS; FLAP!NG RMEUCTION PROJECI

STAFF AH PRAISAL, 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'heGovernment is aware of this, and continues to invest about one-third of public resources in the develop-ment of indigenous energy resources. Tl.e acceleration of economic growth during the 1980s has strainexdthe capacity of the energy sector to meet the surge in the demand for energy and, in spite of massiveinvestments in the expansion of oil, gas, coal and power sectors, energy demand continues to outstripsupply. Thus, in the years ahead, India will again have to contend with the economic implications ofsharply rising oil imports.

1.02 This puts the Government in a difficult position. It is under pressure to improve the balanceof payments, reduce the budget deficit and provide a modicum of economic growth in order to avoidlosing whatever progress has been made in the reduction of poverty during the 1980s. Und',r thesecircuinstances, an increase of oil imports will most likely necessitate a reduction in the imports of capitalgoods, while a cut in public expenditures will slow the development of indigenous energy resourcesleading 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 reducepoverty and provide employment for a rapidly growing labor force, it will need to ensur- that energy isused efficiently, thus eliminating the demand caused by wasteful energy use. It will also need to ensurethat investments in expanding energy production are guided by efficiency considcrations. This coulJ beachieved with a shift towards fewer controls and greater reNiance on market forces.

1.03 Managing the transitioni tow. ;-ds a more open, market-oriented energy sector will bxe aformidable task, since it will be carried out in an environment of increasingiv severe budget and balanceof payments constraints. The proposed project is a step in this direction. Its objectives are to eliminiate thewasteful flaring of gas, improve the reservoir management of the Bombay lHigh oilfield, reduce the needfor oil imports and help meet the energy needs in India's rapidly growing western region. While theproposed project supports change towards a more oren energy sector, it is only the beginning ot a diffi-cult transition. The following paragraphs highlight the main issues and constramints which the Governmentneeds 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 thedemand for commercial energy. While the economy grew at an average rate of 4.5%c betweeni 1979/80 ar,d1989/90, commercial energy demand grew at a rate of 6%. Within commercial energy, the demand for oilproducts 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 consumnptioni islow compared to that of other developing countries. While IndianE consume about 2(X) kilograms ot oilequivalent (kgoe) per capita, Chinese consume 540 kgoe and Brazilians 84() kgoe. Althouigh energyconsumption is relatively low in absolute terms, the Govmrnment is concerned ahout it, rapid grovth andthe relatively low efficiency with which energy is used. l1o curb the growth of delrr denmul a!id imi

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prove the efficiency of energy use, the Government continues to pursue a i wo-pronged approach. To slowthe growth of power consumption and the use of imported oil products, tho Government rel.es primarilyon rationing. In parallel, the Government has introduceo several energy coi'servation' programs toeliminiate the wasteful use of energy. Overall, the strategy has not been very efiective. Two factors artprimari!y responsible for that: the reletively high energy intensity of major sectors of the Indian economyand 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 therelatively high energy intensity of India's industrial sector and the rapidly growing energy intensity of theagrictiltural sector.

1.07 INDXUs'RY. While the energy intensity of the industrial sector has deciined by 8% during the1 980s, mostly as a result of the slower growth of energy-intensive industries, such as steel, aluminum andfertilizer, and the phasinig out of somne energy-intensive technologies in the manufacture of cement andfertilizer, the industrial sector continues to account for more than half of India's commercial energyconsumption, and, in terms of its energy intensity, India's industrial sector ranks near the top amongdc'veloping countries and well above the average among industrial countries. Several factors account forthe 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 mainobjective was to reduce India's dependence on imports. Consequently, large investmentswere made in the 1960s and 1970s in basic energy intensive industries such as steel, cement,aluminum, fertilizers, heavy chemicals, refineries, etc. All of these industries are highlyenergy-intensive and absorb a considerable share of indigenous energy production.

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

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

(d) Another disincentive for improving energy efficiency has its roots in the widespread use of'cost plus pricing' in India. This is still the most widely used approach by the Governmentfor setting prices of goods and services that fall under an administered price regime. Whilethe number of goods and services under administered price regimes has declined graduallyin recent years, they are now used mainly to price the goods and services of pubil. sectorenterprises that face little intemal or external competition. To provide some incentives tothese 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-

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ful use of energv. However, the effectiveness of these incentives has been blunted by theGovernment's willingness to provide financial support to 'sick' industries in order to preventthe closure of large enterprises aiid the loss of jobs. Price incentives for using energy effi-ciently are also undermined by the fact that protective import tariffs raise the pt ixes of finalproducts and thus lower the relative cost of energy. Thus, in spite of the fact that manyenergy 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 borderprices and electricity prices faced by industry are also close to the estimated long run mar-ginal cost . they do not result in efficiency improvements.

(e) Another objective of India's economic development strategy, which contributed to therelatively high eneigy intensity of the economy, was the decision to ensure that all parts ofthe country shat equitably in the benefits of developmenrt. To achieve this objective, theGovernment ens,red, thtough its public investnents that economic activities and in particu-lar, industries that provided employrnent were set up fairly evenly spread across the coun-try. To supply these industries with energy an extensive energy supply system based onthermal power generation using coal, India's most abundant commereial energy resource,had to be set up. In thermnal power generation only a small share (between 25% -40%) of thefuel used (coal, fuel oil, natural gas, etc.) is convertpd into electric energy. The remainder islost in the conversion process. These 'conversion losses' together with transmission anddistribution 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 basedon coal fired thermal power has contributed to the growth in the demand for middle distil-lates. Most of the coal deposits are in the eastem and central parts of India. About 70% of allcoal is shipped by rail mostly to power and industrial plants that are spread fairly evenlyacross the country. The surge in energy demand during the 1980s has strained the capacityof the railways to move coal. This has contributed to disruptions in coal supply, which inturn has encouraged investrnents in 'captive' power generation using primnarily middledistillates. Since the railways have been replacing steam locomotives with diesel drivenelectric locomotives even though steam locomotives were more cc st efficient -- theirdemand for oil products has increased sharply.

1.08 TRANSIPORT. The steep increase in energy consumption during the 1980s is partly due to thegrowing demand for energy in the transport sector. This s-ctor accounts for about one-fourth of totalenergy consumnption in India. While its overall energy intcensity has declined with the shift from rail toroad transport (mainly because of under-investment in the railway system), its need for oil products, inparticular diesel oil, has increased dramnatically. The current designs of indigenously manufactured trucksand 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 inenergy intensity, mainly for two reasons: (a) to increase productivity and (b) provide a butfer againstdroughts 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 withincreased mechanization they have contributed to the rapid growth in the demand for electricity andpetroleum 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 nowtwice the amount of energy to produce an average unit of agricultural output (for example, a ton of wheat)than it did fifteen years ago.

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1.19) Si II I:c('M I RADrIlONAI. It)C:OMMIKtlA!. I t At the tine of Independence, I r.dias iiajorsource of energy was biomass, whichl accounted for more than 85% of all energy used. Currently, biomass,mostly fuel woodi, crop r c'ue and animal wastes, accounts for less than 40% of total eaergy consumption.Several factors are responsible for the sh,ift to cornmercial energy: the growth of indcistrial production,urban,wation, thie expansion of rural electrification and price subsidies for electri( power andl kr -osine. Theprice stlhsid ics arte rooted ifn tit ( Governrment's concern about the r ural poor and t?he need to slow theprocc , (if (idton-;tation In part, the sihift a way froma traditional fuels is the result of the developmentproct- ; in part it is tit resilt of the Government's pricing policies for power ar.d oil products. While it isdoobtful wihther these pril ing pXolicieS iniC1dee achit ve their intended objectives, studies of energy use inthe rmol wtor pA)Int tito ihighly wasteful use of electricity anL a steep tise in the deimind for niddiledistillatti ' ri injo and diesl.l oill). There are also no sigins tihat the rapid pace of deforestation has sloweddown .

Energy Conservation

1.11 l'o eliminate the wasteful use of energy continues to be a major objective of theGovernment's energy strategy. Stidies carried out by the Government cstiinate that, through betterenergy demnand mnanagement andS conservation, the industrial sector could save 25% and the agriculturalsctor 30t,t of their cuirretit energy demands. Howcver, up to now the Government's energy conservationefforts have been largely ineffective A discussion of the causes of the high energy intensity of manjorsctors of the cc onowiv poinits to the linderlving reasons.

1.12 lo enscure that energy is use'l efficiently wouli require fundamental changes in the currentpolicy 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;overnmrient no longer deterna.ies 'administered' prices on theha.&,ls 1 flistorical 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 cornsumersthElmrbu orji increase s.

oin ede' to bN effective a po!licv change wouIld require thiat producers face internal oresxtesrnal i lmrtOtiiio01 thus eliminating the opportunity of absorbing increases in tihe cost ofoncts throuigh monopoflistic profits. It would also require that the Government no longerAlhSerbsL the 'osses of enterprises to safeguard employmenit.

O. ) Eln'rgy users would need to he able to use capital goods embodying energy-fficient de-signs In order to be alble to compeste, Indian entrepren1eurs would netied to bh able to purchasLe Wuionnesticallv 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 liine withni,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)lCmenItation of theoe changes ;would bring into question the fundamental values whichhave guided Indian policvmakers since Independence. The political and financial costs of such drasticchanges ws.)uld h ennormotis and 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 itsindigeniotis energv resources1 to the fullest extent, in order to minimize imports, and an energy ronserva-tion policv which 'ill ! et c! primiilv u. fn ad -hoc n trve\t.ntrt:ns aimed at curbing the blatantly wastefuluSe 01 itl I'

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Constraints to Expanding Indigenous Energy Production

1.14 As noted in the section above, efforts to manage energy demand have been largely ineffec-tive to late. Even if implemented successfully in th( future, energy conservation will not fully substitutefor the need to expand indigenous energy production to close the widening energy gap. In order to assessthe potential of further developing indigenous resources it is important to first take stock of the energyresource base of the country and the constraints to further increases of production in the main energysubsectors.

1.15 ENtcy RESOURCE BASE. 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 itspublic investment resources to the development of these resources, India depends on oil imports to meetits domestic energy needs. India does, however, have a wide range of commercial energy resourcesincluding oil, natural gas, coal, hydro-electric potential and uranium. Unfortunately their relative sizedoes not match the structure of energy demand (Figure 1). India's energy resource base is dominated bycoal. Total coal and lignite reserves are estimated at more than 170 billion tons. Although these reservesare mostly of low quality, they are India's most important commercial energy resource. India has also asizeable potential for the generation of hydro-electric energy, estimated at 100,000 MW, of which up tonow only about 13,000 MW have been developed. Environmental concems, the high cost of, and growingresistance to, the resettlement of a large number of people, disputes about water rights and financialconstraints make hydro-electric power projects increasingly unattractive. Thus, the power sector prefers toinvest in coal and gas-based thermal power generation. Considering the size of its economy India ispoorly endowed with hydrocarbon resources. Proven and probable reserves amount to about 840 milliontons. At projected consumption levels these reserves will last for about two decades. Th'is, unless explora-tion efforts succeed in raising the level of reserves, India will need to meet its demand for petroleumproducts increasingly through imports. Natural gas may provide some respite in the short run. Naturalgas reserves, which are estimated at 961 Bcrn, would permit India to significantly reduce imports of oilproducts. Up to now this effort has been hampered by conflicting policies and insufficient financialresources. Finally, India also has modest reserves of uranium, which would be sufficient to support anuclear power program of about 8000 MW.

1.'6 OIL AND GAs. Oil production has increased dramatically over the past ten years, mainly as aresult of the discovery of Bombay High and its satellite fields during the esily .)70s. These fields nowaccount for about 65% of indigenous production. Prior to the discovery of Bombay high, the oilfields of

Figure 1 Reserves, Production and Consumption of Commercial Energy in India, 1990Milluin tons of od equivalent

oilHydr. Hydro Hydro

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

Reserves (83574) Production (157) Consumption (114)%urm. Tat& Enwa R_dach Institute and World BDnk StaIf stimate

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Assam and Gujarat were the only indigenous sources of oil supply. Development of Bombay High drasti-cally reduced India's dependence on oil imports. However, in 1984/85 oil output from the Bombay Highoilfield reached a plateau. Further production increases will require the use of costly enhanced oil recov-ery technology as well as substantial investments for the development of the smaller satellite fields. TheGovemment's official projections of crude oil production (51 million tons by 1995/96 and 67 million tonsby 2000/01) indicate that ONGC expects to maintain current levels of self-sufficiency through heavyinvestments in enhanced oil recovery, the accelerated exploitation of undeveloped fields, large invest-ments in oil exploration, and substitution of a significant share of domestic oil products demrand withnatural gas. The Bank's staff is less optimistic. Based on a field-by-field review of oil reserves, the Bank'sstaff concluded that indigenous oil production would reach a peak of 42 million tons in 1996/97 and thengradually decline to about 38 million tons in the year 2000; this projection is based on the assumption thatIndia's oil companies will face no difficulties in getting the investment resources (including foreignexchange) they would need and that neither company makes any significant oil discoveries. In caseexploration efforts result in a major oil discovery during the next 2-3 years, production would continuealong the projected plateau postponing the inevitable decline of oil output. The Government's projectionsof indigenous oil production assume a significant increase in the pace of developing existing in-placereserves 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 theGovernment implement policies that encourage the efficient use of energy and substitution of oil productswith other indigenous energy resources. The proposed project, which would provide the infrastructure forthe 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 energystrategy. To meet the growing demand for coal, particularly from the power sector, the Governmentnationalized the coal industry in the early 1970s. This provided the industry with access to public invest-ment resources, and allowed Coal India (CIL) to meet the Government's ambitious coal production targetsby 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 higherquality coal mined in underground mines. Coal India's strategy led not only to a decline in the averagequality of its coal output, but also to a neglect of its labor-intensive underground mines. Freqvent realincreases in the wages of miners, poor labor discipline and low labor productivity have turned mostunderground mines into loss-making operations. Hamstrung between the need to meet production targetsand political pressure not to retrench excess labor, CIL's financial performance became dependent on themagnitude and timing of coal price increases and the allocation of pub!ic resources. In all but four yearsCIL closed its accounts with a loss.

1.18 Budgetary constraints will force the Government to sharply reduce its allocation of funds toCIL, 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 commnercial coal com-pany, and to create a poli-y environment that would attract private investment into an industry that is sovital for the growth of the Indian economy.

1.19 ELECrRIC POWER. With the emphasis on self sufficiency and a policy of balanced regionalgrowth, the electric power sector plays a key role in meeting the energy needs of the Indian economy. Notonly is electricity the prime input into industries dispersed all over the country, a large effort to expandrural electrification to substitute for oil products has further increased the demand for electric power.Total installed capacity is currently 62,000 megawatts (MW). Additions to capacity have been made at anaverage growth rate of 10 % per annum, but demand for electricity has continued to outstrip supply by10-12 %. Low capacity utilization, transmission losses, institutional bottlenecks and an inefficient pricingstructure which results in inadequate returns and disincentives to conservation have contributed tofinancial constraints and a widening power gap. Power shortages have adverse implications for the

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

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

1.21 TFERMAL POWER. Most of the existing thermnal power generation capacity is based on coal. Inlight of the vast resources of coal, the shorter construction period for thermal power stations than that ofhydro-electric plants, and the locational flexibility of thermal plants wherever access and water facilitiesare sufficient, the Govemment has increasingly invested in coal based thermal power. This investment hasnot been without cost. High conversion losses, high costs of transporting low quality coals over longdistances, high transmission losses, the firing up and idling of boilers to meet peak demand using largequantities of expensive fuel oil, and growing environmental costs of burning high ash coal are raising thecost of coal-based power generation and reducing its attractiveness as the premier option t3 meet India'srapidly growing energy demand. Gas- based combined cycle plants, which have lower energy conversionlosses 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 duringthe 1990s. Oil production will be constrained by the growing scarcity of foreign exchange and the need toshut-in an increasing number of oil wells with a high gas/oil ratios. The Bank's staff doubts that India's oilcompanies will be able to attain, under these circumstances, the Government's production target of 67million tons by the end of the decade. In addition, the financial constraints and environmental pressuresconfronting the power and coal subsectors will most likely sharply reduce the expected growth of theirrespective 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 thepast, 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 burdenon the balance of payments. Under these circumstances the Government is faced with a limited range ofoptions to bridge the widening gap between energy demand and indigenous energy supplies.

1.24 ENERGY CONSERVArON. The first option is to contain the growth of energy demand. This canonly be done through a concerted effort at energy conservation, reducing the energy consumption of thehighly energy intensive industrial, agricultural and transport sectors. While the Government is nowdedicating more resources to energy conservation efforts, the sheer magnitude of the problem and thestructural changes required indicate that it will be some time before any impact on demand will be felt,

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

Enrrgy Resources/ Sectors 1970 l980 1990 2000

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

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

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

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

S'Lurce Tata Energy Research Institute, World Bank s^ff projectons

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

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

1.27 ACci.EFRATI ED DlviELoPMFKI OF INDIGENous ENERGY REsoukcEs. The overriding objective of theGovernment's energy strategy will remain the full development of India's indigenous energy resources, inparticular its natural gas resources to meet the increasing shortage of energy supplies and reduce the needfor oil imports. The current project aims precisely at providing the requisite infrastructure to reducewasteful flaring of associated gas and optimal utilization of both associated and free gas resources in thecountry.

11. THE NATURAL GAS MARKET

2.01 Although India's reserves of natural gas are small compared to its reserves of coal and itshydroelectric potential, natural gas is playing an increasingly important role: gas takes some of thcpressure of the demand for oil pioducts (fuel oil, naphtha and kerosine); it also reduces the demand for

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coal, particularly in India's Westem Region, which is farthest away from the main coal producing areas -nIndia; it helps to reduce India's widening energy gap at a time when oil and coal production fall short ofproduction 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 over-view 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 thisgas was flared. In the rnid-1960s ONGC began to explore systematically for oil all over India. Althoughthe main thrust of ONGC's exploration efforts was directed at finding oil, these efforts led to the discoveryof several free gas fields: the Cambay Basin (in the State of Gujarat) in 1960, the giant Bombay High oilfield (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 (inthe State of Tamil Nadu) in 1989. When oil discoveries were put on production, the 'associated' or 'solu-tion' gas, which is unavoidably produced with the oil, was for the most part flared. Although the mainthrust of ONGC's exploration efforts was directed at finding oil, these efforts led to the discovery ofseveral 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 thesereserves are located in the Bombay Offshore area. Up to now about 150 Bcm of gas have been produced, alarge part of which has been flared. This quantity represents about 13% of the original recoverable gasreserves, whereas 32% of the original recoverable reserves of oil have been produced.

Table 2.1 ONGC's Gas Reserves, 1990Billion cubic etrs

Area Sod ution Gs Frw Gas Tota

Bombay offshore 64.5 391.6 456.1Kutch offshore 0.0 0.3 0.3Krishna-Godavari 2.6 18.3 20.9C^ ery 3.9 2.5 631 wr Assamn 21.6 3.2 24.8

i-Arakan Fold Belt 0.1 9.6 9.8Carnbay 37.1 55.5 92.6Rajasthan 0.0 1.0 1.0Andaman and Nicobar Islands 0.0 0.1 0.1

Total India 129.8 482.1 611.9

Source ONCC

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2.04 REGIONAL DlsrTIBunON OF GAS RESERVES. Since gas contains much less energy than oil (on avolure basis), it is expensive to transport; gas is also difficult to store; and the need to maintain a ctertainpressure in the pipeline system requires close coordination between gas producers and users. In the gasindustry, this close link between producer, gas transmission and distribution company and users, fre-quently 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 gasreserves (Table 2.1) are located close to the highly industrialized western and northwestern regions, whoseenergy 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 secondlargest reserves. There are two separate gas producing areas in this region: the oilfields of Assam andArunachal Pradesh and the free gas fields in the land-locked state of Tripura. Assam has oil and coalresources that far exceed its own requirements, and companies find it difficult to mnarket all the associatedgas. Unlike in the western region, oil companies in Assam have little incentive to develop free gas re-serves. Although gas is the major source of commercial energy in the State of Tripura, the local demand istoo small and major gas markets are too distant to justify at present the development of the gas resourcesthat have been discovered there.

2.06 1he lack of remunerative gas markets has been the major disincentive for oil companies toexplore more aggressively for gas. There is widespread agreement among geologists that future discover-ies will most likely consist of gas fields. A rapi -ly growing demand for oil and balance of paymentsconsideration will remain the driving force behind ONGCs and OIL's all-out efforts to explore for oil. Therelatively low prices producers receive for gas encourage this. Gas goes a long way towards replacing oilproducts and coal. In setting producer prices for oil and gas, the Government needs to carefully weigh thecost of encouraging oil exploration in areas that would yield high cost oil against the benefits of exploringfor 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 gasreserves could sustain a production of 90 million cubic meters per day. Yet, in 1990, India produced onlyslightly more than half of that (53.2 MMCMD). Only two-thirds of the gas produced was actually usedone-third of the total gas production was flared (Annex 2.2). The substantial gas flaring has been causedby 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 numberof institutional factors that have slowed the development of gas markets in India.

2.08 GAS FLARINC IN Tn E BOMBAY HIGH OILFIELD. The reason for the sudden increase in flaring gasduring the 1980s lies principally in the production history of the Bombay High oilfield. The reasons arevarious, some connected with the nature of the oil reservoir rock and somne attributable to the productionregime 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 thesame fluids, but in the course of oil production pressure differentials developed within the reservoir andthe 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 overallreservoir pressure drop resulting from an increase of oil production rates not being compensated ad-equately by injection of water into the reservoir below the oil/water contact, as envisaged in the originalproduction plan. The water injection plan was initiated too late and on an inadequate scale.

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2.10 The problem was further compounded by well drilling and completion techniques em-ployed in the wells. These permitted the presence of channels and voids in the current layer surroundingthe 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 bygravity, this permitted the most mobile fluids, gas and to a lesser extent water, to be drawn towards theproducing section of the well. Thus, some of the free gas from the gas cap has also been produced with theoil.

2.11 The net result of all these effects has been a dramatic rise in the gas/oil ratio from theproducing oil wells. The natural solution gas volume in the reservoir was 90 cubic meters of gas to onecubic meter of oil (GOR 90 v/v). In the north half of the field, at the start of water injection the GOR was175 v/v, and by April 1990 it had risen to 520 v/v. In the southem part of the field the producing GORwas 150 v/v until the end of 1985. Water injection conmmenced in 1987, out by the end of 1989 the GORhad risen to 360 v/v. Some wells were producing with a GOR in excess of 1000 v/v, and ONGC has nowtaken a decision to shut in such wells in order to avoid dissipating reservoir energy. In 1990 the BombayHigh 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 withan associated gas production of 26.5 MMCMD in 1990, the balance (minus the amount used for in-fielduse) 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 inattempt to seal them off and accelerated installation of water treatment and reinjection facilities. As aresult of these efforts ONGC has reduced associated gas production, although at the coti of a reduction ofoil production; as ONGC continues its strategy of containing excessive gas flaring by shutting in wellswith a high gas/oil ratio, oil output will continue to decline correspondingly.

2.13 LAcx OF PiPE NE NETuWORK. Despite huge investments in the development of offshore gasprojects, India still has a relatively inmmature gas pipeline infrastructure. Until the early 1980s little at-tempt was made to construct a pipeline network for gas distribution. There are two reasons for that. Untilthe mid-1980s the volume of gas (associated as well as free gas) available from the Bombay offshore areawas vastly underestimnated. When it became apparent during the late 1980s that gas could play a signifi-cant role in reducing energy shortages in the Western region and take some of the pressure off the balanceof payments, the Govemment could no longer mobilize the foreign exchange required for these invest-ments.

2.14 SLOW EXPANSION OF MARKJES OR GAS. In addition to the unexpected increase of associated gasin the western offshore area and the lack of pipelines for the transmission and distribution of gas, theGovemment paid little attention to the timely development of markets for the gas. As mentioned in theintroduction to this chapter, the efficient use of gas resources requires close coordination between gasproducers and consumers, (costly) investment infrastructure facilities for the transport of gas and institu-tional 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 withthe construction of the HBJ gas pipeline, the Govemment did little to encourage the growth of gas mar-kets. Poor coordination between gas producers ONGC, GAIL and najor potential gas consumers, the lackof a clear policy that would spell out how the conflicting demands on gas resources by major interestgroups, such as the fertilizer and power industries, should be resolved and the lack of a pricing policy forgas were the main factors that slowed the growth of gas markets. They will be discussed briefly in theremaining paragraphs of this chapter together with steps that have or will be taken by the Government toresolve these issues.

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2.15 POOR COORDINA110N BE1WEFN PRODUCERS AND CONSUMERS. Efficient use of gas requires carefulcoordination of plans for the production and the use of gas. This coordination is particularly critical in thecase of associated gas, where the option for suppressing its supply are usually limnited. After all, thesupply of associated gas is determined by the demand for oil and, unless reinjection of associated gas isfeasible, it has to be either used or flared. While some efforts were made in the Planning Commission inthe context of the preparation of the Seventh Five-Year Plan to ensure that tho gas supplies projected byONGC and OIL would be fully allocated to specific consumers, there was no institutional mechanism inplace that allowed the Planning Commission to change these allocation plans, in case more (or less) of theprojected volume of gas became available or designated consumers failed to use their gas allocations. TheGovernment has agreed to set up a body ('Gas Coordination Committee9) in the Department of Petroleumand Natural Gas that will monitor quarterly the implementation of oil and gas field developments andrevise gas production plans accordingly; it will also monitor quarterly the progress in construction ofplants and other facilities (pipelines, gas processingfacilities, etc.) required for the offtake of gas. Thisbody will issue a quartcrly report, in which it will list any deviation from the plans of gas producers andpotential consumers. This report will also contain recommendations for steps that would need to betaken to ensure the efficient use of projected gas supplies. Copies of these reports would be submitted tothe Bank for comments . The Bank's staff recommended that greater consideration should be given in thefuture to retrofitting existing industrial plants to burn gas, preferably on a dual-fuel, interruptible basis. Inmost other developing countries conversion has been a major early factor in the development of gasmarkets. Conversion has the advantages of short lead times, little capital requirenent and establishmentof dual-fuelled plants providing future demand flexibility. Benefits in terms of reduced oil imports aresubstantial. Increased attention to conversion and dual firing in power and industry in India could greatlyimprove the efficiency of offtake in the short and medium term. This would give GAIL much neededflexibility in coping with supply and demand fluctuations, quite apart from the environmental benefitswhich would accrue as a result of such a policy. This would obviously require construction of a secondarygas distribution system along the HBJ pipeline.

2.16 UNCLEAR GAS USE PoucIy. Until the late 1970s oil companies sold gas to consumers in thevicinity of oilfields at whatever price the market would bear. The completion of the gas pipeline fromBombay High to Uran in 1978, following upon the discovery of the large reserves of South Bassein twoyears previously, led to an examination of gas use options by the Govemment. In 1979 a committeerecommended that butane and propane (C3/C4) fractions be separated for liquefied petroleum gases orbottled 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 wouldsubstitute for naphtha. Use for power generation was rejected in view of the availability of domestic coalat prices competitive with the high oil prices prevailing at that time. The economics of fertilizer produc-tion, which favor location of plants close to consuming areas, and the desire to spread the benefits ofoffshore gas to states other than Maharashtra, led the committee to reconmmend that the bulk of gas shouldbe allocated to fertilizer plants in the Westem and Northern states. To supply these plants, the 1300 kmHazira-Bijaipur-Jagdishpur (HBJ) pipeline was constructed to take gas through Gujarat and Rajasthanto Uttar Pradesh. During the 1980s the Government's gas utilization policy shifted towards broader usesfor gas, for power and liquid fuel replacement in industry. This change of policy was due to a perceptionthat gas availability would exceed the requirements of the fertilizer sector, and to the increasing attractionof combined-cycle power plants for reducing India's power shortages, particularly in regions away fromthe coalfields in the eastern part of the country. It was decided to construct eight combined cycle powerplants, with total capacity of 1500 MW along the HBJ gas pipeline.

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

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(a) Construction of three of the six fertilizer plants planned in the early 1980s has only startedvery recently. This has been due to the delays in the authorization process and to changes inthe fertilizer pricing system after authorization of the plants, which reduced the profitabilityof 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 tooperate at base load as originally planned, because the higher unit cost of power from newgas-based combined cyclc plants has made it difficult for the National Thermal PowerCorporation to sell their electricity to the SEBs. SEBs can purchase base-load power morecheaply from older coal-fired thermal power plants.

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

(a) first priority is given to the elimination of gas flaring, except where flaring cannot beavoided 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 atime-bound gas utilization plan and the signing of gas contracts well in advance of the actualuse of the gas;

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

(d) preferenre should be given to the allocation of gas to the power sector. The rationale for thisrecommendation is based on India's persistent power deficit, and the fact that, unlikefertilizer where imports are likely to be less expensive than domestically produced fertilizerfor the foreseeable future, power cannot be imported. However, gas should not L allocatedto 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. Powerplants that generate power for peaking purposes could use free gas, since there is greaterflexibility in adjusting gas supplies from these fields.

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

(f) to reduce the risk of delays in the offtake of gas, the Department of Petroleum and NaturalGas should be authorized to seek commitments for the use of gas that exceeds projectedavailabilities 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 beenimplemented. Its current commitments to potential gas consumers (Table 2.4) exceed pro-jected gas supplies and offtake by a sizeable margin.

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

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Table 2.2 Reserves and Marketed Production of NaturalGas in Selected Developing Countries, 1990

Bill wn cubk wmiS

Country Resere Produc*im

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

Sources: Oil and Gas journal, ONCC, UN World Energy Statiscs

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

2.20 LACX OF A Ct.rEAR RFSPONSIBILnTY FOR GAS MARKIN. Production, transport, and distribution ofgas is entirely in the hand of state organizations, mainly OCNGC, OIL and GAIL. Gas supplies are allocatedadministratively by the Department of Petroleum and Natural Gas. Until recently both the producingcompanies, ONGC and OIL, and GAIL were allowed to sell gas to final consumers. To ensure the orderlymatching of supply and demand, and the consistency of demandfrom established plants, the Governmenthas decided to streamline all marketing activities and transfer the sole responsibility for the marketing ofgas in India to GAIL. This decision greatly strengthens GAIL's role as a gas marketing company, bringingtheir operations closer into line with gas marketing companies in industrial countries. Apart from elimi-nating inefficiencies in the marketing of gas, this decision will make it easier to implement the recommen-dations 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 devel-oping countries (Table 2.2). The Government's current plans call for the full development of the remainingdiscovered gas resources during the 1990s, which will lead to a substantial increase in gas availability inthe medium term. Expected gas production in India's major gas producing region, the Western offshorearea, is shown in detail in Annex 2.1. Table 2.3 which summarizes these projections, shows that associatedgas production will decline fairly rapidly after the year 2000. The significance of these figures can beappreciated when it is realized that 1000 cubic meters of natural gas have approximately the sante calorificvalue 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 gasare in the west of India, whereas the coal fields are nearly all in the east, the substitution of gas for coalcan lead to substantial economic and environmnental benefits.

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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 fertiliz-ers, power and industry close to the terminal at Uran, with substantial potential demandarising from Bombay's concentration of heavy industry;

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

(c) the Northern market se-ved by the HBJ gas pipeline. The primary users along the gaspipeline 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 inthe three gas markets served by the project. It also contains a review of the status of implementation ofprojects 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 TtuF BOMBAY MARKET. Bombay is one of the more industrialized arees of India, and gas isconsumed by power stations, fertilizer and petrochemical plants. The market for gas in Bombay is pro-jected to expanc to 16 MMCMD by 1995, partly due to increasing consumption by existing consumers andpartly to the construction of new petrochemical and metallurgical plants. This market has a large energydeficit, and the Bank's staff agrees with GAIL's expectation that all allocated gas supplies will be utilized.

2.24 THlE GUJARAT 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 byfertilizer and power plants, and some 50 industrial users. In general this is an energy-deficient region, andsince gas will be sold at 'landfall prices', the Bank's staff expects that there is only a small risk that therewill be significant shortfalls in the offtake of the gas supplies a,located to this marke..

2.25 TinE NoR11iaLN MARKET. ThM HBJ gas pipeline has currently a capacity of 20 MMCMD. Withadditional 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 ofgas have been listed in paras 2.08 - 2.16. GAIL charges consumers along the pipeline an additional fee ofRs 850 per 1000 m3. 'Te National Thermal Power Corporation has pointed out that it cannot sell powergenerated in combined cycle power stations to SEBs at prevailing power tariffs and the higher gas pricesalong the HBJ gas pipeline. Offtake of gas along the HBJ poses a serious marketing risk for gas. This riskhas been further heightened by the growing scarcity of investment resources, which may delay thecompletion of projects along the HBJ gas pipeline. The Bank's recommendation to set up a monitoringbody in the Department of Petroleum and Natural Gas (para. 2.15) makes it possible for the Goven.mentto redirect gas supplies to the Gujarat market in a timely manner. If there ar,. clear indications that the gassupplies allocated to users along the HBJ are not utilized, the Governrment and GAIL wi'l have to rethinktheir gas marketing strategy for the western offshore region, and address the constraints that prevent themarketing 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 timelydevelopment of gas markets. Gas pricing is a highly controversial issue. The Government has informallydiscussed the various options for pricing of gas with the Bank. The policy that is currently before theCabinet is in line with the Bank's recommendations.

* l6-

Table 2.3 Gas Production and Utilization in the Westem Offshore Region, 1991 to 2010Millaim cubic metm per day

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

1991 17: 7.5 24.6 20.0 12.5 12.5 12.1 24.61992 t:7.5 9.7 27.2 20.0 14.7 12.5 12.5 27.21993 13.8 13.8 29.6 20.0 17.6 12.5 12.0 29.61994 20.7 15.3 36.0 200 20.0 16.0 16.0 36.01995 23.3 12.7 36.0 20.0 20.0 16.0 16.0 35.01996 32.2 28.8 61.0 45.0 28.0 16.0 14.0 42.01997 30.3 30.7 61.0 45.0 38.0 16.0 14.0 52.01998 27.3 33.7 61.0 45.0 45.0 1&0 16.0 61.01999 26.0 35.0 61.0 45.0 45.0 16.0 16.0 61.02000 23.8 37.2 61.0 45.0 45.0 16.0 16.0 61.02001 21.5 39.5 61.0 45.0 45.0 16.0 16.0 61.02002. 18.9 42.1 61.0 45.0 45.0 16.0 16.0 61.0200.3 16.6 44.4 61,0 45.0 45.0 16.0 16.0 61.02034 15.0 46.0 61.0 45.0 45.0 16.0 16.0 61.02005 13.6 47.4 61.0 45.0 45.0 16.0 16.0 61.02006 11.6 49.4 61.0 45.0 45.0 16.0 16.0 61.02OCr 10.5 50.5 61.0 45.0 45.0 16.0 16.0 61.020038 9.5 51.5 61,0 45.0 45.0 16.0 16.0 61.02(X9 9.0 52.0 61.0 45.0 45.0 16.0 16.0 61.02210 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 pipelineconstraintsI Free gas production includes production from new known fields (Annex 2.1) with additioinal produc-tion from South Basseinaasumed as meeting denud as reqired.Sourre ONGC and mission estimates.

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

2.28 EVOLULnON OF A PRICING POLI, Y FOR NATURAL GAS. In India gas has historically been vroducedalong with crude oil. Since most such gas, which would otherwise be flared, is sold to consumers on acost-plus basis, there has been no pressing need for a comprehensive gas pricing policy. With the i dventof larger vohtmes of offshore associated gas from Bombay High, ONGC and the GOI have been moving

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more towards replacement pricing over the past few years. As a result, a numTlber of dlifferent pricinglevels have evolved based on contractual arrangements negotiated at different times in different regions otthe country. For example, on shore associated gas from Gujarat has been pricedi as low as Rs 355 per1000m3. Although this price is the result of a decision by an arbitration cormnittee, it is indicative of thelow contractual prices ONGC received as a result of the lack of alternative markets for gas at the tinme otfield 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 thes higherpnce 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 examinedvarious 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 tousers to be uniform along the pipeline, and

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

Mlarket/ Sector 1991 l992 1993 1994 1995

Bombay marketFertilizer 5.10 5.10 5.10 5.40 5 40flower 4.50 6.00 6.00 6.(X0 6(0)Industry 2.98 3 73 3,74 5 94 W.10Other 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 marketFertilizer 3.30 3,30 3.30 3 30 3.30Power 0.00 0,00 0.0() 2.25 2.25Industry 0.80 0.80 2.80 3.7(0 4.70Otther 1 00 1 00 1.3(2 1.30 1 30

Subtotal Gujarat market 510 5.10 7.40 10.55 11 S5Expected offtake Gujarat market 5.10 5.10 7(X) 9.25 1(00

Northern market (HBJ pipeline)Fertilizer 5 40 5,40 5.40 1 2. f 14.40Power 5.10 7.60 7.60 7.85 11 85Industry 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 3445Expected 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

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(c) the gas company, GAIL, should earn a fair return on costs. Any surplus would accrue at theproducer 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 announcedin 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 per1000m3. Allowances are Iso made for discounts in the cases of interruptible users, and toencourage 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 gasand, 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 averageproduction cost of gas from the South Bassein (free) gas field, and proposed a price of Rs1500 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 marginalreplacement fuel. The BICP based its recommcndavion on the assumption that gas shouldprimnarily be used to replace costly tradeable oil products, wherever this was technica-llyfeasible. Annex 2.4 ..lustrates this approach. It is based on the Govemment's projections ofgas 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, 1991US DLar5

Fuel Type of Use Unit Ex Refinery Price Wltolel CIF Price Ratio of WhoksaekEx Pithead Price Price to CIF Prices

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

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

Notes: ' Wholesale prices in BombayNatiural gas prices refer to producer price and price alcng the HBJ gas pipelne (including taxes), respectively

XCoai price refers to coal (2330 KcAl) from the Maira mine, Chandrapur, delivered at BombayImporta,d coal is estimated to have 6500 Kca.

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prices of fuels competing with gas. The BICP decided on fuel oil as the marginal replacementfuel, and proposed that gas prices to consumers should be brought in line with the cost ofinternational fuel oil prices. The Govemment has decided to implement this volicy over athree year period starting July 1, 1991. In the first year gas prices (at landfall points) will beraised to Rs 1550 per 1000m3; in the second year to Rs 1650 per 1000m3; and in the third yearto Rs 1750 per 1000m3. At the end of the third year gas prices will be raised to Rs 1850 per10o0m3 .

(c) the committee recommended that Gas Authority of India nimited (GAIL) should be alloweda margin of RS 850 per 1000m3 for transport and distribution costs. This was the recom-mended price for all consumers along the HBJ pipeline regardless of distance from thesupply 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 ofonly Rs 600--1000 per 1000m3.

2.32 The proposed gas pricing policy is line with the pricing principles the Bank has recom-mended. The link between domestic gas prices and international fuel oil prices eliminates much of thearbitrariness that governs the Govemment's price setting practices by tying the price Indian consumershave to pay to the international market price of the marginal replacement fuel. The Government hasagreed to discuss any proposals for revisions of 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 1970s when thedevelopment of ONGC's giant Bombay Hign o,J i. ld was first undertaken. The projects financed fromBank loans since then have been successfully c 't eted and have achieved their main objectives. The firstBank loar helped finance the Bombay High OtnI,-c Development project (Ln. 1473-1N). This was fol-lowed by the Second Bornbay High Offshore D"' ,.nment project (Ln. 1925-1N), the Krishna GodavariPetroleurni Exploration project (Ln. 2205-IN) anc aLbe Cambay 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 ofassociated natural gas along with the large natusa,' .c r-served discovered at South bassein, the Bankshifted the emphasis u f its support to the naturail g, d ector. A need was foreseen to come to grips withsuch critical issues as gas utilization, sector plannin, :..nd gas pricing. The Bank's first lending operation inthe gas sector was to help Finance the South Bassein C. - Development project (Ln.2241-IN); this wasfollowed 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 akn unprecedented rate and in the processONGC has developed into a full-fledged production ol onmpany. Despite its rapid growth ONGC hasbeen able to train and maintain i competent and dedicated staff. ONGC, however, has one weaknesswhich 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, causesnumerous delays which past experience has shown can add two or more years to the projection comple-tion 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.

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

2.35 T'i; BANK"' laNDoINC STRArhC;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 develop-ment of gas markets in line with the existing gas production potential. Thus, in parallel to its ongoingsupport for gas projects with ONGC and OIL, the Bank increasingly seeks to support GAIL's efforts toexpand 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 Highoilfield 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 ensurethat gas will be used efficiently under the proposed project, the marketing plans for gas have been re-viewed with the Gas Authority of India Ltd., fall back plans for the allocation of gas have been drawn upin case sonme users are unable to utilize their gas allocations and a body will be set up in the Department ofPetroleum and Natural Gas that will monitor progress in the implementation of gas projects as well as ofprojects that will utilize gas

2.37 Several projects with ONGC have taken longer to irrnA!ement than anticipated at appraisal.ONGC's complex decision making structure has been a major cause of these delays. ONGC has requestedthe 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 proposedproject. ONGC was established by the Government in 1959 as a statutory body to plan, promote, organizeand implement programs for the development of oil and natural gas resources and the sale of oil andnatural gas products. ONGC, which is fully owned by the Government, now shares this mission withseveral other publicly-owned corporations. About 10% of India's oil and gas output is produced by OilIndia Ltd. (OIL), whose operations are concentrated in India's northeastem region, mainly Assam, andRajasthan. Refining of crude oil and the marketing of oil products is in the hands of six refinery and threemarketing 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 isin the hands of the Gas Authority of India Ltd. (GAIL). All of these corporations report to the Ministry ofPetrolcum and Chemicals. All major investments in the oil and gas sector have to be approved by theCabinet Committee on Economic Affairs following a recommendation by the Public Investmer; Board onwhich all concerned ministnes as well as the Planning Commission are represented. Decisions on the

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pricing of oil and gas products are made by the Cabinet based on reLconunenddtions Of the Mfililstrv efPetroleum 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'ithan two, but not more than eight Members. Members are appointed by the Government for ternis notexceeding five years and are eligible for reappointment. The conmmission sets policies, manages theactivities, and develops plans and budgets for ONGC. All decisions must be approved by a majority ofMembers. At present, the Commission consists of the Chairman and six Members from within ONGC andtwo 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'sday-to-day operations.

Institutional Issues

3.03 GREATER MANAGERIAL EFFcCENcY. In 1986, ONGC's oard reorganized the activities of theCommission along functional lines and regions. The objective of the reorganization was to improve theoperational performnance, raise accountability, and achieve greater coordination between functionalgroups. Six regional 'business centers' were established that integrated all activities of each region (Annex3.1). Each business center is headed by a regional director. Within each business center, staff is organizedalong functional lines (e.g., exploration, development) in the form of business groups. ONGC has set upeight institutes with the aim of providing technical support and training to the staff in the business groupsin each regional center. Each member of the Commission is in charge of one of the regional centers. As aresult of this reorganization ONGC has been in a better position to deal with the strains caused by therapid growth of its operations. Over the past ten years, ONGC was able to increase oil output by almost15% per year while keeping the growth of its staff to 1% per year.

3.04 GREATms AUroNomyc. As a statutory body, ONGC's room for tak"nG decisions is constrainedby Govemment prevailing policies and procedures. In order to reap the full benefits of its efficiencyimprovements, ONGC uses Memoranda of Understandings with the Government (MOUs) to define itsresponsibilities vis-a-vis the Government, to minimize Government interference in its day-to-day opera-tions 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 totake to speed up approvals. Subsequent MOUs extended ONGC's autonomy, and in 1990 the Governmentgranted ONGC far-reaching autonomy over its foreign exchange budget. ONGC can now spend 75% of itsapproved annual foreign exchange budget; the remaining 25% will be released by the Government afterONGC provides the required detailed information. In many respects, ONGC's autonomy is now compa-rable to that of other public sector corporations.

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

3.06 DIvTrErRE. ONGC uses not only the services of existing domestic private and public sectorcompanies, it also assists former employees in setting up cooperatives and joint ventures with foreigncompanies. 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. Theyinclude charter hiring of drilling rigs; helicopter, marine and diving services; operation and maintenanceof installations and vessels; soil investigation, surveys, well logging and production testing. Nlost of these

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

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

3.08 Up to now, there have been three "rounds of offerings of exploration acreage". The first tworounds mnet only with limnited success. The industry felt that the terms of the production sharing contractswere 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 submittedbids for two blocks and only one contract was signed. In the second round in 1982, the Governmentoffered 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 27offshore blocks that were offered, seven international oil companies submitted 12 bids. A fourth round isexpected to be announced by the Government before August 1991. The contractual termns will be similar tothose of the third round. These terms are in line with international practices. Despite the lack of success ofthe three previous rounds, international oil companies appreciate that India is essentially stillunderexplored, particularly in technically difficult areas such as the Bay of Cambay, Kutch and thepossible western extension of Bombay High in deeper waters on the continental shelf and slope. Thefourth 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 drillingoperations - a practice followed by most international oil and gas companies. ONGC's accountingsystem, which is computerized, meets the requirements for financial accounting, budgetary control andcost and mnanagement accounting. ONGC prepares detailed rolling budgets that are largely based onphysical performance targets (million tons of oil produced, meters drilled, etc.) for each of its operatingunits. Since achievement of the agreed physical performance targets remains the paramount objective ofONGC's management, the budget system lacks sufficient orientation towards cost control and improvingefficiency. It also makes it difficult to respond to changing circumstances. ' "anges in performance targetsfrequently require ministerial or cabinet approval, particularly when foreign exchange expenditures areinvolved, resulting in delays in implementation of corrective measures. ONGC is aware of this and isintroducing changes that will make the budget a more effective tool for enhancing efficiency. Long termfinancial planning is currently only carried out in conjunction with the Government's five year plans, butsteps 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 systemwhich makes it possible for management to assess ONGC's operational performance through detailedmonthly reports and other reports. ONGC is in the process of computerizing the system by establishingsatellite 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 theCorporate Management Group undertakes management audits on a regular basis. The audit arrangementsare satisfactory. ONGC has agreed that its annual accounts, including the audit report of the specialaccount and the statement of expenditures for the project, if any, will be made available to the Bank

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

Fiscal yr ending March31 1986 1987 1988 1989 1990

Volumes sold: Crude 0hi (mill tons) 26 28 27 29 30Natural Gas (MMCM) 3,3( 5,042 5,873 6,932 8,610LPG 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 63.2Otherrevenues 5.7 8.3 11.6 16.0 18.1

Total Revenue 43.9 563 61.1 69.7 81.3Royalties, excise cess and sales tax 12.3 21.8 24.6 28.1 37.2Total revenues retained 31.1 34.5 36.5 41.6 44.1Total operating expenses 10.7 12.2 15.3 19.9 22.9Operating income 20.4 22.3 21.2 21.7 21.2Les: Interest (net) 1.6 1.2 0.7 0.8 1.0Corporate taxes 6.0 6.2 5.4 4.9 4.0Net operating incorme 12.8 14.9 15.1 16.0 16.2Dividends 0.3 0.4 0.4 0.5 0.5

Net income retained 1Z5 14.5 14.7 15.5 15.7Key financial ratios

Operating ratio (revenues retained) (Percent) 34 35 42 48 52Return on total equity (Percent) 32 27 21 19 16Return on average net fixed assets (Percent) 31 28 23 21 19Return on capital employed (Percent) 22 20 17 16 14Dividend as Percent of total equity I 1 1 1 1Current Ratio (times) 1.3 1.5 1.6 1 8 1.7L.ong-term debt to total equity ratio (times) 0.5 0.5 0.4 0.5 0.5Debt service coverage (times) 4.8 1.9 3.6 5.4 2.8Self 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 unauditedfinancial statements (income statements, funds flow statement and balance sheet) to the Bank within sixmonths of the end of the fiscal year.

Financial Performance

3.12 The financial performance of ONGC over the past ten years is sunmmarized in Annexes 3.3 -3.6. An overview of its performance during the past five years is provided in Table 3.1. The table showsthat ONGC's operations grew rapidly during the past ten years. Sales of crude oil increased from 9 milliontons in 1981 to 26 million tons in 1985 and 30 million tons in 1990. Sales of natural gas increased moregradually from 972 MMCM in 1981 to 8610 MMCM in 1990, an average increase of about 27% a year. Totalrevenues 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 netfixed assets in operation have declined since 1986. This is to a large extent due to the Government'sdecision not to raise ONGCs net retention price of Rs 967.85 per metric ton (mt) of crude oil which hasbeen aimde at this level since July 1981 in spite of increasing operating costs, rising inflation and a steadydevaluation of the Rupee. Similarly for natural gas the basic price of Rs 1,400 per 1000 m3 has been ineffect since 1985. Taking into account the devaluation of the Rupee over the past ten years, the net reten-tion price for oil has declined from US$123 per mt (equivalent to US$17 per bbl) in 1981 to US$54 per mt(equivalent to US$7 per bbl) in 1990. In spite of the lack of adjustments in the producer prices for oil and

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gas, ONGC's financial position has remnained sound. All its financial ratios agreed with the Bank underpreviously 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 theSeventh Plan (1980-90). The high self-financing ratios reflect the rapid growth of oil output from theBombay High oilfield, where production costs are lower than in other Indian fields, a reduction of corpo-rate 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'srequirement that all foreign currency expenditure on capital projects be financed either directly or throughthe Government from official sources. Sources, timing and currencies of foreign loans are decided by theMinistry 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 3.2provides an overview of ONGC's sources of finance.

3.16 Over the past ten years, some 42% of ONGC's total foreign exchange requirements (includ-ing capital expenditures, operating costs and debt service requirements) were met from the country's freeforeign exchange resources. The remaining 58% of the total foreign exchange requirenents were securedthrough direct borrowing from foreign private sources or indirectly from loans (mostly from the WorldBank) on-lent to ONGC by the Government. During 1985-90, ONGC's foreign borrowing amounted to Rs55.4 billion (about US$ 3.2 billion) of which 88% consisted of long term syndicated loans and issues ofsecurities, both predominantly US Dollar denominated and arranged with the help of US, Japanese and

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

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

Funding requirementsTota! capital e>penditures 17.36 18.96 18.96 23.29 31 00 109.57Total debt service 4.74 13.34 7.86 6.43 13.67 46.04Corpx)rate taxes 5.96 6.21 5.35 4.93 3.97 26.42Inaease 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 41.88 174.60Borrowings:

Domestic be-rowmngs 0.08 0.04 0.02 0.02 0.00 0.16Foreign currency loans onlent by GOI 0.93 0.76 1.60 1.00 1.35 5.64International capital market borrowings by ONGC 2.81 13.74 7.87 8.40 16.12 48.94Suppliers/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 55.40Total sources 32.50 45.49 43.20 49.46 59.35 230.00Surplus 0.64 1.81 9.58 13.60 6.14 31.77Used 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

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European private banks and security houses. Such wide market access enabled ONGC to minimnize theuse of tied, market priced financing, such as export and supplier credits. As of March 31, 1990, ONGC'stotal direct foreign currency long term debt amounted to Rs 48.1 billion (equivalent to about US$ 2.8billion 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 9.3billion.

3.17 ONGC has sought to insulate itself to the extent possible from the risks associated with itsgrowing foreign exchange indebtedness; it sought to diversify the currencies in which it borrowed, andstrike a balance between fixed and floating rate borrowings; it also arranged a number of interest rateswaps. In 1987, ONGC prepaid some loans in order to take advantage of the drop of interest rates ininternational financial markets. However, since ONGC has no direct foreign exchange earnings, itsoptions 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 SeventhPlan, ONGC contributed about R.s 16.5 billion to the budget of the Central (Rs 14.5 billion) and StateGovemment (Rs 2 billion) in the form of excise cess, royalties, duties, corporate tax and dividends. TheGovernment's policy regarding producer prices for oil and gas and ONGC's borrowing strategy haveallowed ONGC to generate substantial Rupee surpluses, which have been used for long term investmentsin public sector securities and public sector undertakings. On March 31,1990, the total value of theseinvestments and loans was about Rs 35 billion (about US$2 billion). It has provided ONGC with substan-tial 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 andinternationial oil companies. Unlike private intemational oil companies, whose main objective is profitmaximization, ONGC's role is more complex. While its primary role is to explore for and develop India'soil and gas resources, ONGC remains an important vehicle for raising revenues in domestic markets andforeign exchange loans in intemational financial markets. ONGC has also emerged as a major institutionalinvestor in non-oil and gas related activities in India. To foster this role, the Government has kept pro-ducer prices well in excess of ONGC's production costs and, more recently, reduced the corporate tax rateto compensate for inflation and the devaluation of the Rupee. Administered prices for crude oil and gashave protected ONqGC from fluctuations of oil prices in international markets and its near-monopolyposition shelters it from competitive pressures. To ensure that ONGC operates efficiently, the Governmentmonitors ONGC's operations through the physical and financial performnance targets agreed in the annualMOUs. Annex 3.7 provides a comparison of ONGC's performance in terms of selected cost and otherratios.

3.20 ONGC's production costs for cTude oil have re-rined well below the import parity pricethroughout the 1980s. In 1990, ONGC's average production costs at the wellhead were about US$25 perton of oil (US$3.42 per barrel) and US$48 per 1000 m3 of gas. Offshore production costs were US$22 perton for oil (US$3.0 per barrel) and US$38 per 1000 m3 of gas. After declining steadily until 1988, ONGC'sproduction unit costs in 1989 and 1990 and operating expenses in 1990 increased considerably. This wasdue to several factors: rising inflation, the devaluation of the Rupee, higher financing costs a less success-ful exploration program in these years, which increased the level of amortization and ONGC's costlyindigenization policy (para. 3.06). In spite of these cost increases, ONGC's production costs are rough)v inline with those of oil and gas companies of this size. Its reserve to production ratios of about 22 for oil and41 for gas remain at acceptable levels.

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3.21 There is, however, room for efficiency improvements. With a staff of about 47,000, ONGCsproduction of about 17 bbl of oil equivalent/day per employee is relatively low by international stan-dards. Its average drilling cost has declined to about US$ 541 per meter in 1990 but remains high byinternational standards. Continuous involvement of the Bank with ONGC has, over the years, led toimprovements in operational efficiency as well as policy changes with respect to increased involvement ofthe private sector. ONGC has recently requested the Bank to review project implementation arrangementsand its reservoir management. As ONGC owns most of its field service equipment, compared to other oilcompanies, the Bank has recommended improving efficiency by farming out services to both domesticand 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 interna-tional oil companies to explore for oil and gas in India will expose ONGC to state-of-the art explorationtechniques and efficient operations, particularly if ONGC enters into a production sharing agreement withthe foreign oil companies. While ONGC's mnanagement favors close interaction with the private sector,particularly through joint ventures, privatization of ONGC would be politically not feasible. Bank supportfor the Government's policy to increase ONGC's exposure to a more competitive environment extpnd itsautonomy and shift the emphasis from attaining quantitative targets to efficiency improvements, wouldachieve similar objectives.

Investment Program

3.22 ONGC's level of capital expenditure almost doubled from Rs .58 billion during the SixthPlan (1981 - 1985) to Rs 110 billion during the Seventh Plan (1986-1990). Output from the Bombay Highoilfield accounts for about 60% of indigenous oil production output has reached a plateau and will declineby 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 produc-tion from existing fields. Investments during the Eighth Plan (1991-1995) are expected to amnount to aboutRs 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 1995R.- billion

Fiscal yearending March31 1991 1992 1993 1994 1995 Toal

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

Surveys 1.4 1.3 !.0 1,0 1.1 5.8Exploration drilling 10.7 10.1 5.3 4.0 4.7 34.8Development drlling 5.3 6.5 4.0 4.4 2.5 22.7Research 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 35.5 200.4Total investments (current prices) 31.5 37.8 57.5 52.2 42.9 221.9of which foreign exchange expenditure 10.1 12.5 31.6 29.8 22.8 106.8Project cost 1.3 1' 0 20.5 15.2 54.0Percent of total capital expenditure 4.0 3 0 39.0 35.0 24.0

Notes: 'Includes price escalation Rupees 62 billion of project expenditure vill be spent in 1996Proiect cost excludes equipment and services for reservoir management as they we consideredto be operstional expendituresSource ONGC and Bank staff estimates

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Table 3.4 ONGC Financial Projections, 1991 to 1995

Fiscalyor ending AMarch 31 1991 1992 1993 1994 1995

Volumes sold Crude ol (milL tons) 29.4 31.1 31.8 38.0 43.5Natural gas (MMCM) 9,875 11,170 15,527 19,211 20,506LPG, 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 92.0Other revenues 21,7 25.1 3Z5 39.4 41.8Total Revennes 63.7 90.8 99.6 119.8 133.8Royalties, excise cess and sales tax 37.4 40.0 45.1 51.8 58.8Total revenues retained 463 50.8 54.5 68.0 75.0Total operating expenses 31.2 29.9 30.0 38.6 41.5Operating income 15.1 20.9 24.5 29.4 33.5Less: Interest (net) 2.0 1.7 3.5 6.9 9.3Corporate Taxes 3.0 4.2 4.9 5.9 6.7Net operating irpcome 10.0 15.0 16.1 16.6 17.5Dividends 1.0 1.1 1.3 1.4 1.6Net income retained 9.0 13.9 14.8 15.2 15.9

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

Source: ONGC and Bank estimates

would represent about 24%. ONGC's investment program is summarized in Table 3.3, and details aregiven in Annex 3.8. The bank supports the objectives and strategy reflected in the proposed investmentprogram. ONGC has agreed to review its investment program annually with the Bank together with theimplications 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. Thefinancial projections are based on the assumption that the retention price for crude oil and gas will remainunchanged. The projections show that, in spite of rising inflation rates and a gradual devaluation of theRupee against the US Dollar and other currencies, ONGC will remain financially viable. However, ONGCwill no longer generate sufficient resources to fully finance its investment program, working capital anddebt service, but it is expected to have sufficient borrowing capacity to supplement its own resources andto raise foreign exchange. Also, unless the Government decides to raise producer prices, it would need todivest part of its non-oil related investment portfolio. In order to ensure that ONGC continues to remainfinancially viable, ONGC has agreed to maintain its cutrent ratio at 1.2 times or higher, its debt semiceratio at 1.5 times or higher and its long term debt to equity ratio at not more than 1.5. In addition to thetechnical risks associated with oil and gas production, there are, however, a number of factors whichcould easily affect ONGC's financial position and its capability to implement its investment program.

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First, with the exception of the loans from multilateral donors onlent by the Government, ONGC carriesthe foreign exchange risk on most of its long term debt. Its debt profile is rather uneven, and debt serviceis projected to double in Rupee terms by 1993 from its 1991 level and to triple by 1994. The Rupee hasdepreciated by an average of about 12% against foreign currencies from March to November 1990. Anaccelerated devaluation or an increase in local inflation in excess of the rates projected would weakenONGC'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 caseof ONGC, this relatively high level of self-financing is crucial as a cushion against devaluation, inflationand for maintaining its sound credit rating. It is estimnated that, during the period 1991-1995, ONGCwould need about Rs 203 billion (US$ 9.4 billion) in foreign exchange, about US$ 4.9 billion (52%) to coverthe foreign exchange cost of its capital expenditure program and US$4 billion equivalent (43%) to coverdebt service, the balance (US$ 0.5 billion) being for operating costs. Of this amount about US$110 millionhas been already arranged through previous loans and about US$400 million from recent bond issues inGermany and Japan. An estimated US$2 billion is expected to be arranged in the context of this project.ONGC plans to raise directly an additional US$3.7 billion (equivalent) from external sources, primarilyfrom export credit agencies and suppliers. The balance of about US$3.2 billion would need to be providedby the Government. Given India's need to sustain investments in oil and gas exploration, it is expectedthat the Governm ent will give ONGC priority in its allocation of free foreign exchange. There is consider-able risk that ONGC and the government will be unable to mobilize all of the projected foreign exchangerequirements. If this should happen, ONCC would most likely delay investments in the Bombay offshoreregion, particularly in Neelam and Gandhar, and India's oil production would be substantially lower thancurrently projected.

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

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

Funding requirementsTotal capital expenditures 31.5 37.8 57,5 52.2 42.9 221.9 63Total debt service 10.8 10.4 18.9 287 29.1 979 28Corporate taxes 3,0 4.2 4.9 5.9 6.7 24.7 7Increase 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 68Borrowings

Foreign currency loans onlent by GO! 1.0 1.3 6.7 7.3 5.1 21.4 5Export credits andother 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 32Total 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 42.7Used for 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 Bank estniate

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3.25 ONGC's external resource mobilization during the 1991-95 period will have to be carriedout 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 externalposition, Moody's revised India's (and ONGC's) credit rating from A2 to BAAL. Other credit ratingagencies soon followed suit. By end-May 1991, S&P's implied rating of India's long-term debt was furtherreduccd 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 developmentassistance, 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 limnited way, can still offer substantialamounts of tied long term credit.

3.26 Apart from the Bank's direct involvement in motilizing the resources for ONGC's invest-ment program, the proposed project focuses on improving ONGCs overall project implermentationcapabilities, including strengthening of relationships with export credit agencies and other internationalfinancial institutions. The financial covenants are designed to ensure that ONGCs overall financialviability will be maintained. The growing complexity of ONGCs overall future resource mobilizationrequirements (over and above the proposed project) as well as the need to continue its efforts to optimizeits liability management, dictate that ONGC strengthen its capacities in this area. To that end, ONGC hasagreed that it will retain a financial advisor who will develrp the necessary strategic resource mobiliza-tion and asset and liability management plans for ONGC and assist in their implementation, includingthe 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 indus-trialized areas. Close to 75% of total gas reserves are concentrated in the Bombay offshore area. Aboutone-third of these reserves consist of associated gas. Unlike free gas, whose production can be controlledquite easily, the supply of associated gas depends on such factors as the rate of oil production, the geologi-cal characteristics of the reservoir and the age of the oil field. Most gas consumers prefer a stable andassured supply. When associated gas cannot be reinjected, oil companies tend to flare it, unless they areable to identify a market that Is willing to take whatever quantities of gas become available or even outfluctuating 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 itproduced 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 thenecessary investments for bringing the additional gas supplies ashore. The steep increase in gas suppliesis primarily the result of a drop in reservoir pressure, which was caused by delays in the implementationof 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 wouldincrease 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 inthe south sector of the Bombay High oil field through infill drilling. This will require drilling of 78 produc-tion and water injection wells. In addition to the production and water injection wells, to be drilledthrough eight well platforms, the program will require additional process platforms with intra-field andtrunk gas pipelines. ONGC estinmates that this will yield an additional 40 million tons of crude oil and 18billion cubic meters (Bem) of associated gas. The program includes also similar investments to develop the

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

4.04 PNoJEcr DESI(;N. The basic design of the gas production and recovery components of theproject 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 withONGC and the Gas Authority of India Ltd. The least-cost option which calls for taking all the gas that isbeing tlared in the Bombay High oilfield to t:le Bombay area market cannot be implemented due to thelimited capacity of the Uran gas terminal which cannot be increased beyond 16 MMCMD. Construction ofanother terninal at Usar to process oil and gas is being studied. However such a terminal is likely to facestiff opposition from environmental groups. In addition, both ONGC and GAIL expect that land acquisi-tion difficulties would extend the completion of the new terminal well beyond the date at which theproposed project would remain viable. Thus, ONGC decided to design a pipeline system that would takethe additional gas from the Bombay High oilfield to the other available landfall point, Hazira. FromHazira the gas will be distributed through the Hazira-Bijaipur-Jagdishpur (HBJ) pipeline to consumers inGujarat, Rajasthan, Uttar Pradhesh, Harayana and New Delhi. Annex 4.1 describes in more detail therationale 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 manage-ment of the Bombay High Reservoir, in order to arrest the decline of oil production andoptimize the ultimate recovery of hydrocarbons;

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

(c) to promote a greater involvement of the private sector in the oil and gas industry in India.

Project Description

4.06 The project is designed to transport up to 25.3 MMCMD of additional gas from the BombayHigh oil field to lJran and Hazira. These facilities will eliminate the flaring of gas in the Bombay High oilfield and help to meet the growing demand for natural gas in the Bombay area and along the HBJ pipelinein Northwest India. The project includes an additional trunk gas pipeline from South - Bassein to Haziraand the expansion of the terminal facilities at Hazira. These two components will increase the existingtransmission capacity from Bombay offshore fields, particularly Bombay High and South Bassein, from 32to 61 MMCMD of gas and will make it possible to segregate the transmission of sweet and sour gas. Toensure that gas consumers in the Bombay area receive the volume of gas committed to them, the projectalso includes a pipeline from the south sector of the Bombay High oil field to the Heera oil field where itconnects with the Heera - Uran trunkline. This additional pipeline will supplement gas deliveries to Uranby an additional 4 MMCMD. (Figures 1 and 2 in Annex 4.1 show the capacities of the various gas pipe-lines 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:

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(a) Construction of a process platform, SHG, in the southern sector of the Bombay High oil fieldwith a processing capacity of 100,000 barrels (bbl) of oil per day, 15 MMCMD of gas and140,000 bbl of water per day. The platform includes a 78 kilometer (km) pipeline with adiameter 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 oilfield, with a processing capacity of 60,000 bbl of oil per day, 6.8 MMCMD of gas and 90,000bbl of water per day. The platform includes a 30 km pipeline with a diameter of 18 inches tothe BHN - Uran gas trunk pipeline.

(c) Modifications of existing platforms.

(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 properreservoir management practices.

(i) Reservoir performance and management studies and training.

(j) Implementation of a package of measures to reduce the environmental risks and enhance thesafety 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 inRajasthan, Harayana, Uttar Pradesh and New Delhi. To offset a declire in the availability of associatedgas, the project will give ONGC the flexibility to bring additional free gas from the South Bassein gas fieldashore. This will provide consumers with an assured supply of gas, which will replace naphtha in fertil-izer production, middle distillates in the generation of peak-load power and coal in base-load powergeneration. 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 ofproject design and implementation, ONGC will be assisted by Engineers India Ltd. (EIL). EIL is the largestand most experienced engineering firmn in the oil and gas production and processing field in India. EIL, intum, has collaboration arrangements with experienced international engineering firms. ONGC requiresthat all its offshore structures and facilities, including pipelines, meet international standards and receivecertificates to that effect from recognized certification companies. These services will be provided byEngineers India Certification Agency.

4.10 The organizational arrangements for the implementation of the project are shown in Annex43. Because of the large size of the individual project components, ONGC is managing the implementa-tion of the project in terms of four separate subprojects: (a) facilities in the northern sector of the BombayHigh oilfield; (b) facilities in the southern sector of the field; (c) construction of the pipelines extendingfrom platform ICP (in the Bombay High oil field), to the Heera oil field and from the South - Bassein gas

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field to the Hazira gas terminal; and (d) the expansion of the Hazira gas terminal. Fach of thesesubprojects will be headed by a project manager with a separate task force and support services. Thesubproject 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 BusinessCenter (BRBC) who will have the overall responsibility for the implementation of the project in BRBC. Toensure maximum coordination in the implementation of project components, subprojects (a) - (d), in theBombay 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, ONGChas 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 Officein Bombay. With the implementation of the Bombav Offshore projects, phase I of the South BasseinDeveloprnent project (Ln.2241-IN), and the Western Gas Development project (Ln.2904-IN), the office hasdemonstrated its ability to effectively manage the implem'entation of large-scale offshore projects. Itsmanagement team has been exposed to all phases of offshore development. As a result, it has been able toput 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 willbe made of single responsibility turnkey contracts. The items that will be procured under the project havebeen grouped in 19 packages. With the exception of six packages for the expansion of the Hazira gasterminal and three packages for platform modifications, each package will be procured on the basis of asingle responsibility turnkey contract. Under these contracts the responsibility of the contractor extendsfrom detailed engineering to commissioning and final acceptance by ONGC. The single responsibilityapproach was chosen-as is the case with similar offshore and onshore work in India--because special-ized contractors with thc necessary experience and resources offer the greatest chance for the expeditiousexecution of contracts in spite of weather and construction risks. (The single responsibility approachwould have been impractical for the expansion of the Hazira gas terminal, tie platform modifications, theenvironmental component and the implementation of measures to improve the reservoir managemnent ofthe Bombay High oilfield, since implementation of these components requires close interaction with themanagement of existing facilities. ONGC would be in a better position than contractors to ensure thetimely implementation of these components).

4.13 Annex 4.4 shows the major stages of project implementation. The Bank's staff u.:stimates thatONGC will be able to complete the project in five years. The estimate of the Bank's staff takes into accountONGC's experience with the implementation of similar projects. Delays in Government approvals, inparticular environmental clearances, difficulties in obtaining land and procurement delays have been themain causes of slippages in project implementation in the pist. The complet.on time estimated by theBank'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 tihem acceptable. Because ofthe extreme sensitivity of the economic viability of the project to delays in project implementation, ONGChas agreed to arrangefor ar 'iew of its procurement andproject implementa'ion organization, discussthe results of this reviewv wit 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 theBank and found satisfactory. Also, bid packages for procuring the major project components have beencompleted and forwarded to the Bank. These documents are technically satisfactory.

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Environmental and Safety Issues

4.15 Offshore oil and gas operations are hazardous to the environment and the personnelinvolved. While the risks cannot be completely eliminated, they can be minimized . While the Governmenithas not yet adopted legislation that would govern safety concerns of oftshore operations, 0NGCd ealswith these issues effectively through compliance with international safety standards. With regard to theproposed project, the Bank's environmental and safety' specialistfound that the recovery of gas and thetransmission of gas to shore poses minimal environmental and safety risks. Construction of the platformsand 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 withoffshore safety. In 1985 ONGC adopted a Recommended Code of Practice for its offshore operations. ThisCode is based on best practices adopted elsewhere. By following this Code, ONGC complies with relevantinternational safety standards and maritime regulations. ONGC observes all of the safety standards foroffshore drilling and production platforms of the American Petroleum Institute and relevant rules of theAmerican Bui eau of Shipping (ABS), Britain's Lloyd's Register of Shipping and Norway's Det NorskeVeritas. Each platform is equipped with sufficient survival craft to accommodate all of the men at work atany time, In addition, India is a signatory to the Safety of Life At Sea (SOLAS) convention. T'he MercantileMarine 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. Aspart of this agreement, ONGC is required to obtain clearances for all of its projects from the Ministry ofEnvironment and Forests (MOEF). Before clearing any new projects, MOEF now requires the preparationof environmental impact assessments, environmental management plans and disaster maniagement plans.

4.18 ONGC's ARRANGEM1N-MS FOR ENVIRONMFNT AND SAiFEY. In order to be able to complv withenvironmental 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 require-ments. Ihe Group provides technical advice on environmental and safety issues to line managers. Theultimate responsibility for the safety of personnel and environmental protection within each region restswith the Board member responsible for that region.

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

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

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4.21 PNoprcr RELATFI) CONSIDFRATnONS. NEERI has prepared an Environmental Impact Assessmentreport (EIA) for the proposed project components in the northem and southern zones of the Bombay Highoilfield. The report has been reviewed by the Bank's staff, which agreed with its overall conclusions. Theseconclusions suggest that the environmental impact of the proposed project will be within acceptablelevels, if ONGC observes the suggested safeguards. The report points out that there may be, in fact, a netimprovement in the quality of the environment as a result of the substantial reduction of gas flaring. Keyenvironmental 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. Thetreatment 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 ofsampiing points. After treatment, the effluent is discharged at a depth of 40 to 50 meters,wihich ensures 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 ensurethat the treated sewage meets the standards stipulated by the US Coast Guard. Again, thesedischarges are monitored by the Central Pollution Control Board. Deck drainings are routedto the nroduced water treatment facilities.

(b) SOIID WASTES. The only significant source of solid wastes on a production platform arekitchen wastes. These should be either ground and disposed of in the sea, or transported tothe shore for disposal.

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

(d) DiSRUv0ON OF MARIINE LIFE.. Construction of the platforms will initially disrupt the seabedconditions in their vicinity. The same is true for the laying of the high pressure gastrunklines. However, these disruptions will be neither severe nor permanent. Marine growthon offshore structures is likely to result in a localized increase in the range and quantity ofmiarine life.

(e) DISAS`TER ENVIRONME.N`AL PRO.CrTION. The potential sources of major oil spills on a productionplatform are limited to large failures of the process equipnent or the oil/well fluid risers. Inthe event of a substantial process leak, the platform would be quickly shut down and thesource of the leak isolated. In the event of a riser failure, the leak may continue for sometime. ONGC is equipped to deal with oil spills of up to 400 tons of spilled oil per day. To thisend, ONGC has deployed five multi-purpose support vessels in the Arabian Sea. Two ofthese vessels carry containment booms and oil skimmers. Additional equipment for contain-ing oil spills is stored ashore. The Indian Coast Guard has the capacity to deal with oil spillsof up to 300 tons per day. However, ONGC and the Coast Guard would not be able to copewith a major oil spill. Following the recommendations of the appraisal mission, ONGCagreed to prepare contingency plans for such an incident, wliich would involve supportfrom international oil spill control centers. The necessary investments would be financedunder the proposed project.

(f) LEAKAGE FROM GAS PUIELINES. Since the gas transported in the pipelines to be constructed underthe project consists mainly of methane and does not have a significant concentration ofhydrogen sulfide, even a large release of gas into the atmosphere will not have a significant

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Table 4.1 Project Cost Estimate

Foreign Lxal TotJ Foreign L1al Total ForeignCost components Exdwnge

----- Rs million-- -- USS milion--- Percent

Process platform, NQP 4,516 1,084 5,600 209.0 50.2 259.2 81Compressors, St C 2,612 627 3,239 125.0 30.0 155.0 81Process platform, SHG 5,001 1,200 6,201 230.0 55.2 285.2 81Unepipe, SlGC-BPB 1,195 359 1,554 58.0 17.4 75.4 77Laying, coating and wrapping, SHC-BPB 229 1,544 1,872 15.7 6.1 21.8 72Platform modifications 1,362 327 1,69 63.3 15.2 78.5 81Linepipe, ICP-lleera 1,443 433 1,876 70.0 21.0 91.0 77Laying, coating and wrapping ICP-Hieera 2,067 496 2,563 97.0 23.3 120.3 81Lirepipe, BPB-iazira 4,941 1,4U; 6,424 220.0 66.0 286.0 77Laying, coating and wrapping, BPB-Hlazlra 2,899 696 3,595 129.3 31.0 160.3 81Expansion Hazira gas terminal 6,130 4,850 10,980 2753 217.8 493.1 56Reservoir management, services and equipment 1,355 1,239 2,593 67.4 61.7 129.1 52Engineering and project management 159 477 637 7.5 22.5 3Q0 25Studies and training 43 13 55 2.0 0.6 2.6 77Environmental component 304 139 444 14.7 9.8 24.5 60

Base cost (1991 prices) 34,357 14,966 49,323 1,54.2 627.7 2,211.9 72Physical contingendes 3,436 1,497 4,932 158.4 62.8 221.2 72Price contingencies 5,261 4,531 9,792 239.5 205.8 4453 54

Total project cost 43,054 20,993 64,047 1,982.1 8963 2,S78A. 69Interest during construction 4,341 2,165 6,506 204.1 101.8 305.9

Total Financing Required 47,395 23,159 70,554 2,186.2 998.1 3,184.3

Note: Baseline cost include customs duties of USS 374.4 million equivalentONGC charges interest during constructixn to operatons

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

Project Cost

4.22 The project is estimated to cost US$ 2878 million, including physical and price contingenciesas 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$ 450million represents 22.7% of the estimated foreig. exchange cost.

4.23 Estimated project costs are expressed in mid-1991 prices which have been derived fromrecent contracts and similar modification work. Physical contingencies of 10% of base costs have beenincludeJ. Local price contingencies have been estimated at 8.3% in 1991, 6.6% in 1992,6.5% in 1993 and1994 and 6.2% in 1995 and 1996. Foreign price contingencies have been estimated at 3.4% of the respectivebase costs pluS physical contingencies. Taxes and customs duties on imported goods and services havebeen estimated on the basis of average rates provided by ONGC.

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Table 4.2 FinancOnt PlanUSS million

Source of Finance local Foreign Total Percent

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

Total 996.1 2,186.2 3,1843 100.0

'GO's request for finarndrg is currently under 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 foreignexchange. ONGC will have no difficulty meeting the local cost component (31% ot . al cost) from inter-nally generated cash. Tre principal sources of foreign exchange for this project would include the WorldBank, the Asian Development Bank, the Export-Import-Bank of Japan as well as export credit agencies andsuppliers. However, since ONGC does not earn foreign exchange, it would have to cover the remainingforeign exchange costs through external borrowing or from the Government's free foreign exchangereserves. ONGC has requested the Bank's assistance in nobilizing the foreign exchange required underthe proposed project.

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

4.26 The Bank plays a crucial catalytic role in arranging the financing for this project, at a timewhen India's credit rating has come under pressure. Taking into account the importance of this role andthe amount of cofinancing the pr lject is likely to attract, a Bank loan of US$ 450 million equivalent isproposed. The loan, which will b madedirectly to ONGC on the Bank's standard termsfor India, will beguaranteed by the Government. The Government will charge a guarantee fee of 1% p.a. on the outstandingamount 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 procurementpackages and the Bank's interest in providing technical assistance, the following project components wereselected for Bank financing:

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(a) construction of the process platfornm, NQP;

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

(c) installation of platforn modifications;

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

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

(f) studies and training.

Table 4.3 Summary of Procurement ArrangementsUSS million

Procuemet MethodProject Components 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 4Bank 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 procuremnent procedures

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Procurement and Disbursements

4.28 Table 43, which sumnmarizes the procurement arrangements, shows that about US$ 1.2billion worth of goods and services will be procured in accordance with the Bank's guidelines for interna-tional competitive bidding. This is equivalent to about 41% of total project cost. The Bank's loan of USS450 million will finance about 38% of the cost of items procured under ICB. Procuremnent under limitedIntemational Competitive Bidding (LICB), financed by supplers' or export credits, is expected to amountto about US$957 million (for a description of LICB, see Annex 4.4). Consulting services will be obtained byONOC in line with the Bank's guidelines for the use of consultants. It is expected that the componentsfinanced under an untied cofinancing facility currently under study by the Export-Import Bank of Japanwould be procured through ICB in line with World Bank procurement guidelines. The procurement underthe proposed Asian Development Bank loan v Id be carried out under its guidelines.

4.29 The Bank's loan will provide financing for three major packages. Considering the smallnumber of packages and their large amounts, prior Bank review of all essential procurement documenta-tion will be required. In view of the fact that timely implementation is critical for the viability of theproject, ONGC has submitted the documentation for all packages to the Bank for review. For items to befinanced by the Bank, the Bank's standard domestic preference provisions will, at ONGC's option, applyfor the evaluation and comparison of bids.

4.30 Given the urgency to complete the proposed project as scheduled, ONGC has started theprocurement process for the process platform SHG, the compressors and the linepipe for the pipelineconnecting platforn SHG with platform BPB. In addition, ONGC has incurred substantial expenditures inthe context of implementing measures to improve the reservoir management of the Bombay High oilfield.Depending on the pace with which these measures are implemented and contracts can be finalized, up toUS$45 million of retroactive financing by the Bank may be required. ONGC has requested the Bank toreview all packages for which advance contracting might apply. The appraisal mission has made specificrecommendations to ONGC in order to bring the packages in line with the Bank's guidelines. ONGC nasrevised the packages accordingly.

4.31 The phasing of the projected disbursements of the Bank loan is shown in detail in Annex 4.8and summarized in Table 4.4:

Table 4.4 Phasing of DisbursementsUS$ million

Yelr I Yar 2 Year 3 Yar 4 Yegr 5FY92 FY93 FY94 FY95 FY96

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

Source: Buik stff projectons

432 Disbursement of the proposed Bank loan is based on the assumption that the loan willbecome effective by the end of the first quarter of FY92. It is expected that the loan will be completelydisbursed by December 31, 1995. While the disbursement period of five years is substantially shorter thanwould be indicated by the Bank's experience with similar oil and gas projects, the advanced state ofproject preparation and procurement makes this a realistic assessment. ONGC and the Govemment arefully aware that slippages in the implementation of the project would jeopardize the viability of theproject. ONGC has worked closely with the Bank to minimize the risk of implementation delays and thusdelays in the disbursement of the Bank's loan. Based on the projected schedule of expenditures a closingdatefer the Bank's loan of December 31, 1995 has been established.

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Table 4.5 Allocation of the Proposed Bank Loan

Category USS million Percentnge of Fxpnditures Financed

Process ' ilities and pipeline systems(a) equipment and materials 325.0 100% of foreign expenditures and IOOY of 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 expendituresUnallocated 20.0Total 450.0

4.33 To facilitate disbursements a Special Account would be established with an authorizedallocation of US$25 million, which is equivalent to about four months of average disbursemrents. Disburse-ments for consultant services and training under contracts valued at less than US$ 100,000 would be madeon the basis of Statements of Expenditure (SOE). Documentation of SOEs would be retained by ONGCand made available for review by Bank supervision missions. All other disbursemrents would be madeagainst 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 atincreasing oil output from the Bombay High oilfield. As an integral part of this project, the Gas FlaringReduction project will finance investments that will allow ONGC to recover, compress, transport, andprocess gas onshore. The gas recovery and compression facilities serve two purposes, to increase oiloutput 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 projectwill make it possible to take gas from other offshore oil and gas fields, - South Bassein, Heera andNeelam, and Panna and Mukta - to onshore markets.

5.02 The investments under the proposed project will eliminate the flaring of about 12 MMCMDof associated gas and contribute to an increase of oil production by about 3 -4 million tons a year in theBombay High oilfield. It is estimated that over the life of the project (1991 - 2010) an additional volume ofabout 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 liquidpetroleum products (mainly naphtha) in petrochemical and fertilizer industries, middle-distillates inpeak-load power generation, and coal and fuel oil in industrial uses and base-load power generation. Assuch, the project will reduce India's petroleum import requirements and the consequent drain on foreignexchange; it will also reduce the demand for coal in the western region, the need of additional rail trans-port capacity for coal and the environmental pollution associated with the use of coal. The project will alsomake it possible for ONGC to increase oil production in the Bombay High oilfield. Over the life of theproject these investments will add about 60 million tons of oil. Valued at US$20 per barrel, this wouldrepresent a financial value of about US$8.2 billion.

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Project Financial Analysis

5.03 Annex 5.1 contains the detailed assumptions and Annex 5.2 the calculations of the financialrate of return of the project. This calculation is based on the capital and operating cost estimates containedin the project cost tabic, including physical contingencies and local taxes and duties. The revenues fromsales of incremental gas are valued at Rs 1,500 per 1000 ml for the base case. All inputs have been valuedin constant 1991 terms.

5.04 Table 5.1 summarizes the financial internal rates of return for the base case and the resultsof the :nsitivity analyses.

Table 5.1 Financial Rate of Return: Sensitivity Analyses

Assumption InternaJ Rate of ReturnPercent

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

.)x)urce Bank staff estcmates

5.05 The sensitivity analyses show that the financial rate of return is quite sensitive to implernen-tation delavs suggesting the need for efficient project implementation (para.4.13).

Project Economiic Analysis

5.06 For the economic analysis, natural gas has been valued on the basis of the fuel which itreplaces. For the purposes of project evaluation, it has been conservatively assumed that all gas replacesfuel oil, the lowest valued replacement. Even where gas replaces coal in power generation or industrialuses, the economic cost of coal, either imported or supplied by indigenous coal iields is roughly at parwith the cost of imported fuel oil.

5.07 Annexes 5.3 and 5.4 show the detailod assumptions and calculations of the economic rate ofreturn of the project. The project cost estimates are in constant 1991 dollars, net of taxes and duties. Thestandard conversion factor of 0.8 has been applied to the cost of the local component of the project to br. ngit to the level of border prices in India. Physical contingencies of 10% of the base cost estimate have alsobeen included. CIF costs have been used in calculating the cost of the foreign exchange component.

5.08 The operating costs are based on ONGC's experience with similar installations and repre-sent overall about 2% of the estimated capital cost. This appears low for estimates in the offshore oilindustry but can be explained by the comparatively high proportion of pipeline investments for whichrepair and maintenance costs are not as high as for platform and other investments. ONGC estimates that1% of the capital cost is appropriate for pipeline repair and maintenance. For all other Investments thecorresponding percentage is 3% Annex 5.1 shows the detailcd calculation of the operating cost of theproject.

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5.09 The project benefits (natural gas) have been valued at equivalent fuel oil prices expressed inconstant 1991 terms. Fuel oil prices were projected on the basis of crude oil price projections issued by theBank's International Commodity Markets division. The detailed calculations of the prices for the fuel oilequivalent 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 ofwhich 29 billion would have to be flared without the project. Marketia. .of this incremental gas will becarried out through the terminials in Hazira (in the State of Gujarat) and LJran (in the Bombay area). Theflow of incremental gas through Hazira requires strengthening of the HBJ gas pipe line. The cost of theseadditional 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 mnodest 3.6 MMCMD of gas due to thecapacity limitations of the Uran terminal. In 1996 additional gas supplies are expected to increase to 24.6MMCMD. From then on, supplies will decline due to the gradual exhaustion of the Bombay Highoilfields. Additional finds are expected to make up for the decline in gas supplies from this major oilfieldshortfall.

5.11 When converting to natural gas there are further economic benefits in the formn of reducedstorage and handling costs, reduced maintenance costs as well as lower pollution. Additional benefitsresult from the increased thermal efficiency of natural gas relative to liquid fuels. Although the mnagnitudeof these savings varies from industry to industry, their total impact can be substantial. These benefits werenot included in the benefit-cost analysis.

5.12 As menrionrt.d above, the project contributes also to an increase of oil output from theBonibay Hiigh oilfield, which amounts to about 60 million tons of oil over the 19 year 'life-time' of theproject. Again, the value of this contribution of the project was not taken into account in the evaluation ofthe economic rate of retL rn.

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

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

Source Bank staff estimates

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Project Risks

5.15 The project faces three najor risks:

(i) delays in the implementation of the project which would quickly reduce its viability;

(ii) delays in the offtake of the additional gas that will be made available through the project;and

(iii) the possibility that ONGC will not be able to raise the foreign exchange required for theproject. This risk is aggravated by the fact that India's credit worthiness has suffered re-cently.

5.16 To minimize the risk of implementation delays, ONGC has agreed to award the construc-tion of najor items, such as platforms and submarine pipelines, on the basis of a series of contracts undersingle responsibility. In addition, ONGC has worked dosely with the Bank to streamline its organizationand management for the implementation of projects. The bidding documents for all major components ofthe project have been reviewed by the Bank. (para 4.14).

5.17 The risk of delays in the offtake of the gas will be significantly reduced through theGovernment's decision to set up a special monitoring committee in the Department of Petroleum andNatural Gas that will review quarterly the progress in implementing the proposed project as well as theprojects that will utilize the additional gas supplies. The quarterly reports of the monitoring committeewill be submitted to the Bank for review together with recommendations in case of any slippage in projectimplementation. The Bank will have an opportunity to review the implementation of these recommenda-tions.

5.18 To minimize the risk that difficulties in the financing of the foreign exchange componentsdelay the project, the Bank has engaged in extensive consultations with ADB and J-EXIM and has workedclosely with ONGC and the Government to ascertain the availability of finance from export credit agen-cies and suppliers. The Government's request for untied co-financing from J-EXIM is currently understudy by J-EXIM. In the unlikely event that J-EXIM is unable to participate in the financing of the project,the Bank will assist ONGC in mobilizing credit from other export credit agencies.

5.19 While technical risks are higher for offshore than for onshore projects, ONGC has accumu-lated considerable expertise in carrying out projects of this kind. In addition, all major project componentswill be carried out by experienced contractors on a turnkey basis. Thus, the proposed project poses nosignificant technical risks.

VI. AGREEMENTS AND RECOMMENDATION

6.01 AGREEMENS. The following agreements have been reached:

(a) With the Government that it will:

(i) implement a gas pricing policy which links domestic gas prices to intemational pricesof fuel oil and discuss, with the Bank, any revisions of this pricing policy (para. 2.31-2.32);

(ii) set up a body in the Department of Petroleum and Natural Gas to monitor, on aquarterly basis, the implementation of oil and gas field developments and revise gasproduction plans accordingly; this body would monitor, also on a quarterly basis, the

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progress in construction of plants and other facilities (pipelines, gas processngfacilities. etc.) required for the projected offtake of gas. The body will issue a quarterlyreport, listing any deviation from the plans of gas producers and potential consumersand containing recommendations for steps to be taken to ensure the efficient use ofprojected gas supplies. Copies of these reports would be submitted to the Bank forreview (para. 2.15);

(iii) submit annual reports to the Bank indicating changes in gas allocations and theirimputed or net-back values (para. 2.19).

(b) With the Oil and Natural Gas Commission that it will:

(i) review annually with the Bank its investment program and the implications of thisprogram on its financial position (para. 3.22);

(ii) naintain its current ratio at 1.2 tines or higher, its debt-service coverage ratio at 1.5times or higher, and its debt-to-equity ratio at no more than 1: 5 (para. 3.23);

(iii) have its annual accounts audited by an independent auditor acceptable to the Bankwithin nine months of the end of the fiscal year and provide the Bank with unauditedfinancial statements (incomne statements, funds flow statement and balance sheet)within six months of the end of the fiscal year (para. 3.11);

(iv) retain the services of a financial advisor for mobilizing foreign exchange resources(para. 3.26);

(v) establish Project Implementation Units for each of the four sub-projects, and appointan overall coordinator (OSD) for the purposes of the Bank project (para. 4.10);

(vi) carry out a review of its procurenent and project implementation organization,discuss the results of this review with the Bank and implement its recommendations(para. 4.13).

(vii) carry out a safety audit for its entire offshore operations, discuss the results with theBank and implement the recommendations of the audit (para. 4.20);

(viii) carry out a safety engineering study of existing platforms linked to facilities that willbe constructed under the project, discuss the results with the Bank and implement therecommendations of the study (para. 4.20);

6.02 The following are conditions of effectiveness of the proposed loan:(i) announcement inviting domestic and foreign oil companies to participate in a fourth

round of bidding for offshore and onshore parcels selected by GOI for exploration(para. 3.08);

(ii) obtaining of the environmental clearance for all components of the proposed project(para. 4.13); and

(iii) establishing of a body in the Department of Petroleum and Natural Gas which wouldmonitor the implementation of gas supply and utilization plans (para. 2.15).

6.03 RECOMMEW4DATION. On the basis of the project justification and the agreements reached duringnegotiations, the proposed project would be suitable for a loan of US$450 million equivalent to the Oil andNatural Gas Commission for a period of 20 years, including five years of grace, at the Bank's standardvariable interest rate. The loan would be guaranteed by the Govemment of India.

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INDIA Annex 1.1GAS FLARING REDUCTION PROJECT Page-T6m

Energy Balances, 1980-81 to 1988-89

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

Fiscal Gross Conmrion Net Othrr No"-Years eavilabzity tlosses awilability Agriculture Industry Trensport RtsidentiW ene"usew energy uJs

1980-81 92.623 23.859 68.764 1.625 36.861 17.443 5.637 1.901 5.2971981-82 101.411 26.567 74.844 1.624 40.607 17.787 6.258 2.042 8.5261982-83 109.023 28.552 80.471 1.861 44.607 18.758 6.820 2.127 6.6801983-84 114.944 31.261 83.68. 1.687 46.265 19.655 7.250 2.214 6.4121984-85 121.510 34.997 86.513 2.131 46.595 20.309 8.038 2.341 7.0991985-86 131.425 38.028 93.397 2.309 50.059 21.719 8.773 2.488 7.9691986-87 141.187 40.927 100.260 2,807 53.423 22.789 9.532 2.677 9.0321987-88 149.241 47.654 101.587 3.630 51.261 24.476 10.375 2.953 8.8921988-89 163.606 52.621 110.985 3.861 56.214 26.055 11.532 3,684 9.639

Source: Compled from energy baldnce

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INDIA Annex 2.1GAS FLARING REDUCTION PROJECT Page 1 ofT2

Gas Production Projections

1. GAS PRODUCrION. 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 processingplants. The gas caps overlying the oil cannot be drawn on until the oil has been exhausted, otherwise theamount of oil recovered will be diminished. In order to project India's gas production, it is necessary tomake certain assumptions regarding construction and implementation of development programs to becarried out by ONGC and GAIL. Since there are no facilities for storage of natural gas in India, apart fromthe 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 attheir maximurn efficient rate and that any associated gas produced in excess of local gas demand in theproducing regions will continue to be flared. A further corollary to the lack of gas storage is that produc-tion 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 bereduced to 400 cubic meters of gas for eacti cubic meter of oilproduced (v /v), that is a GOR of 400:1 v/v will be maintained atall wells.

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

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

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

- Free gas (which can be connected to the HBJ pipeline) will not beput 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 93MMCMD, even though actual producing capacity may initially exceed this level. Future discoveries ofgas are probable but, being unquantifiable, have not been taken into account. Future large discoveriesmay cause substantial changes in transport and marketing requirements, depending on their physicallocation. Table I summarizes the projected gas out put from oil and gas fields in the Western region andt;-e Bombay High oilficid. These projections are conservative and only production from known fields wastaken into consideration.

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INDIA Annex 2.1GAS FLARING REDUCTION PROJECT Page 2 of 2

Gas Production Projections

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

---- Aswciated Cas ----- Free as Yeaa Bombay Ileera Neelam Patina & Total South South Bombay Panna Mid Other Total Tota

High Mukta Associated assein 2Bassein' High SI South knobm Fra GasGas Tapti structures Gas Pr'd'n

1991 16.0 1.1 17.1 7.5 7.5 24.61992 16.0 1.5 17.5 9.7 9.7 27.21993 14.8 1.0 15.8 13.8 13.8 29.61994 19.3 0.7 0.7 20.7 15.3 15.3 36.01995 19.3 0.5 1.2 2.3 23.3 12.7 12.7 3601996 26.8 0.4 1.2 3.8 32.2 2S.0 3.8 28.8 61.01997 24.2 0.3 1.6 4.2 30.3 25.0 4.2 1.5 30.7 61.01998 21.2 0.3 1.9 3.9 27.3 25.0 2.4 3.0 3.3 33.7 61.01999 19.9 0.6 2.0 3.5 26.0 25.0 3.7 3.0 33 35.0 61.02(00 18.3 0.5 2.0 3.0 23.8 25.0 5.3 3.0 0.6 3.3 37.2 61.02001 16.9 0.5 1.7 2.4 21.5 25.0 7.3 3.0 0.9 3.3 39.5 61.02002 15.3 0.4 1.6 1.6 18.9 25.0 9.2 2.5 2.1 3.3 42.1 61.02003 13.9 0.3 1.2 1.2 16.6 25.0 11.5 22 2.4 3.3 44.4 61.02004 12.6 0.3 1.0 1.1 15.0 25.0 14.1 1.2 2.4 3.3 46.0 61.02005 11.3 0.3 0.9 1.1 13.6 25.0 16.7 2.4 3.3 47.4 61.02006 9.5 0.3 0.9 0.9 11.6 25.0 16.7 2.4 3.3 2.0 49.4 61.02007 8.7 0.3 0.7 0.8 10.5 25.0 15.8 2.4 33 4.0 50.5 61.02008 7.9 0.2 0.7 0.7 9.5 25.0 15.8 2.4 33 5.0 51.5 61.02009 7.6 0.2 0.5 0.7 9.0 25.0 16.5 2.2 3.3 5.0 52.0 61.02010 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 MMCMDI Additional production capaaty from South Bassein requir&e to meet delivery commitments to gas consumersSource: ONGC and Y ssion estimates

-48 -

INDIA Annex 2.2GAS FLARING REDUCTION PROJECT Pag 1 o(f 1

Gas Flaring in Major Gas Producing Regions

Million cubic merTs per day

1 .0 (F) 4.5~~~~~~~~~~~~~~~Rrd a (U-)

2.5UU a (_

28~~ 0 El j omba

| r _ ~~~~~~~~.1 _ U)1

§ Guj~~~~~~ad ra s Z ssm

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

| _00 Calutt 00 00_00

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INDIA Annex 2.3GAS FLARING REDUCTION PROJECT riageT-F4

Projected Gas Utilization

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

Sector Consu4mer 1991 1992 2993 1994 1995

Fertilizer: Rashtriya Chem. & Fert., Trombay 1.80 1.80 1.80 1.80 i0Rashtriya Chem. & Fert., Thal 3.00 3.00 3.00 3.00 3.00Deepak 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 1.50Maharashtra SEB Uran 3.00 3.00 3.00 3.00 3.00Maharashtra 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 Gas Cracker 0.60 0.60 0.60 0.60 0.60Bharat Petr./llindustan Pctr. Ltd. 0.05 0.05 0.05 0.05 0.05Bharat Electronic Ltd. 0.03 0.03 0 03 0.03 0.03ONGC: C2/C3 1.15 1.15 1.15 1.15 1.15ONGC: LPG 1.00 1.00 1.00 1.00 1.00Heavy Water Project 0.15 0.15 0.15 0.15 0.15Grasim 0.75 0.75 0.75 0.75lindustan Copper Ltd. 0.01 0.01 0.01Kalyanm Steel 0.75 0.75Nippon Denro 1.00 1.00GAIL: LPC 0.45 0.45Hindustan Organic Co. 0.15Medtist 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 19.00Uran terminal capacitv 12.50 12.50 12.50 16.00 16.00Expected offtake 12.50 12.50 12.50 1600 16.00

Source: GAIT. and mission estimates

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INDIA Annex 23GAS FLARING REDUCTION PROJECT Pa2gei2 of4

Projected Gas Utilization

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

Existing New Cas Govt. Gas FinancingConsumer Alloc- Approved Contract Arranged

Sector Consumer Commitments 'ations Proects Signed Remrks

Fertilizer: Rashtriya Chem. & Fert., Trombay 1.80 YesRashtriya Chem, & Fort., Thai 3.00 YesDeepak Fort. & Petro-chem. Ltd. 0.60 Yes

Power: Tata Electric Company 1.50 YesMaharashtra SEB Uran 3.00 YesMaharashtra SEB Uran extension 1.50 Yes No Yes Planned conumnissioning 1992

Industry: Maharashtra Gas Cracker 0.60 YesBharat Petr./Hindustan Petr. Ltd. 0.05 YesBharat Electronic Ltd. 0.03 YesONGC: C2/C3 1.15 NoONGC: LPG 1.00 NoI leavy Water Project 0.15 Yes(rasim 0.75 Yes No YesI lindustan Copper Ltd. 0.01 No No NoKalvani Steel 0.75 Yes No Yes Private. Land acquired.Nippon Denro 1.00 Yes No Yes Private. Land acquired.GAIL: LPG 0.45 No No NoI lindustan Organic Co 0.15 No No NoModtist 0.01 No No No

Other: Bombav City I)istribution 1.50 No No No

lotal 12.88 6.12

Notes " otai off take is generalIy i rmtne with total conmnitments, because of fall back demandSource- GAIL.

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INDIA Annex 23GAS 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 cubic metm pr7 day

Sector Consumer 1991 1992 1993 1994 1995

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

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

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

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

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

Source, GAIL and mission estizmates

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INDIA Annex 2.3GAS FL1 ¶ING REDUCTION PROJECT 15go

Projected Gas Utilization

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

Exist Gas New Govt GasCon nts Oiftake Gas Appr. Contract Fm.

Sector Cnusumer 1990/91 Alloc's PrFj. Signed Arr'd Remarks

Fertilizer: Krishak Bharati Coop. 3.30 3.30National Fort Ltd., Bijaipur, MP 1.80 1.55Indian Farmers and Fert., Aonla,UP 1.80 1.55Indo Gulf, Jagdishpur, UP 1.80 1.55Chambal Fert, Gadepan-Rajasthan 1.80 Yes Yes Yes Constr. startedTata, Barbala, UP 1.80 Yes Yes Yes Constr. startedBindal Agro, Shajahanpur, UP 1.80 Yes Yes Yes Constr. startedIndian Farmers and Fert., Aonla,UP 1.80 No No No Appr. pend. 8th PlanNational 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 NoNTPC, Kawas 2.25 Yes No WB Sched. comm. 92 to 94NTI'C, Anta, Rajasthan 0.25 Yes No No Sched. comm. 94 to 95NTP'C, Faridabad, liarvana 2.00 Yes No No Sched. comm. 94 to95DESU, Bawana 2.00 No No No

Industry F:ssar, Cujarat 0 50 0 50L1PG, C)NIC I iazira 0.30 0.30L.1'(, Bijaipur, MP. GAIL 1.0(RclKance Ltd, P'etrochemicals 0.50 Yes No NoI lca, N Water Project 0.10 Yes Yac No(2/C3 (GAIL, Auraiya) 2.40 No No NoC2/C3, GAIL, I lazira) 2.10 No No NoIndiani (.Il Corp, Koyali. Gularat 110 Yes No Yes Under implementationE Nsar EXport 0.90 No No NolIquLid Fuel Replacemen: 0.90 No No NoLP(; GAIL I iazira extension 0.30 No No NoL PG (location to be decded) 1.00 No No NoU 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 NoTotal 1810 12 05 27s90

Notes Comrnilmr nti are considerablv in excess of terminal capacity However, estimated offtake ir taken only at about 75% of commitments.Moreover. additi,na 'upphies fr(m the Guiarat onshore fields are possibleSource GAIl

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INDIA Annex 2.4GAS FLARING REDUCTION PROJECT Page 1 of 1

Gas Prices

Prices of Gas and Altemative Fuels in Majo1r Sectors, 1991

Price aR per 1OOm3)4000-

Not-back values Rs 2200 - 30003000 Net-back values Rs 2500 - 2700

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

2000 ~~~Gas price along HBJ (Rs 2350) e Nt-akvls2000- Net-back values

IRs 1300 - 1 500- --- -------------- ~~~~- -- - - ---- - -- - -

Gas price at landfall points (Rs 1500) OR10001

Petro-dhemials Power Fertilizer IndustryNaphtha Coal Subsidized Naphtha Fuel-ilRs3632 Rs2446 Rs2242 Rsl713

0-18.70 38.85 24.10 10.91

Gas commitments (MMCMD)

Note. AU prici in this figue we expraed in terms of their thermal equivalents of 1000m3 of gas

1. The figure above provides a comparison of the value of natural gas in major end-uses, themanufacture of petrochemicals and fertilizer, power generation and industrial uses. The 'replacementvalue' of natural gas is given by the price of the fuel which gas could potentially replace 'at the margin', --naphtha in the petrochemical industry, coal in power generation, (subsidized) naphtha in the fertilizerindustry and fuel oil industrial uses of gas. In addition to these replacement values for natural gas, thefigure above shows ranges of net-back values of natural gas and the prices of gas at landfall points as wellas along the HBJ gas pipeline. The netback values provide an indication of the value of gas in a particularindustry. It has to be kept in mind that these net-back values are plant and therefore location-specific; atbest, they serve as an indicator of the maximum price users would be willing to pay for gas.

2. The conclusion that can be safely drawn from the information presented in the figure aboveis that gas sold at landfall prices provides an attractive alternative fuel in all major end-uses. Along theHBJ pipeline, some users may find gas at the currently proposed prices unattractive, and may be unwill-ing to switch to gas. However, since the prices of alternative fuels (naphtha, coal, fuel oil) will most likelychange as will transport charges for these fuels, the demand for gas along the HBJ will depend on relativefuel prices at specific locations.

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INDIA Annex 3.1GAS FLARING REDUCTION PROJECT Pag I of I

Oranization Chart of the Oil and Natural Gas Commission

Ioea Mora ExcuL C hmittZ (CmorteMampgaeot)

ISertary to Commlulson :

Excudtive Diector(Seunity & Vglne

_ Member Member Mem lerMember Ma*Mer(Dr/IIiing) (Operation) 1k(Tednkl) (Penonnd) (Fmance | (Part-lme)

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i ' I l l ~~~~~~ID Cena aRdt 01 DL; D lorDiEMag ~~mana Eag Oan (Ntlwm RBC CSmAthm

, l 1, W v) | 1, ~~~OAarbs) IT |R IC|

Grap GCmup

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

d d | l |G~~~~~~~~~~~~~COp l G.nfa

IMa 1nIaaim)

I IIIEC I l l ~~~~~~~iflnl (Adn l

|GupGmt |

R| P Gp.)

RaamamGp.)

aAttutfa of

DmbpwerA-t~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~

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INDIA Annex 3.2GAS FLARING REDUCTION PROJECT r

Summary of ONGC's Accounting Practices

In fiscal year 1986, ONGC changed its accounting practices to bring them into line withinternational oil industry practice. The results for 1981 to 1985 have not been restated and are thereforenot fully comparable with the accounts for the later years. The Comptroller and Auditor General of Indiaobserved that until 1989, the "Successful Efforts Method of Accounting" had not always been correctlyapplied. These problems have now been corrected.

2. Until 1985 it 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 inwhich they were incurred. All exploratory drilling costs were initially capitalized andyear's expenditure was amortized equally over 15 years. In case of unsuccessful efforts, thelicense was surrendered and net amortized costs were expensed against income in threeequal annual installments. In case an area was declared successful, amortized costs weretransferred to producing properties.

ouPRoDucNC PRoPERnEs. The oil and gas producing properties included unamortized explor-atory drilling costs and costs incurred on development of the producing field. Theseproperties were created when regular production was started from the field regardless ofthe level of productionand were depreciated equally over ten years. Subsequent develop-ment drilling costs were depreciated in a manner where total costs were charged againstincome during the remaining ten year period. Development costs after the tenth year werecharged against income of the year.

3. Following the practices of most international oil companies, ONGC changed its accountingpractices 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 assuccessful 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 amorti-zation, depletion and depreciation already charged until previous years (without disturbingthe 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 ofApril 1, 1985 and 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 againstincome as incurred.

- DEPRECATION. Plant and equipment and other capital items are stated at cost and thendepreciated on diminishing balance method at the rates set forth in the Income Tax

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INDIA Annex 3.2GAS FLARING REDUCTION PROJECT Page 2 of 2

Summary of ONGC's Accounting Practices

Act, 1961, except the Research and Development Equipment which is depreciated onstraight 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 inpipeline are not taken note of as it is not possible to measure such stocks. Inventoriesof stores and spares and assets for replacement are stated at cost.FoREICN CURRECY TRANSACnONS. All expenditure incurred and liabilities undertakenin the form of loans drawn and/or other liabilities are provided at the exchange rateprevailing on the date of the transaction. These liabilities are recogni7ed, on the lastday of the accounting year, at the mean of the buying and selling rate of exchangeprevailing on that date. The difference arising out of such adjustments and alsochanges in the value of cash balance and other adjustable advances held abroad areadjusted to the relevant head of account wherever feasible, otherwise to the Profit andLoss Account.LONG TERM DERTS. The practice of considering the portion of the Long Term Debtsmaturing for payment in the ensuing year as a current liability was discontinued afterMarch 31, 1988.CoRPoRATE TAXFS. Taxes are levied on income determined after providing for amorti-zation and depletion in accordance with the provision in the Agreement with theGovernment under Section 42 of the Income Tax Act, 1961. For Corporate Taxpurposes, total depreciation charged, whether allocable to production and transporta-tion activities or to exploration and development activity, is considered as an item ofexpendituire against year's income.

Note: All years refer to Indian fiscal years starting on April I

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INDIA Annex 3.3GAS FLARING REDUCTION PROJECT Pa-ge T6T

ONGC Sales and Revenues, 1981 to 1990

Fisci year ending March 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 20.9Crude 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 7,438Natural 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 8,610LPG (mill. tons) 0 73 161 196 242 320 450 502 680 718NGL (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 63,169Natural gas 502 807 1,363 1,842 3,077 4,162 7,263 9,659 11,899 14,318LPG 0 127 295 367 442 587 84 508 1,944 1,592Other 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 revenuesCrude oil (Rs per ton) 389 946 1,225 1,393 1,392 1,454 1,737 1,826 1,882 2,127Natural gas (Rs per 1O0O ml) 517 656 734 829 1,103 1,258 1,440 1,645 1,717 1,663LPG (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.

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

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

RevenuesOil rvewnues 3,466 11,764 21,537 31,422 35,525 38,180 48,037 49,492 53,706 P4,169Naturel reg enues 5W 807 1363 1,842 3,077 4,162 7,263 9,659 11,899 14,318Other revenues 550 915 956 1,464 1,747 1,537 974 1,922 4,119 3,840Total revenue 4,518 13,485 3,856 34,728 40,350 43,879 56,274 61,073 69,724 81,327Royalties, 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

ExpensesCash operatlng ctob 732 1,224 1,630 1,985 2,969 3,342 3,929 4,614 5,012 6,481Other expenditures 1 247 180 621 1,224 987 1,688 875 4,8& 2,428Depreciation 984 1,282 2,822 2,592 4,289 2,178 2,103 3,342 2,946 3,027Depletion 430 683 1,151 2,160 2,617 1,466 1,923 2,064 2,466 4,50Amortization 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 21,205Less: Interest2 476 862 873 884 1,338 1,580 1,214 746 769 997Corporate Taxes 1,975 4,900 8,020 7,450 5,960 6,205 5,347 4,930 3,970Net Operating Income 466 3,756 6,929 8,057 8,824 12,868 14,845 15,076 16,015 16,238Dividends 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:

Normnal Operating 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 52Return on total equity 16 49 48 37 31 32 27 21 19 16Return on net average flxed assets 36 39 31 28 31 28 23 21 19Return on capital employed 9 25 28 24 21 22 20 17 16 14Dividend as percent of total equity 3 2 2 1 1 1 1 1 1 1

Notes:"indude year end revaluationvnet interet payment

.59 -

INDIA Annex 35GAS FLARING REDUCTION PROJECT Page lofl

ONGC Sources and Applications of Funds, 1981 to 1990

Rs millim

FiwMlyr migMn* 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 25,076Additions (deduwo1ns)Depreciation 984 1,282 2,822 2,592 4,289 2,175 2,108 3,342 2,946 3,027Depletion 430 683 1,151 2,160 2,60 1,466 1,923 2,064 2,466 4,503Amortization 572 721 992 1,360 1,887 2,717 2,594 4,412 4,614 6,48Others (nct) 14 129 81 205 (39) 189 (702) 50 129 375Year 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

BorrowingsDomesticborrowings 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 1,350lnt.cap. narket borrowings by ONGC 1,025 801 4,027 980 1,663 2,809 13,733 7,865 8,401 16,117Suppliers/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 17,467Governnment funds 55

Total Sources 5,499 13,493 25,734 27,873 32,999 32,505 45,486 43,196 49,462 59,344

ApplicationsAcquisition of Capital Assets 2,729 5,729 9,169 9,461 11,251 11,555 11,560 10,306 12394 17,889Exploration & Devt. Expenditure 1,530 2,376 4,420 5,524 5,466 5,808 7,398 8,652 10,897 13,106

Total capital expenditure 4,259 8,105 13,589 14,985 16,717 17,363 18,958 18,958 23,291 30,995

Long-term investment and PSU loans 3,895 1,003 128 298 1,445 9,180 13,088 5,589Debt service: principal repayments 475 417 1,112 1,269 1,894 2,496 11,050 5,356 2,888 8,806Interest 485 888 1,179 1,659 1,993 2,242 2,294 2,500 3,538 4,868Subtotal debt service 960 1,305 2,291 2,928 3,887 4,738 13,344 7,856 6,426 13,674Corporate tax 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 549Increase (decrease) in working capital 68 1,884 752 617 4,457 3,758 5,201 1,428 1,184 4,650lncrease (decrease) in intangible assets 8 10 33 11 34 45 (27) 24 29 (83)Total applications 5,499 13,493 25.734 27,873 32,999 32,505 45,486 43,196 49,462 59,344

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

Notec Variadon in working capital may not appear consistent with balance sheets, due to accounting tteatment of fixed aset addition, the curretpatlmn of long-tam debts and of gatulty, which is not considered by ONGC as a curnt liabilty.

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INDIA Annex 3.6GAS 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 2,065Debtos (net of provisions) 563 2p26 3,216 2,506 4.046 3,979 5,041 62.62 8,338 16,954Inventories 2,2W5 3,037 4,00 466 5,910 8,8 10,811 11,104 11,640 12,166Other 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 anstsProperty, plant and equipment 4,561 4,988 8,780 12,181 13,239 20,894 24,450 22,966 21.6 24,424Producng property 1,I67 2,476 3,66 4,C13 533 9,851 15,149 21,711 30,.95 39,834Capital works in progres 232 719 1,.51 2.650 3,729 1,342 2,982 3,154 2,512 4,555Othr fixed aeebs 1,983 5,028 5,129 6,770 9,673 9,114 7,519 7,949 11,491 12,040Unalloated 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-term investments 250 250 4,145 4,168 4,296 4,921 6,693 15,199 26,447 30,156Loans to :.SUs 980 980 653 327 1,000 2,840 4,720Intangible assets 248 395 424 234 1,149 352 405 666 695 3,860

Total ssets 14,902 25,030 45,922 S4,055 84,963 101,425 116,210 134,508 162,303 199,554

Liabilities and equityCurrent liabilities:

Current portion of long-term debt' 417 712 1,274 1,9% 2,149 3,005 2,353 2,681Provisionfort x andgrstulty 896 2,305 7,203 15,283 22,783 21,768 20,064 18,097 17,147 21,146Other current liabilities 2,180 3,7Q0 6,483 6,040 6,796 9,211 6,904 7,487 8,829 15,156

Subtotal current 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 equityCapital 3,428 3,428 3,428 3,428 3,428 3,428 3,428 3,428 3,428 3,428Reserves & surplus 2,468 6,021 12,677 20,425 28,933 41,615 56,105 70,77h 86,328 102,096

Subtotal total equity 5,896 9,449 16,105 23,853 32,361 45,043 59,533 74,206 89,756 105,524Total liabilities and equity 14,902 25,030 45,922 64,055 84,963 101,425 116,210 134,08 i62,303 199,554

Current ratio 1.2 1.3 1.2 1.1 1.2 1.3 1.5 1.6 1.8 1.7Long-term debt-equity ratio 0.9 0.9 0.9 0.7 0.6 0.5 0.5 0.4 0.5 0.5Accounts receivable (days) 45 55 49 26 37 33 33 38 44 76

Note: IPractice of showing curent portion of long Wm debts a acwrrnt iabtlids has bon dlacotntinued sice 1969.

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INDIA Annex 3.7GAS FLARING REDUCTION PROJECT Page 1 of 3

Performance Parameten

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

Fisdyear ending March 31 Onshore Onshore Offsho Offshore Avne AwFr Rieentiwn PriceCurre"t Constant CurCnt Cnstnt Curnt Contat Current ContsntPries Prices Prics pris Pric prim Prices Prim

1962 326 326 759 759 507 5091983 367 350 545 520 474 4521984 409 362 553 490 50 4461985 781 650 614 511 658 541986 595 474 482 384 508 405 1,400 1,1161987 777 586 384 289 444 335 1,400 1,0551988 1,249 870 423 295 547 381 1,400 9751989 2,570 1,666 583 378 886 574 1,400 9071990 2,124 1,307 668 411 859 529 1,400 862

Notes: Constant prices haw been expresd in 191I/8 tmsSource: ONGC

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

Fisl yer ending March 31 Onshore Onshore Offshore Offsho Avrge Average Retention PriceCurret Constant Currn Constant Current Cout t Cuet Constant'Prices Prices Prices Prims Prices Prics Prices Prics

1982 201 201 326 326 2Th 273 968 9681983 264 252 341 325 317 302 968 9231984 392 347 294 260 319 283 968 8571985 458 381 43O 358 436 363 968 8061986 356 284 269 215 291 232 968 7721987 401 302 275 207 307 231 968 7291988 403 281 281 196 315 219 968 6741989 553 358 321 208 385 250 968 6271990 608 374 386 238 453 279 968 596

Not: 'Prices a-e expresd in constant 1981/C2 termsSoume: ONCC

-62 -

INDIA Annex 3.7GAS 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 anrd gas in bWIlim bic mtew

CaklA r yars 1985 1986 1987 1988 19f Totals027 Gas OCi GCs V GM 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 450.96 408.77Revision of upgrading/resting 60.25 7.48 25.09 12.92 67.68 16.24 16617 28.50 6.91 9.45 176.10 74.59Coanges 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 27.78Extensions and discoveries 19.66 14.51 29.34 14.15 20.06 27.42 89.70 49.35 49.79 37.56 20657 142.99Production 27,26 6.33 28.27 10.30 28.60 9.15 28.55 11.84 31.13 14.59 143.81 52.21End of the year 505.03 424.57 52525 465.41 563.18 50.27 665.55 567.28 695.92 601.92 695.92 601.92Memo 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 rneserves ae the etimated quantiti of l and g which geooil and gi tng data den -trated wlthr reonable cwtanty to berecverable in future years from known resavois under edsting economic and oprating nditione

Average cost of drnlling, 1981 to 1Q90 %

Cnshm Offsore Exlrptoy Development AverageFiscal ywr ending March 31 Cost per meter Cost per meter Cost pr mter Cost per meter Cost per 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 9141982 2,975 333 15,896 1,780 7,153 801 7,718 864 7,452 8351983 3,703 385 16,645 1,729 8,563 891 P205 852 8W346 86719B4 5,593 542 16,841 1,633 12763 1,238 8,418 816 10,132 9831985 5,216 ' 9 17,348 1,45 14,402 1,212 7,777 654 10,655 8961986 6,505 532 16,496 1,348 12,957 1,059 6,220 508 9,497 7761987 5,925 463 17,496 1,368 13,519 1,057 5,07G 396 9,112 7131988 6,513 502 17,050 1,315 14,389 1,110 5,524 426 9,513 7341989 6,720 415 16,027 989 16,027 989 6,720 415 9,790 6041990 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 productiontesting.

Source: ONGC

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INDIA Annex 3.8GAS FLARING REDUCTION PROJECT Page 1 of T

ONGC's Investment Program, 1991 to 1995

Milio Rupes (at 1991 Prim)

Fscl yar ending March 31 1991 1992 1993 1994 1995 1991-95

Ongoing PjectAccelerated Production Plan Bombay High 74 32 106Heera Phase 11 Oi development 2,319 100 931 3,350Gas lift Bombay High 1,278 497 178 1,953BH 22 Ollfield development (near Bombay High) 95 60 84 240BH 25 Oilfield m.velopment (near Bombay High) 119 60 26 205Uran Gas Fractioiing Plant (C-C3 extraction) 335 65 400Hazira Gas Sweetening Plant If 402 246 176 823Cambay Basin Petroleum Project 285 190 ; '9 653Additional oil recovery Bombay High South 182 28 21UAdditional oil recovery Bombay Hfigh North 230 136 32 3962 Jack-up rigs (offshore dril'ing) 135 135Regional computers 61 61Assam area captive power plant 33 13 45Land development driling rigs 33 12 45South Bassein- Phase 11 residual drilling 126 126Gandhar I Development (Cambay Basin) 456 198 168 822B131 Devel<okment (Neelam Field) Bombay offshore 77 30 39 146B57 DeveloF ment (Mukta Field) Bombay offshore 77 30 22 129South Bassein I 8 8Total orgoir g projects 6,263 1,757 1,835 9,855

Development SchemesPanna field (Bombay offshore) 408 1,250 2,472 2,749 2,000 8,880Neelam field (Bombay offshore) 325 2,500 5,710 3,100 3,296 14,930Mukta Field (Bombay offshore) 80 100 3,745 4,295 4,000 12,220L 11 (oil only) 118 2,822 648 3,588Llil (oil only) 2,495 3,898 1,502 1,001 8,896Gas Flaring Reduction Project 1,278 15,492 17,843 12,531 47,145Candhar If Development 303 400 2,275 2,144 80 5,201Ravva Development 464 265 289 428 1,736 3,181Crude Desaiter(Cambay) 20 iS0 240 70 480Kerosene Recovery Unit (Hazlra) 6 50 200 274 530Natural gas liquids refoener 0 500 733 733 733 2,700Cambay onshore oil pIpeline 4 4 42 50BPB Hazira Pipeline 3,240 3,240 6,480Usar oi terminal 10 10 20ICP- Heera Pipeline 5 5 10Total 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 16,000Grand 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 5,854Exploration Drilling 10,704 10,104 5,320 4,040 4,700 34,868Development Drilling 5,314 6,513 4,000 4,350 2,510 22,687

Subtotal Exploration and Development 17,447 1,922 10,360 9,420 8,260 63,409Resarch and Development 600 934 740 710 520 3,504

Grnd Total 31,494 35,860 52,291 45,419 35,S15 200,578

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INDIA Annex 3.9GAS FLARING REDUCTION PROJECT g'eToF

ONGC Revenue Projections, 1990 to 1995

FiywretdingM arch31 1990 1991 1992 1993 1994 1995

Summary of net volumes soldCrude oil, offshore (mill. tons) 20.9 20.3 20.4 19.7 24.5 29.2Crude oil, onshore (mill. tons) 8.8 9.1 10.7 12.0 13.5 14.3

Subtotal crude 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 17,187Natural go, onshore (MMCM) 1,172 1,625 2,070 2,810 3,319 3,319Subtotal naturl gas 8,610 9,875 11,170 15,527 19,211 20,506

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

Revenues (Rs million)Crude oil 63,169 62080 65,735 67,088 80,357 92,000Natural gas 14,318 16,519 18,654 25,939 32115 34,310LPG 1,592 1,544 1,650 1,748 1,829 1,829NCL 1,116 1,338 1,446 1,446 1,446 1,446C-2, C-3 240 1,261 1,801 2,282 2,282Other revenues 1,132 2,nlo 2,096 1,535 1,745 1,939

Total revenues 81,327 83,730 90,842 99,557 119,774 133,806Average' priceCrudeoioff hore(Rsperton) 2,118 2,113 2,113 2,113 2,113 2,113Crudeoil onshore(Rsperton) 2,110 2,113 2,113 2,113 2,113 2,113Natural gas offshore (Rs per 1000 ml) 1,673 1,695 1,695 1,695 1,695 1,695Natural gas onshore (Rs per 1000 m3) 1,479 1,560 1,560 1,560 1,560 1,360LPG (Rs per tan) 2,213 2,129 2,129 2,129 2,129 2,129NGL (Rs per ton) 1,888 1,808 1,808 1,806 1,806 1,808C-2, C-3 (Rs per ton) 4,003 4,003 4,003 4,003 4,003

Note: Other revenues include: Pipeline revenues, NGL saes, receipt from contacts etc.

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

Rs mvillton

Fiscal yeat eiding March 31 1990 1991 1992 1993 19'4 199I

RevenuesOil revenues 63169 62080 65735 67088 80357 92000Natural gas revenues 14318 16519 18654 25939 32115 34310Other revenues 3840 5132 6453 6531 7302 7496Total revenues 81327 83730 90842 99557 119774 133806Royalties, excise cess and sales tax 37215 37416 40043 45073 51822 58754

Total revenues retained 44112 46314 50799 54484 67952 75052

Operating expensesManpower 582 799 798 921 1079 1260Materials 1638 2078 2229 4046 5758 7248Services 4n85 4399 4796 4270 6076 7649Research and development 176 169 375 352 363 385Year end revaluahon 2428 8781 5198 4420 6572 6061Depreciation 3027 3375 3782 4034 3691 3361Depletion 4503 5307 6161 5577 7175 9080Amortization 6468 6332 6553 6419 7865 6493

Total operating expenses 22907 31240 29892 30038 38579 41537

Operatirig income 21205 15074 20908 2U47 29373 33515Interest income 3871 3662 5663 6387 6194 6510Interest paid 4868 5684 7361 9868 13080 15802Less. Intere-t (net) 997 202t2 1698 3481 6886 9291Corporate taxes 3970 3015 4182 4889 587; 6713Net operating inconme 16238 10037 15029 16076 16612 17i320Dividends 549 1055 1145 1284 1432 1 ;84

Net income rctained 15689 8982 13883 14792 15180 15937

RatiosOperatin g ratio (gross revenues) (percent) 28 37 .33 30 32 I1Operating ratio (revenues retained) (percent) 52 67 59 55 57 55Return on total equity (percent) 16 11 13 14 15 16Retirn oi net average fixed assets (percent) 19 11 13 12 12 12Return on capital employed (percent) 14 9 11 10 10 10Divid,-ol 'pI fwrrent of total equity (percent) 1 1 1 1 1 1

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INDIA Annex 3.11GAS 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

SourcesOperating income ncl.interest income) 25,076 18,736 26,571 30,834 35,567 40,M5Additions (deductons):Depredation 3,027 3,375 3,782 4,034 3,691 3,361Depletion 4,503 5,307 6,161 5,577 7,175 9,060Amortization 6,468 6,3. 6,553 6,419 7,865 6,493Others (net) 375Year 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 65,019Borrowings

Foreign currency loans onlent by COI 1,350 1,004 1,321 6,669 /,275 5,52ExportcreditsandotherFCborrowing 16,117 13,378 13,584 27,703 29,146 23,555Subtotal 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 93,426ApplicationsTotal capital expenditure 30,995 31,494 37,848 57,472 52,227 42,940Long-term investment and PSU loans 5,589 19,062 6,894 (1.843) 3,014 8,874Debt 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 15,802Subtotal debt service 13,674 10,805 10,432 18,876 28,696 29,081Corporate tax 3,970 3,015 4,182 4,889 5,875 6,703Dividends 549 1,055 1,145 1,284 1,432 1,584Inaease (decrease) in working capital 4,650 (8,518) 2,668 4,978 6,048 4,445Increase (decrease) in intangible assets (83)Total applications 59,344 56913 63,170 85,655 97,292 93,626Debt service coverage 2.8 3.7 4.2 2.5 1.9 2.0Self fLnancing ratio (percent) 81 ;79 100 36 45 78

ONGC's Foreign Exchange Requirements, 1991 to 199SUSS million

2500 9 1 9flaring1pro9|Lll - Lillproect

2000 Other capital expenditure__CGsh operating cost1Debt serviceI I

1500

1000

0 -99 1992 1993 1994 1995

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INDIA Annex 3.12GAS FLARING REDUClION PROJECr Pa-ge1onf1

ONGC Balance Sheets, 1990 to 1995

Rs miliw

Fiw yar endmg Marc 31 1990 1991 1992 1993 1994 1995

AssetsCurrent sCash and bank 2,065 2,234 2,460 2,877 3,982 4,963Debtors (net of provisions) 16,954 6,467 6,781 6,824 8,232 9,309Inventories 12,166 13,966 1452 9 21,5M 25,522 28,402Other 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 assetsProperty, plant and equipment 39,825 39,967 44,027 52,951 61,067 6S,502Producing property 39,834 47,991 58,077 80,729 1E3,041 115,407Unallocted 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 66,157Loans to public sector undertakings 4,720 4,720 4,720 4,720 4,720 4,720Intangible assets 3,860 3,860 3,860 3,860 3,860 3,860Total assets 199,554 226,578 299,890 306,982 3529 392,265

Liabilities and equityCurrent liabilities:

Provision for tax and gratuity 21,146 21,146 22,542 24,007 25,567 27,152Other 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 3,428Reserves&surplus 102,096 111,078 124,961 139,754 154,934 170,871

Total equity 105,524 114,506 128,389 143,182 158,362 174,299Total 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 1.7Long-term debt-equity ratio 0.5 0.7 0.7 0.9 0.9 1.0

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INDIA Annex 3.13GAS 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 yearsending March3 1. The financial projections do not take into account the transfer of assets from ONGC toGAIL, 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:

Exchange Ra,es and Inflation Rates 1991 1992 1993 1994 1995

Exchange rates (I USS equivalent) Rs 19.4 20,8 21.8 23.0 24.1Domestic inflation (percent) 8.3 6.6 6.5 6.5 6.2International 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 ratesprevailing on December 31, 1990 are assumed to depreciate against the Rupee at the same rates as the USDollar.

Income statements

3. Projected sales of crude oil and gas are based on ONGCs production forecasts, taking intoaccount ongoing and planned development schemes. For the purpose of the financial projections pro-jected revenues assume the same producer prices for crude oil and gas as those prevailing in FY91 (Annex3.9) throughout the projected period. The level of royalties, excise cess and sales tax has also been as-sumed constant.

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

5. Deprdciation, depletion and amortization assume the continued application of ONGC'scurrent 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 terminvestments and ISU loans. Interest paid represent ONGC's projected annual interest payments on itslong term debt

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

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INDIA Annex 3.13GAS FLARING REDUCTION PROJECT Fage ToT

Assumptions to the Financial Projections

Fund Flow Statements

8. New borrowings take into account the proposed project financing plan. Foreign currencyloans onlent by Govemment assume a 15% interest rate with a 5 year grace period and 15 year overallmaturity. New export credits were assumed at a 10% interest rate with annual repayments of 10% of theamnount outstanding at the end of each year.

9. Details of ONGC's planned capital expenditure are given in Annex 3.8. The amounts havebeen adjusted for inflation and fixed asset additions are based on ONGC's current accounting practices. Itshould be noted that the proposed investment program was based on ONGC and Bank estimates and notall expenditures have been approved by the Government.

Balance sheets

10. Current assets: Average level of cash and bank balances was assumed at 30% of cashoperating costs. Debtors assume a credit period of 21 days for crude oil, 15 days for LPG and NGL salesand 30 days for natural gas. The level of inventories was assumed at 12% of net fixed assets. Other assetswere assumed to increase with domestic inflation.

11. Current liabilities were assumed to increase with inflation.

12. Increases and decreases in long term investments were determined by the level of totalsources available after taking into account working capital requirements, debt service and capital expendi-ture.

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INDIA Annex 4.1GAS FLARING REDUCTION PROJECT Page Tof 4

Layout Optimization of the Pipelines to be Constructed

1. While the design of the process platforns and related gathering fluid lines for the BombayHigh field is fairly standardized, the layout cn-eptualization of the gas trunk pipelines requires someattention to the optimum route in relation to potential gas markets. The principal factors that were takeninto account in the decision of the layout of the proposed gas pipeline system included review of therecoverable reserves, market growth rate, consumption pattern and problems associated with the develop-ment of the infrastructure. The review of the Bombay High, South Bassein and surrounding fields poten-til indicates that the project would sustain the delivery of 30 to 35 MMCMD of gas for the next 20 yearsIn addition, new offshore gas reserves are being identified north of the Bombay offshore field towards theGulf of Cambay. The conceptualization of the proposed pipeline system as well as the flow capacity of theprocessing facilities have, therefore, taken into account the issue of whether the gas should be taken to theBombay area or to the northern part of the country along the HBJ gas pipeline. After a careful review ofthe gas demand projections, market constraints and pattern of consumption, it is proposed that the projectwould bring gas to both the Bombay area and Hazira as wel as areas along the HBJ pipeline.

2. The Bombay area market, where gas is mainly used as industrial fuel, is a supply con-strained market with long lead times for development of the necessary additional gas supply infrastruc-ture. This market will continue to be dependent on the Uran terminal for the next 8 to 10 years. Thesupply shortfall is, however, expected to be substantially reduced with the expansion of the terminalwhich will be undertaken soon under a separate project. The terminal, which is now supplying 12MMCMD, will be expanded to its maximum capacity of 16 MMCMD. As the demand is projected to growfurther, ONGC is proposing to the Government the construction of a new terminal to increase the supplyby 10 MMCMD of gas. With regard to the market along the HBJ gas pipeline with a current consumptionof about 15 MMCMD as feedstock for fertilizers, the demand has been less than anticipated. There is,however, a perceptible shift occurring in the previous policies of gas allocation and pricing that have up tonow hindered greater gas utilization along this pipeline. The demand for gas along the HBj is nowproiected to grow at a fairly rapid and higher rate than for the Bombay area. Power generation is expectedto entail a big increase in gas use. Other markets, including petrochemicals, are also being developed.Various projections indicate that overall gas demand along the HBJ pipeline would increase to 40MMCMD by 1995-96.

3. The quantity of additional gas to be supplied to the Bombay area market would be limitedto the maximum capacity (16 MMCMD) of the Uran gas terminal. To meet this additional quantity, theexisting Uran - Heera gas pipeline would require to be extended to the Bombay High field. It is onlythrough this extension, the ICP-Heera gas pipeline, that the supply of the Bombay market can be increasedand the current gas flaring substantially reduced. Since no gas compression would be required, theconstruction of this line would have to be undertaken as soon as possible in order to be completed simul-taneously with the expansion of the Uran terminal. Such a line, for which the precise route would bedetermined by the detailed engineering design, could also be used for the transport of the Bombay Highgs cap at a later date as well as associated gas from any of the recent discoveries made in the BombayHigh field area. Furtmore, the line would optimize ONGC's contingency response capability shouldthe existing old line need to be repaired. With regard to the mnarket along the HBJ gas pipeline, it becomesnecesary that a new pipeline be built between Bombay High and Hazira. The pipeline constructionwould consist of two wgments, from Bombay High to South Bassein (SHG-BPB) and then to Hazira.Subeequently, the capacity of the Hazira gas terminal would need to be expanded.

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INDIA Annex 4.1GAS FLARING REDUCTION PROJECT Pe 2 of 4

Lay-out Optimization of the Pipelines to be Constructed

4. The project optimization design carried out by ONGCs consultant EIL has been reviewedby the Bank and found acceptable. It is a preliminary engineering design based on an exhaustive study ofall pertinent factors and data related to gas recoverable reserves and utilization plans. The sizing andbroad specifications of the project facilities including the pipeline system layout have been determinedfollowing a careful evaluation of available alternatives. The detailed engineering design would be carriedout by the contractor to be selected for the construction of the project component. The current preliminarydesign is sufficiently flexible to allow configuration design adjustments to be recommended by thedetailed engineering design. Figure 1 shows the schemnatic layout of the existing gas pipelines and thosethat will be constructed under the project. Figure 2 shows the expected flows of gas through the pipelinesystem in the Western offshore region.

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INDIA Annex 4.1GAS FLARING REDUCTION PROJECT Pdge 3 of4

Lay-out Optimization of the Pipelines to be Constructed

Figure 1 Layout of the Pipeline System

L,egeiid

o Existing plattorrn

Pl tform to be constructedunder the project

0 00 - Existing pipeline

.Pi ' peline to be constructedunder the project .. .

3',0~~M- ' :0 ., 0 lptz

* >; A B /3agW/f MMcfp *N.,

_~~~~~~Q

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" am lox cog"Ir m a9m r

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l~ ~~i ml _u~' WI e.9S¢fl__ 9Sl Ml Mt ncOh ml 10l r9

091 Mt Mil : toil Mt 461 006act1 1M1 "'I t

¢ §" S VIIi ilt rol | Nl il 9fS n l

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pnXsuoD aq °1 saulpdd *~C M, o uopezadId Mt ooo~~~~~~~~~~~~~~~~~~~~~~uei rc MteS )NfOEd galDla3 fit-t~~~~~~~~~~~~~~~~~~~~~~~a Mtu zolannt

VI ml crtt ull ii ourradid~~F'1-t WI 0 1 lot IROWN-MG as m 'SdG-DHS IMVH a~~~~~~~~~~~~~~~~~~~~~-s.

UwJn-NHO~~~~~~~~~~~~~I

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to to Noeaomn CK Mra ro~~~~~~~~~~~~~~'s p r a t u

tI 9 a km1

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C-otael IDId OL-0 NilNrvu v

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INDIA Annex 4.2GAS .LARING REDUCTION PROJECT Pag I of

Detailed Project Description

Background

1. ONGC has decided to implement a najor investment program aimed at enhancing oilproduction in the Bombay High oilfield. This oilfield, which is about 160 km west-northwest of Bombayand in the Arabian Sea, accounts for about two thirds of the country's current oil production of about 32million tons a year. The field was discovered in 1974 and put on production in 1976. The programconsists 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 phasedsequences 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 reservesof about 1500 million tons. It extends within the entire field area at an average depth of 1300 m. An East-West sedimnentary discontinuity divides the field into two sectors, the North and the South. About onethird of the L-1I1 oil reserves is located in the North and two thirds in the South. Oil production from L-IIINorth started in 1976 and reached a plateau rate of 6.25 million tons per year in 1980. It started to declinein 1987. In 1990 it produced about five million tons per year. The decline in production was largely dueto the shutting of several welkl as a result of delays in implementing the pressure maintenance and gas-liftprograms. By the end of 1990, the cumulative production from L-l1 North had reached about 68 milliontons of oil and 21 billion cubic meters of gas, representing about 18% of the initial in-place reserves. Oilproduction from L-lI1 South started in 1980 and reached a level of about 13 million tons per year in 1983and maintained between 13 and 15 mnillion tons per year thereafter. By the end of 1990, the cumulativeproduction 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'stotal oil reserves, is located only in the northern part of the field at an average depth of 950 m. It has alimited oa column thickness of 25 to 30 m. It remained undeveloped because ONGC devoted its efforts tofirst develop the L-III reservoir. Its performance, however, has been conclusively tested by some 20production wells. Some of these wells have been producing oil since 1981. Its production rate has reachedone million tons per year of which two thirds comes from four horizontal wells drilled over the past fouryears. The L-Il reservoir will now be developed and is expected to sustain a production level of about 1.5million 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 1988 by ONGC with the assistance of the Frenchoil company CFP Total, indicatea that the Bombay High production can be substantially increased and itsoverall decline delayed by developing the westem and southem peripheral areas of the L-1lI reservoir inthe 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 theHazira Gas Terminal (located about 260 km north of Bombay in the southem part of the Gujarat State) andthe other to the Heera field (located about 70 km southwest of Bombay in the Arabian Sea) where it wouldbe connected to the existing Heera-Uran gas pipeline which is currently supplying about 1.5 MMCMD of

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INDIA Annex 42GAS FLARING REDUCTION PROJECT Page 2 of 8

Detailed Project Description

Figure 1 NQP Proce" Piatform Flowsheet

FUelPS A>[<gLlrEFue

e,*,,,, ,*...>,.......................

~~~~~~3tge0:0s PL ~WI1:-.:::

...... . . ....... , J.. .. conditire weNc

packag

s s ,, ss ,, ........ ., , .. j,. ......

gas from Heera to the Uran Oil and Gas Terminal (about 15 Jr. southeast of Bomnbay) for the Bombay areanarket. rae L-III program is expected to increase the production by about 40 million tons of oil and 18Bcm of gas during the 1B95-2010 period. The L-11 reservoir development will cons.;t of construction offive well platforns with the drilling of 42 infill wells, a process platform and an inter-connecting gaspipeline system. The L-II vrogram is expected to increase the production by at least 16.5 million tons of oiland 6 Bcm of gas during the 1995-2010 period.

5. To accommodate the additional production, ONGC is expanding the gas processing capac-ity of the Uran terminal frn.n 12 to 16 MMCMD, ar.d that of the Hazira gas terminal from 20 to 41MMCMD. The expansion feasibility and environnental impact studies for the Hazira terminal areexpected to be submitted for Government approval within the first quarter of 1991. Furthermore, cor.-struction of an additional oil and gas terminal with a first phase processIng capacity of 10 million tons ofoil pei, year and 10 MMCNMD of gas is being studied by ONGC's consultant, Engineers India Ltd. Accord-

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INDIA Annex 4.2GAS 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 wouldincrease the gas supply of the Bombay area from 16 to 26 MMCMD. lmplementatio*. of the entire pro-gram, including construction of the terrninals, is planned to take seven to eight years. DL velopment of theBombay High L-III and L-ll reservoirs along with construction of related gas pipeline systems and expan-sion of the Uran and Hazira terminals is expected to be completed during the first five years of the devel-opment program.

Project Proposed Project

6. The project proposed for Bank financing would provide support for those components ofthe Bombay High development program that are required to eliminate the flaring of associated gas. Theproject would enable ONGC to recover an additional 7 to 8 MMCMD of gas over and above the 12 to 14MMCMD 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 fieldwith a processing capacity of 100,000 barrels (bbl) of oil per day, 15 MMCMD of gas and140,000 bbl of water per day. The platform includes a 78 kilometer (km) pipeline with adiameter of 28 inches to the BPB platform at South -Bassein.

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

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

* Reservoir pcrformance and management studies and training.

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

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

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INDIA Annex 4.2GAS FLARING REDUCTION PROJECT FgWo

Detailed Project Desaiption

Figure 2 SHG Process Platform Flowsheet

Cmupodty. 2., ,esD _ 0 ,,,,,,: : -: arl s;> .. ~~~~~............ ... f

,,,,, l l Fuel gs

f 1 s~~~~~~~~~~~~- ~ R c . s_ ..... ........

(12 No.) 1*11~ stgs(y.

glycolo,e:

............ ........ . ~~~~~~~~ ~ ~ ~ ~ ~~~........ . ....... . .. .. .. .. '."

. ~ ~ ~ (N.

necte~ to th exstigpa tforms, N. an N , by a brdg. It wil hav faiite fo oi, ga an wae

separa..on water treat t, g, d, fr se ' e t r ad c sio, high pflare to be- located at- about 750 .m away on a: tripod, fireprotection oil pumping, te

r~~~~~~~~~A Mil I* . . . ......... .. . . .:,:.,:

- | P s i£i; I J . : l*~~~~~rodcec wter i i

Llnes ~~~~~~~~~~~~~~~~~~~~~~~~~~~~~. .. .. :. .. ... . .

flare~~~~~ ~~ ''' be located wate abu 75 m awa on a trpd'iepoeto,olpmigeeomnctos

tolemetry, telecontrol and helideck. The platform construction will include supply and installation ofthree gas turbine driven centrifugal compressors, each designed for 2.2 MMCMD corpression capacity at8 to 10. k<g/cm2 suction and 103 kg/cm2 discharge pressures, supply and construction of intc -conr.ecting

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INDIA Annex 4.2GAS 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 gaspipeline.

8. CONSTRUCMON OF SHG PROCESS PLATFORM. This is to be a two-deck, eight leg platform with aprocessing capacity of 100,000 barrels of oil per day, 15 MMCM'. of gas and 140,000 barrels of water perday. It will be installed in the southem part of the field in about 70 m water depth and connected by abridge to the existing SHP and SHQ processing platforms It will have facilities for oil, gas and waterseparation, water treatment, gas dehydration and compression high pressure ilare to be located at aboutone kilometer away on a tripod, fire protection, oil pumping, telecommunications, telemetry andtelecontrol. The platform construction will include supply and construction of the interconnecting wellfluid lines, installation of seven gas compressor modules and construction of a gas pipeline to connect theplatform to the BPB platform in the South Bassein gas field. The gas compressor modules and the linepipes will be procured separately from the platform.

9. CONSrRucION OF GAS COMPRRSSOR MODUxES. Seven gas turbine driven centrifugal compressormodules will be built by specialized manufacturers and supplied to the SHG platform contractor forinstallation. 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 toprovide sufficient pressure to transport the gas through a 330 km submarine pipeline to the HaziraTerminal. A small quantity of the cornpressed gas will be distributed and circulated in the oil producingwells to improve their productivity through gas lift mnechanism.

10. MOI)IrICArION OF E)asnNG PLATrFORMs. In order to fully integrate the platforms NQP and SHGinto 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 producedtogether with the oil from the ageing reservoirs. Acoditional lines with pipeline scraper launchers andreceivers w ill be built between the new and existing well platforms. Piping configuration will also bereviewed and s:me lines changerl. Structural reinforcement will be required for some of the oldestplatforms. 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 fourwell platforms (NO, NW, NHi, and N6) and four process platforms (NQD, NQO, NQG, and NQF) inBombay High North, eight wclU platforms (SY, SW, SY, IL., 1K, SS, II and IH) and four process platforms(SHP, SHID, SCA, and SHQ) in 13ombav High South and one process platform (BPB) in South Bassein. Thework 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 southsectors of the Bombay High oilfield;

(b) Modification of the following existing weil platforms so that they can handle additional wellfluids: 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 flaresystems.

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INDIA Annex 4.2GAS FLARING REDUCTION PROJECT Page oT

Detailed Project Description

11. CONSnRUCrION OF INTERCONNECFING AND TWUN.K PIPELINES. To optimize the field oil and gasgathering system and bring the associated gas to shore, new interconnecting and trunk submarine gaspipelines will be built under the project. The interconnecting pipelines will consist of well fluid lines fromthe process platforms to the well platforms and two gas lines from the process platforms to the trunk gaslines. About four well fluid lines will be built in the North (from NQP, NQO and NQG complex to NH 8.5km, NO 3.6 km, NW 7 km and N6 11 km) and three in the South (from SHG, SHP and SHQ complex to SY8 km, IL 8 km and IH 15.5 km). The two gas lirnes will consist of (i) a 30 km long, 18 inch diameter pipelinewith 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 platformSHG to the South Bassein gas field). The construction of these lines aJong with the well fluid lines will becarried out under the NQP and SHG platform construction contracts.

12. ICP-HEFRA PIPL:LINE. To take all associated gas to shore, two new trunk gas pipelines will bebuilt under the project. The ICP-Heera Trunk pipeline, also called the South Loop, will stretch 142 kmfrom 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

= ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ t -== a:=

l15.6 M;M ==_M daTeon :0 : ::CM

V MMCMD I I Y L :: : : : :7MMCM

Slu~[E -g cachr ;' : "'""''

397t/d ~ ~ ~ ri /

$35 ~ ,/ . ,.,. ... , ,. , .:,

swening d

n lugcat er ---X>n 5 i :

i s sM n~~~~ tfd unit n

$ sE- .: : : . j :~~~~~~~~NC'-.'.

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INDIA Annex 4.2GAS 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 deter-mined, but will be between 26 and 30 inches for a gas flow capacitv of about 9.5 MMCMD. It will beconnected to the SHG process complex by a 22 inch size, 11 km long line. It will supply gas to the Uranterminal for the Bombay area market. Its construction will complete the South Loop for which the firstsection, Heera-Uran, was completed in July 1990 under a separate Bank financed project (Western GasDevelopment Project, Loan 2904-IN). The new line will carry about 3.5 MMCMD from Bombay HighSouth to Uran as soon as its extension is complete. Its design will also optimize contingency responsecapabilities of ONGC should the 15 year old Bombay High-Uran trunk gas pipeline become idle forservice and repair. The risks of disruption of the existing pipeline system have been assessed under aproject previously called the Western Offshore Integrated Development Prosect (WOIDP). The WOIDP, asoriginally designed. has been abandoned. However, several of its key components have been integratedinto the new developmnent program.

13. BPB - HAaiA PIWPLINE. The second trunk gas pipeline, BPB-Hazira, will stretch some 255 kmfrom South Bassein gas field (about 65 km west of Bombay in the Arabian Sea) to a landfall point nearUmrat (about 235 km northeast of South Bassein and 240 km north of Bombay in the southern part of theState of Gujarat) and then to the Hazira gas terminal (about 20 km north of Umrat). It will be built alongthe existing South Bassein - Hazira gas pipeline. Its size has not yet been determined but will be between36 and 42 inches for a gas flow capacity of about 20 to 25 MMCMD. It will connect with the SHG-BPB gasline and transport about I MMCMD of associated gas from the Bombay High oilfield and 5 MMCMD ofsour 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 determinewhether the gas to be transported should be "wet" or "dry." A wet gas contains some hydromarbonliquids (condensate), which will undergo some degree of condensation during transport depending on thecomposition of the gas, transient temperature and pressure conditionrs in the pipeline. For the samevolume, a wet gas requires a slightly larger pipeline size than a dry gas from which most of the conden-sate have been removed. In the present case, condensate removal will require complex treatment withadditional offshore platform space and facilities such as refrigeration units, condensate handling andother equipment, which could, as in the case of existing gas pipelines, offset the incremental cost of largerpipeline sizes. ONGC will consider the least cost option on the basis of an ongoing engineering study. Allinterconnecting and trunk submarine pipeline routes will be in well known areas. Most of the pipelayingcorridors have been surveyed under pievious construction activities and do not present any implementa-tion difficulties.

15. EXPANSION OF HAnRA GAS TERMINAL. In order to be utilized efficiently and sdfely, natural gasdelivered to consumers must meet certain requirements and specifications. Untreated or unprocessednatural gas contains many hydrocarbon compounds and a few non-hydrocarbon compounds. Some ofthem are of considerable value (LPGs and NGLs), while others are contaminants that render the gasun1 suitable for most commercial uses (water, hydrogen sulfide and carbon dioxide). In the case of BombayHigh 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 carriedout at the Hazira terminal. The Hazira terminal is also designed to remove carbon dioxide and hydrogensulfide, which are found in high concentration in South Bassein and Panna gas fields. The hydrogensulfide is a poisonous gas that could be a serious hazard to the environment if it is not treated properly.

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INDIA Annex 4.2GAS FLARING REDUCTION PROJECT TNaeR of 6

Detailed Project Desaiption

16. The Hazira Gas Terminal has been built in phases. The first one for a capacity of 10MMCMD of gas from South Bassein field was financed by the Bank under a loan that closed on December31,1988 (South Bassein Gas Development Project - Loan 2241-IN). It was completed and commissioned inJuly 1988. The second phase, to increase the terminal's capacity by another 10 MMCMD of gas also fromSouth 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 thenits 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 processingcapacity from 20 to 41 MMCMD. The new facilities to be designed for a 21 MMCMD capacity will besimilar to the existing ones. They will consist of two slug catcher units (one for sweet gas and the otherone for sour gas), one gas sweetening train, one sulfur recovery train, one gas dehydration unit, four dewpoint depression trains and four condensate fractionation trains. The size of the sweetening, sulfurrecovery and dehydration units will have a processing capacity of five MMCMD of sour gas, which willcome from the South Bassein and Panna fields. The liquid hydrocarbon recovery from the proposedexpansion will be 192,000 tons per year of LPG and 360,000 tons per year of NGLs. Additional plantutilities and offsite facilities, such as power generation, cooling water, product storage and productloading terninal will also be required.

18. E.VI\ONoMhN-rAl. COMPONFNTr. Following the appraisal mission's review of environmental andsafety 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;

(c) strengthening of the current arrangements for rescue of persons at sea;

(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 environmentallysensitive 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 desigrn of efticientflare systems and risk assessment studies.

19. RESERVOIR MANAGEMSENT COMPONENT. The rapid increase of gas flaring is, to a large extent, dueto the delay in water injection and other measures that proper reservoir management practices wouldrequire. ONGC requested financial support for a study of the Bombay High reservoir, which shouldrecommnend a number of steps to optimize hydrocarbon production and arrest the decline of oil outputfrom this field. This component will provide financial support for equipment, materials and servicesneeded for the workover and rehabilitation of designated oilwells.

a a

a a 1~~~~~~~~~~~~~~~1

L L2 ia ; C

A, .~~~ ~~~~~~~~~~~~~~~~~~~~..~...... .. .. ... .

.-.... , .,.- ~ ~ ... .. .. . .O'Q•

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INDIA Annex 4.4GAS FLARING REDUCTION PROJECT Page I of

Project Implementation Schedule

VFY 90/9flj FY 91 /92 FY 92/93 FY 93/94 |FY94/95199 1991 199 199 1994 199

NQP Process Patform .

Complex

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

SHC Process PlatformComplex

South Zone Linepipe

South Zone Lin pipe

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

ICP-Heera Linepipe6 - -

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

BPB-Hazira Linepipe

BPB-iHazira Linepipe Coat, IVA4ap and Conauci n

Hazira Terminal Expansion

Ky to symbols I ssue of IFB 4 Award of conbad

4 Bid submission sense"l PNe-Constrdon Activities

O Review of bid evaluation a Cnstruction Activites

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INDIA Annex 4.4GAS FLARING REDUCTION PROJECT Page 2 of 3

Project Implementation Schedule

Inr'tat ion for Opening of Review Award of Compt ion ofMajor procurement packages Bids to be Price Bids of Bid Contract Contract

Issued Ewavutiom

Process platform, NQP Jun-01-91 Jan-01-92 Jan-17-92 Mar-29-92 Apr-30-94Compressors, SI IG Jun-01-90 Jul-10-91 Jul-24-91 Oct-01-91 Aug-30-93Process platform, Si IG May-01-91 Nov-30-91 Dec-15-91 Feb-01-92 Mar-30-94Linepipe, SiCH BPB Apr-25-91 Aug-30-91 Sep-15-91 Nov-11-91 Oat-01-92Laying, coating and wrapping. Si IG-BPB Mar-29-91 Sep-20-91 Oct-0691 Nov-20-91 Apr-20-93Platform modifications Dec-01-91 Jun-08-92 Jwi-23-92 Sep-01-92 Feb-28-94Linepipe, ICP-Hleera Nov-15-91 May-19-92 Jun-04-92 Aug-22-92 Apr-30-93Laying, coating and wrapping, lCP'l ieera Feb-10-92 Aug-25-92 Sep-10-92 Nov-25-92 Mar-31-94Linepipe, BPB-1Hlazira Sep-01-91 Mar-12-92 Apr-18-92 May-30-92 Jw-31-93Laying, coating and wrapping, BPB-I lazira Jun-01-92 Nov-10-92 Dec-17-92 Feb-28-93 Dec-31-94Expansion 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. LICB is a procedure which will be followed by ONGC in procuring of certain projectcomponienits, e.g. linepipe, the process platform SHG and other items, which the Bank will not finance andfor 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 referredto as "price & terms" bids. However, LICB has not yet been used i;] conjunction with Bank-supportedprojects in Inidia. Essentially, LICB is a resource mobilization technique used in cases where there areindications of strong supplier interest and where the prospective borrower finds it convenient to leave theresource mobilization responsibility with the suppliers. It is a practical way to mobilize resources insituations where the actual source of supply would become known only after the bid(ding and where, atthe same titne, the borrower has reasonable evidence that the major part of prospective suppliers wouldbe in a position to provide the requisite financing from, or with the guarantee of, the official sources, suchas Export Credit Agencies (ECAs). The Bank will not firance any portion of the LICBs.

2. T here are two main features of LICB which distinguish it from international competitivebidding, 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), inaddition to quoting the price, to offer financing at certain mninimum terms andconditions, specified beforehand; and

(ii) The responsive bids under LICB are evaluated on the basis of the quoted price andthe offered terrns of financing. Customarily, this process entails the evaluation of bidson the basis of their present value, calculated by applying a pre-announced discountfactor(s).

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

* 85 -

INDIA Annic . 4.4GAS FLARING REDUCTION PROJECT age 3 of3

Project Implementation Schedule

LICB underwent particular scrutiny by ONGC as well as by the World Bank: (i) supplier interest in theprocurement of project items -eferred to in para. : above; and (ii) availability of credit to ONGC from theprospective 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 LICB confirmed the existenceof 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 forprocurement under LICB, evidence was obtained through the tenders issued by ONGC in 1990 for thesupply of line pipe and equipment for the SHG Complex and for the ICP-Heera Pipeline, on whichoccasion about half a dozen suppliers from Western Europe, North America and Japan submitted theirbids. 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 LICBwere likely to originate. In all cases, indications were received of ONGC's eligibility for export credit. Onthat basis, the procurement under LICB in an estimated amount of about U&M957 million was deemedfeasible.

5. One of the key issues that a prospective LICB user has to resolve relates to the minimumterms and conditions of financing which the (responsive) bidders would be required tc furnish. Under thecircumstances, given the length of the period required to depreciate the LICB-procured items and the typeof financing that appeared available for the purpose, ONGC decided to define the minimurmi acceptabletenns of financing under LICB as the most favorable terms and conditions available to India under theOECD 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 certainperiod, e.g. 6 months, after installation of equipment, thus effectively resulting in Ic ans with final maturityin excess of 10 years. T he applicable interest rate, which would be determined on tU E basis of a matrix ofexport credit rates which is revised by the Consensus members every 6 months. Fok example, on January15, 1991, the matrix rate for Consensus export credits to India, with mraturity over 8.5 years and up to 10years, was 9.2 per cent per annum. As an alternative to this rate, ONGC could choose Commercial Intei tReference Rates given that the Consensus allows the borrower to seek commercial rates for variouscurrencies in cases when those are lower than the Consensus matrix rate. Customarily, the financingunder 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 theparticipating bidders to furnish evidence of the availability of the stipulated credit at the time of bidsubmission (or, alternatively, at prequalification, in the event that it should be used as a part of the bid-ding process). Such evidence should be in the form of expressions of interest from ECAs or other financialinstitutions, indicating that the stipulated credit would be available at requisite terms and condiitions orbetter, 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, whichwould be arrived at by applying a predetermnined discount factor(s).

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INDIA Annex 45GAS FLARING REDUCTION PROJECT Page 1 of 3

Environmental Aspects

1. The project is expected to have a major positive environmental impact. The recovery of asubstantial quantity of natural gas that is currently being flared will substantially improve the environ-ment. In addition, the recovery of flared gas along with the incremental gas to be produced under theproject would displace a substantial quantity of fuel oil being used in various small and medium indus-tries in the Bombay areas where industrial and population concentration is already confronting pollutionproblems. Similarly, the power generation program to be supplied with natural gas along the HBJ pipe-line under the project would also displace coal. This would improve air quality by reducing air pollutantscaused by the use of coal such as ash, sulfur dioxide, carbon monoxide, nitrogen oxide and carbon diox-ide.

2. While the use of natural gas compared to that of other fossil fuels is highly beneficial to theenvironment, its development and production entail some environmental and safety hazards. To copewith these hazards, the industry has developed a series of guidelines, which are compiled and updated byinternational agencies (Anetrican Petroleum Institute, American Bureau of Shippin& Uoyds ShippingRegister, and Det Norike Veritas). In most countries, thesc guidelines are adjusted to the country's specificsituation and enforced through national legislation or other regulations. In this regard, ONGC hasadopted a Recomrnended Code of Practice and applies the Indian Environment Protection Act of 1986 forits oil and gas operations. All projects are subject to a Govemnment environmental clearance (Ministry ofEnvironment and Forests) which requires a satisfactory environmental impact assessment with environ-mental management plans and disaster management plans.

3. ONGC's safety and environmental guidelines and regulat.ons as well as ONGC observancewere evaluated by Bank consultant and staff and found satisfactory. The Bank consultant has also carriedout 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 12months; 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 devel-opment drilling, construction of the process platforms, construction of the gas pipelines and expansion ofHazira terminal.

4. FATAL AcaDENr RAm1 The number of fatal accidents related to the Bombay offshore activi-ties has oeen relatively high over the past five years (1985:1; 1986:2; 1987:1; 1988:3 of which 1 onshore and1 for ONGC's contractors; 1989: 5 of which 3 for ONGC's contractors; and 1990:0). Of the 12 fatal accidentsthree were man over-board accidents and three were related to drilling activities including a well blow-out during drilling. In view of the steep increase of fatalities in 1988-89, ONGC adopted several measuresto enhance the level of safety awareness and emergency preparedness. One of the measures is a riskanalysis and safety audit of production platforms. Engineers India Ltd. with the back up of an externalconsulting firm have been carrying out this work since July 1989. These measures were discussed withBank staff, which found them satisfactory. The fact that there were no fatalities in 1990 seems to point tothe effectiveness of the steps taken by ONGC.

5. DEv ELrr DRILLING. While development drilling is not a project component, several wellswill be drilled within the project area to increase oil and gas production. The potential risk to the environ-ment of offshore drilling is largely due to the increase of drilling waste and the effects of well blow outs.Drilling waste consists mainly of drilling fluids (drilling and chemicals), residual substances and drill

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INDIA A 4irGAS 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.lswhich 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 'iischargewhile drilling represent another major danger to the environment. To minimize this dagr.er, L)NC,( use'sdrilling rigs with field proven mechanical integrity and blow out preventers with rermote control systemsDrilling 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 thispurpose, ONGC has five multi-purpose vessels of which two are equipped with booms and oil skimmerswith an oil spill recovery capacity equivalent to a well blow-out discharge. Additional facilities areavailable with the Indian Coastguard for a recovery capacity of about 300 tons per day. It should be notedthat for larger oil spills, ONGC can avail the services of established worldwide oil spill control centers

7. CONSTRUCnON OF 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 platfonrms willbe 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 goisspills will be minimized through appropriate operating and maintenance practices that were fotiund to thoadequate.

8. RE4EDIAL MEASURES FR EXSTINNG PlAIFORMS. A review of the environmental and safetyrelated equipment and practices on the existing platforms of the Bombay High fields will be carried out ,ispart of the proposed project. In addition to the safety audit being carried out, the modifications planiniedtor the existing platforms will take into account the latest environmental and safety regulations In thisregard, the high pressure gas riser of NQO platf'orm, located beneath the iiving quarters would be relocated on platforms with no living quarters such as NQP or NQG. This approach will be followed in thefuture in simnilar situations.

9. CONSTRUCION OF THE GAS PIPEUNTES. Construction of offshore pipeline also does not cntail anvsignificant environmental risks except very limited disturbances of the sea floor. The linepipe would betaken to sea on barges and welded on a derrick-lay large and then allowed to sink and rest on the sea floorwithin 60 to 70 m water depth. All pipelines planned under the project would be along a previouslysurveyed route that is flat, avoiding boulders and any other obstructions that require blasting. To mini-mize 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 forconstruction would be carefully inspected. The welding would be inspected by X-ray techniques andhydrostatic tests. The risk of corrosion would be minimized by using adequate cathodic protectionmethods. The pipeline would be equipped with automatic shut-off valve devices and metering systems togive continuous comparison between input and output on all lines. This allows operators to discoverleaks immediately.

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IND;A Annex 45GAS FLARING REDUCTION PROJECTI age3

Environmental Aspects

10. EXIPANSION OF tHE HAZJIA GAS TERMINAL. The construction of additional facilities at Ha_iraentails no environmental risks. Some disturbances would, however, be generated from dust during thesite 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 facilitiesare put into service, there would be, however, an increase in the environmental risks since similar facilitiesare 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 andloading facilities. The design of the terminal would be such that these effluer.ts would be collected byvapor recovery, ventilating systems. The fact that the additional facilities would process 5 MMCMD ofsour gas to be constructed at Hazira with gas desulfurization and sulfur recovery equipment wouldsignificantly reduce the amount of sulfur that would otherwise be released into the atmosphere. Withregard 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 removeany oil and suspended solids. It will then be filtered and used in cooling systems or disposed of. Thesanitary waste would be treated in specially designed units. Process waste would be collected in tanksand treated for removal of any oil and suspended solids. A-r flotation units would be used for removal ofemulsified 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 asleakproof as possible

INDIAGAS FLARING REDUCTION PROJECT

Detailed Project Cost

usS miallw

Fii Qr y mdi Mwrc 31 FY92 FY93 FY94 FY95 FY96 ToWlnjrd 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 50.2 259.2Cnp_ 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 30.0 155.0Proe 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 2852Lineppe, 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 75.4Layin 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 21.8Plaform nbdificans 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 78.5Linpipe, 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 91.0IAyf atng and wrappingICP-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 23.3 120.3linepipe,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 0.0 220.0 660 286.0laying,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 74.0 275.3 217.8 493.1Raesroi 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 61.6 129.0EngIneei adproat _ 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 2.6ElnvIrommeti 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 2211.9Physcal 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 '212Prkxontingindes 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 2,87.4Taxes and asoms duties 12.4 125.8 1363 89.6 102 374.4

Noee Total bne wot incdudes twoes and cusaous dute

Vfii

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INDIA Anniex 4.7GAS FLARING REDUCTION PROJECr PI1rg

Project Financing Plan

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

Proposed Financing Planus$ "dalo

PrOJ1 ComCants Foin LoW Totl World ap ADB Export ONGC ONGCCost Cost Cost 1ank Untied Credits Forgn Lal

Process platfor. VQP 261.0 713 3323 261.0 713Compre-sors, SHC 152.5 40.9 193.4 129.6 22.9 40.9Process platform, SHG 288.2 79.0 367.2 245.0 43.2 79.0Linepipe, SHG-BPB 70.2 23.3 93.5 59.7 10.5 23.3Laying, coating and wrapping, SHG-BPB 19.2 8.3 27.5 19.2 8.3Platform modifications 78.8 21.5 1003 78.8 21.5Linepipe, ICP-Heera 84.7 28.1 112.8 72o 12.7 28.1LAying, coating and wrapping, ICP-Heera 120.0 32.5 152.5 120.0 32.5U.nepipe, BPB-Hazira 281.6 98.2 379.8 239.4 42.2 98.2Laying, coating and wrapping, BPB-Hazira 165.4 461 211.5 165.4 35.4 46.1Expansion Hazira gas terminal 350.4 320.8 6712 350.0 0.4 320.8Reservoir management, services and equipment 80.6 80.7 161.3 79.3 1.3 80Q7Engineering and project management 9.2 31.4 40.6 9.2 31.4Studies and training 2.5 0.8 33 2.5 0.8Environment and 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 8963Interest during construction 204.1 101.8 305.9 204.1 101.8

Total 2186.2 998.1 3,184.3 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, takinginto account external resource availability constraints outlined in para. 3.25. Given the large foreignexchange requirements - US$2.2 billion - and the fact that a more extensive use by ONGC of private sourceborrowings did not appear feasible at this time, it was agreed that a combination of cofinancing sourceswould be required to make this financing plan viable.

3. ExroRr CREDrr. The effort was first made to maximize the use of official export credits, - asource 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 supplierswith the backing of their respective ECAs (and, possibly, with somne participation from the commnercialbanks supporting the suppliers). Following a request by ONGC for assistance in mobilizing the cofinanc-ing, the Bank contacted a number of ECAs to ascertain the availability of credit and/or export creditinsurance to India. These contacts confirmed that an adequate volume of export credit would be availableto finance suitable procurement packages, e.g. linepipe. Based on inquiries made by ONGC, in some casesalso by the Bank, it was also established that most potential linepipe suppliers would be willing to providecredit. 3ome suppliers indicated that they were prepared to arrange the financing of larger procurementpackages, such as platforms. ONGC decided that it would seek suppliers' and export credits for itemssuch as linepipe, compressors and the process platform SHG.

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INDIA Annex 4.7GAS FLARING REDUCTION PROJECT Fage2

Project Financing Plan

4. In order to ensure that the envisaged USS 745.& million in parallel cofinancing would beforthcoming, ONGC intends to limit the bidding for the kind of packages ihdicated above to biddersoffering 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 toONGC under the Consensus could have repayment terrns of up to 10 years and fixed interest rates. Allresponsive 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 BANK OF JAPAN (1-EXIM). In order to secure additional cofirancing, theGovernment applied in March 1991 for an untied facility from J-EXIM in the amount of US$350 millionequivalent. J-EXIM is currently studying this application. If accepted, the untied J-EXIM loan wouldprovide parallel cofinancing for the expansion of the Hazira gas terminal. Procurement would be carriedout under World Bank procurernent euidelines.

6. THE ASIAN DEvELoPmFNr BANK (ADB). The envisaged cofinancing from ADB would financethe procurement of the laying, coating and wrapping of the ICP-Heera and UPB-Hazira pipelines. ADBwould also finance the environmental component included in the project. Bank staff participated in ADB'spreparatory work for the participation in the proposed project, which has been included in ADB', FY92lending program for India. ADB has informed the Bank that they expect Board approval for their partici-pation in the proposed project in the first quarter of 1992.

7. THE WoRLD BANK. The prcposed Bank loan has been allocated to several procurementpackages. Some of those are crucial and among the most complex components of the project, such as theprocess platform NQP the component dealing with reservoir management. Others, such as 'pltformmodifications', 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 consideredimportant for the Bank to be able to adequately play its supervising role and to provide techtical assis-tance.

8. The total amount of US$ 340.6 million in foreign exchange resources (including US$204million 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 cofi-nancing sources are still being explored, it is viewed as manageable by ONGC.

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INDIA Annex 4.8GAS FLARING REDUCTION PROJECT FagIeTofTTEstimated Schedule of DLsbursemcnb

US$ million

IBRD Amount Cmulhti7e PertnagcFikl Yar Quarter rwi AmountofLam

1992 1 34.9 34.9 7.811 46.9 81.8 18.2111 14.4 96Y2 21.4IV 14.9 111.1 24.7

1993 1 26.5 137.6 30.611 31.5 169.1 37.6111 36.4 205.5 45.7IV 45.0 250.5 55.7

1994 1 36.6 287.1 63.811 41.6 328.7 73.0III 29.6 358.3 79.6IV 27.2 385.5 85.7

1995 1 20.0 405.5 90.111 16.0 421.5 93.7III 13.0 434.5 96.6IV 12.0 446.5 99.2

1996 1 3.5 450.0 100.0

Cumulative and Quarterly Disbursements

US$ million

Quarterly disbursement Cumulative disbusement50 SW

40 uve 400

11 | | |/ ~~~disburuent/30 B l dad 300

20 20D

10 100

PY91 FY92 PY93 FY94 FY95 FY96 FY97 FY98IBRD fisa year

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INDIA Annex 5.1GAS FLARING REDUCTION PROJECT a-ge I fl

Assumptions Underlying the Project Financial Analysis

Capital Costs The capital costs are based on ONGCs and the mission's esti-mates of the cost of the various project components For thepurpose of calculating the financial rate of return of the projectthese costs have been converted into their equivalent in 1991 USDollars. They include physical contingencies of 10% of the basecost of the project components, taxes and duties estimated toaverage 26% of the cost of items to be imported under the project.The cost of upgrading of the HBJ pipeline to accommodate theincreased availability of gas has not been included.

Operating Costs The operating costs are based on ONGCs experience with theoperation of sirnilar installations. The annual expenditures havebeen calculated as follows:

* Repairs and 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 wells andpipelines

Incremental Personnel Cost

Rs 6250 per staff/month for 20 staff

* Overhead

US$ 2 million

Average operating costs amount to about 2% of capital cost.

Gas Price The currently prevailing price for gas is Rs 1400 per 1000 m3 (atland fall points) and Rs 2250 per 1000 nis (along the HBJ pipeline).These prices will be revised, as soon as the Govemment decidesto adopt the gas pricing policy proposed by the Bureau of Indus-trial Cost and Prices. A decision to implement this pricing policyis a condition of the nroposed loan. Implementation of thispolicy would raise &Ls prices to Rs 1500 per 1000 m' to gasproducers, i.e. ONGC and OIL. The financial assessment of theproject is based on Rs 1500 per 1000 m'.

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INDIA Annex 52GAS FLARING REDUCTION PROJECT Page 1 of 1

Project Financial Analysis

Capiw Opering Inaremente Irem ntMl Prim TotI Net cstYear endrng Marct 31 Costs Experse Vdume Cas VouwCe Gas US$M pe n&fits BemIs

US$ milli& USS miniort MMCMD MMCM 1000 Ms US$ miuilt USS mOim

1991 85.7 0.0 0.01992 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 85.7 727.0 595.51997 39.7 22.4 7,728 85.7 662.0 622.31998 39.7 19.1 6,590 85.7 564.5 524.81999 39.7 17.4 6,003 85.7 514.2 474.52000 39.; 15.3 5,279 85.7 4522 412.52001 39.7 13.3 4589 85.7 393.1 353.42002 39.7 10.9 3,761 85.7 322.1 282.42003 39.7 9.1 3,140 85.7 268.9 22922004 39.7 7.7 2,657 85.7 227.6 187.92005 39.7 6.4 2,208 85.7 189.1 149.42006 39.7 5.9 2,036 85.7 174.4 134.72007 39.7 5.8 2,001 85.7 171.4 131.72008 39.7 5.7 1,967 85.7 168.5 128.82009 39.7 5.7 1,967 85.7 168.5 128.82010 39.7 5.9 2,036 85.7 174.4 134.7Total 1,985.3 62,825

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

Note: Capital cost excludes the upgrading of the HBJ go pipeline, but indudes additonal investmnents required to expand thecapacity of the South Bassein ps fieldIncremental volume in MMCM is based on an average offtake of 345 days

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INDIA Annex 5.3GAS 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 thecommitment 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!-LIII project)aimed at increasing oil output from the Bombay High oilfield. To recover the gas that is currently flaredas well as the additional gas that will become available as a result of the increase of oil output from theLII-LIII project, ONGC needs to expand the capacity of the infrastructure for the recovery, transport andprocessing gas in the Westem offshore region. Without these investments gas flaring would increasedramatically.

Table I Assumptions for the Economic Analysis

Year ending March 31 Do, ic International Exchange Rates 0,i Price, Fud 0i Natoml Gas,Inflation InfationPercenti Percent Rs pe US$ USS per barrel USS per ton Rs per 1000m

1990 8.8 6.3 17.5 25.4 151.1 26421991 8.3 3.4 19.4 23.8 142.3 24881992 6.6 3.4 20.8 20.3 123.1 21531993 6.5 3.4 21.8 18.3 112.2 19621994 6.5 3.4 23.0 19.1 116.6 20391995 6.2 3.4 24.1 19.8 120.4 21061996 6.2 3.4 25.1 20.6 124.8 21821997 6.1 3.4 25.9 21.5 129.7 22681998 6.0 3.4 26.6 22.5 135.2 23641999 6.0 3.4 27.3 23.5 140.7 24602000 6.0 3.4 28.0 24.4 145.6 25462001 6.0 3.4 28.0 24.3 145.0 25362002 6.0 3.4 28.0 24.0 143.4 25082003 6.0 3.4 28.0 23.8 142.3 24882004 6.0 3.4 28.0 23.5 140.7 24602005 6.0 3.4 28.0 23.3 139.6 24412006 6.0 3.4 28.0 23.3 139.6 24412007 6.0 3.4 28.0 23.3 139.6 24412008 6.0 3.4 28.0 23.3 139.6 24412009 6.0 3.4 28.0 23.3 139.6 24412010 6.0 3.4 28.0 23.3 139.6 2441

Notm. Weighted average fob pnce of petroleum exports from Ol'EC countries, 1991 US DollasFudeloil prie, cif Bombay, 1990 US DoLlars

c Conresponding inland value of natural gas replacing fuel oil 1991 Rupees per 100 ma

2. A review o; various alternatives for the recovery and transmission of gas carried out byEngineers India Ltd. (Annex 4.1) has established that the proposed investments represent the least costmeans for eliminating gas flaring and transporting gas for use on shore. Hence, the costs and benefits aredefined 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 neces-sary for increasing oil output and continue the flanng of gas. The approach is to L.rImate the incremental

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INDIA Annex 5.3GAS FLARING REDUCTION PROJECT Fgo3

Assumptions Underlyung the Project Economic Analysis

cost and benefit streams associated with the proposed project and compute the economic indicators of theproject, the net present value at the opportunity cost of capital for India (12%), and the economic internalrate of return (EIRR). The analysis period consists of th' construction time and the operating life of theprojft. Table I summarizes the main assumptions that were used in the economic analysis

Econormic Costs

3. The financial flows were converted to economic costs by (i) netting out duties and otherdom 2stic transfers; tii) expressing the import content at c.i.f. prices; and (iii) applying shiadow prices todon.estic components. A standard conversion factor of 0.8 was applied to all domestic costs.

4. The costs include the required investments for the recovery and transmission of associatedgas in the Bombay High oilfield. The increase in gas supplies will require an expansion of the currentcapacity 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 Basseinto Hazira will be used for the transport of gas from the South Bassein gas field as soon as associated gassupplies from the Bombay High gas field are exhausted. The cost of expanding the capacity of the SouthBassein gas field were included in the economic analysis of the projet.

Economic Benefits

5. Table I summarizes the assumptions that were used in the assessment of the economnicbenefits from the project. Although components of this project contribute to the objective of ONGC'slarger investment program (LII-LIll project) aimed at increasing oil production in the Bombay Highoilfield, only the volumes of gas that will be recovered and brought to markets onshore were taken intoac, sunt in the economic analysis of the project. Similarly, the cost of the various components that serveboth the increase in oil uutput and the recovery of gas were apportioned to their respective outputs. Thevolumes 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 pointof use. For the purposes of the economic project evaluation, it has been conservatively assumed that allgas replaces fuel oil, the lowest valued replacement. International prices of fuel oil were projected basedon the Bank's projections for crude oil prices, and adjusted for international transport to arrive at a cifvalue at Bombay. Gas used at landfall points and along the HBJ pipeline has been valued at the thermalequivalence of fuel oil cif Bombay.

7. The use of natural gas yields additional economic benefits in the form of reduced storageand handling costs, reduced maintenance costs as well as lower pollution. Further benefits result from theincreased 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 par-ticularly large where gas replaces coal. Although the magnitude of these savings varies from industry toindustry, 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 theIndian economy.

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NDIA Annex 5.3GAS FLARING REDUCTION PROJECT Page3of

Assumptions Underlying the Project Economic Analysis, 1991 to 2010

Table 2 Volumes of Gas and Oil Produced lInder the Project

YeandingMarch 31 Incremene gas suppliew Oia Pr Fuel Oa Gas Priwe Incr. OaHazira Uran Price 6 Suppik s'

MMCMD MMCMD USS/bbl USS/t"o Rs/l 000 m3 Mill. tons

1991 23.8 142.3 24881992 20.3 123.1 2153 0.61993 18.3 112.2 1962 C.61994 3.6 19.1 116.6 2039 2.31995 33 :9.8 120.4 2106 4.81996 21.2 3.4 20.6 124.8 2182 5.01997 19.3 3.1 21.5 129.7 2268 4.81998 16.3 2.8 22.5 1a5.2 2364 4.21999 15.0 2.4 23.5 140.7 2460 4.02000 12.8 2.5 24.4 145.6 2546 3.92001 10.5 2.8 24.3 145.0 2536 3.72002 7.9 3.0 24.0 143.4 2508 3.42003 2.9 23.8 142.3 2488 3.22004 . L.6 23.5 140.7 2460 2.82005 6.1 03 23.3 139.6 2441 2.52006 5.9 23.3 139.6 2441 2.42007 5.8 23.3 139.6 2441 2.22008 5.7 23.3 139.6 2441 2.02009 5.7 23.3 139.6 2441 1.82010 5.9 23.3 139.6 2441 1.7

Notes:Weighted average f.o.b. price of petroleum exporw front OPEC countriesFuel price, c.i.f. BombaytGa price at lardfl points in India at par with the value of imported fuel oilIncrease in oil output due to the Lll-LIll project

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

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

Gas Oil~N

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IND.A Annex 5AGAS FLARING REDUCTION PROJECr FBe 1 f1

Project Economic Analysis

Capi& 3pewing h,vrSMt, Ivwre,,tul Prix TOW kt wetCosts 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 0.01992 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 8,487 112.3 953.1 841.21997 36.9 22.4 7,728 116.7 902.2 86531998 369 19.1 S,590 121.7 801.7 764B1999 36.9 17.4 6,003 126.6 760.0 723.12000 36.9 15.3 5279 131.0 691.6 654.72001 36.9 13.3 4,5 130.5 599.0 562.12002 36.9 1Q9 3,761 129.1 485.3 448.42003 369 9.1 3,140 128.1 402.1 365.22004 36.9 7.7 2,657 126.6 3363 299.42005 36.9 6.4 2, 125.6 2773 240A2006 36.9 5.9 2,036 125.6 255.7 218.820O7 36.9 5.8 2,001 125.6 251.3 214.42008 36.9 5.7 1,967 125.6 247.0 210.12009 36.9 5.7 1,967 125.6 247.0 210.12010 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% 1,3112NPV at 20% 462.0NPV at 25% 183.6NPV at 27% 103.8NPV at 37% (98.7)

Note: Capital cost indude upgrading the HBJ 3s pitpne and addit3nal ineats required for inacing the cap.dty of the SouthBaeirn pas fied.Incemnental volume in MMCM is baed on an average offitake of 345 days

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INDIA Amiexa61GAS FLARING REDUCTION PROJECr Pifl

Project File

(Filed in the Asia Infomation Center)

The Energy Sector

Eighth Five-Year Plan, 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, Government of India, New Dehi

The Market for Gas

Report of the Committee on Pricing of Natural Gas, Department of Petroleum and Natural Gu NewDelhi, May 1990

Gas Use Policy, Department of Petroleum and Natural Gas, New Delhi, October 1990

Report of the Sub-group on Demand Projections and Refining Capacity, Working Group on Petroleum forthe Eight Plan, Planning Commission, November, 1989

The Oil and Natural Gas Commission

Eighth Five-Year Plan, 1990-1995, Report of the Sub-group on Exploration, Development and Productionof Oil and Gas (Including Gas Utilization), Planning Commission, draft, November, 1989

ONGC, Annual Report, 1989-90

Oil India Ltd. Annual Report, 1989-90

'he Project

Environnwntal and Safety !ssues in ONGC's Offshore Operations, prepared for the World mank by S.Shaw(Technica, London, United Kingdom), November 1990

Westem Offshore Gas Reserves, note prepared by ONGC, January 1991

Feasibility Report for the ICP - Heera and SHG - BPB Gas Pipelines, prepared by ONGC, January 1991

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INDIA Annex 62GAS FLARING REDUCTION PROJECr Page 1 of 2

Supervision Plan

bank Supervision Inputs Into Kev Activities

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

Bank Staff Inputs for Project Supervision

Aptroximate Actjivt Anticiated Skil Inpst hidates Requnremmts staff web

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

Management/Economics 20

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

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

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

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

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

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INDIA Annex 6.2GAS FLARING REDUCTION PROJECT Page 2 of2

Supervision Plan

Borowers Contributions tc Supervision

2. ONGC and the Government of India will be requested at negotiations to teke the followingsteps in order to facilitate supervision of the proposed project:

(a) ONGC - to appoint a i'roject Coordinator to supervise the implementation of the project;

(b) ONGC - to submit quarterly reports on the progress of project implementation. The formatand content of the report will be agreed with ONGC during negiotiations;

(c) GOI (through a monitoring committee of the Department of Petroleum and Natural Gas) - tosubmit quarterly reports which will review the status of implementation of ONGC's gasprojects in addition to projects which are scheduled 3o utilize gas. The formnat and content ofthe report will be agreed during negotiations;

(d) ONGC - to subm.t annual, unaudited financial statements, consisting of incomne and fundflow statements and balance sheet, within six months of the end of the fiscal year, i.e. bySeptember 30 each year;

(e) ONGC - to submit annual, audited financial statements within nine months of the end of thefiscal year, i.e. by December 31 each year. These accounts would include separate auditreports for the project special-account and for withdrawals against statements-of-expendi-ture.

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