World Bank Documentdocuments.worldbank.org/curated/en/488281468284988175/...The Wnrld Bank Asia - Country Department IV (India) Transport and Energy Operations Division International

Cocument of

The World BankInternational Finance Corporation

FOR OFFICIAL USE ONLY

Report No. 9499-INIFC/T-1095

STAFF APPRAISAL REPORT

INDIA

PRIVATE POWER UTILITIES (BSES) PROJECT

FOR

BOMBAY SUBURBAN ELECTRIC SUPPLY LIMITED

MAY 15, 1991

The Wnrld BankAsia - Country Department IV (India)Transport and Energy Operations Division

International Finance CorporationDepartment of Investments, Asia IIDivision 1

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

Pub

lic D

iscl

osur

e A

utho

rized

Pub

lic D

iscl

osur

e A

utho

rized

Pub

lic D

iscl

osur

e A

utho

rized

Pub

lic D

iscl

osur

e A

utho

rized

Pub

lic D

iscl

osur

e A

utho

rized

Pub

lic D

iscl

osur

e A

utho

rized

Pub

lic D

iscl

osur

e A

utho

rized

Pub

lic D

iscl

osur

e A

utho

rized

CURRENCY EQUIVALENTS(As of February 1991)

Currency Unit Rupees (Rs)Rs 1.00 Paise 100US$1.00 = Rs 19.00

Rs 1.00 - US$0.0526

MEASURES AND EQUIVALENTS

1 Meter (m) 39.37 inches (in)

1 kilo-Ampere (kA) 1,000 Amperes

1 Kilometer (km)3 1,000 meters (m) = 0.8214 miles (mi)

1 Cubic Moter (m ) _ 1.31 cubic yard (cu yd) = 35.36 cubic feet (cu ft)

1 Ton (t) 1,000 kilograms (kg) = 2,200 pounds (lbs)

1 Kilocalorie (kcal) 3.97 British Thermal Units (BTU)

1 Kilovolt (kV) = 1,000 volts (V)1 Kilovolt ampere (kVA) = 1,000 volt-amperes (VA)

1 Megawatt (MW) 1,000 kilowatts (kW) = 1 million watts1 Kilowatt-hour (kWh) 1,000 watt-hours1 Megawatt-hour (MWh) = 1,000 kilowatt-hours1 Gigawatt-hour (CWh) 1,000,000 kilowatt-hours

ABBREVIATIONS AND ACRONYMS

AEC - Ahrmedabad Electricity Company LIC - Life Insurance Corporation

BEAG - Bombay Environmental Action Group LRMC - Long Run Marginal Cost

BEST - Bombay Electric Supply and Transport LSHS - Low sulphur heavy stock

EHEL - Bharat Heavy Electricals Ltd. H?CB - Maharashtra Pollution Control Board

BOOT - Built, own, Operate and Transfer MRTP - Monopolies and Restrictive Trade

BSES - Bombay Suburban ELectric Supply Company Practices

CEA - Central Electricity Authority MSEB - Maharashtra State Electricity Board

CESC Ltd. - Formerly Calcutta Electricity Supply NEERI - National Environmental Engineering

Corporation Research Institute

CHD - Chairman Managing Director NGO - Non-Government Organization

OCL - Develcpment Ccnsultants Limited NHPC - National Hydroelectric Power Corporation

DESU - Delhi Electricity Supply Undertaking NOx - Nitrogen oxide (subscript NOx)

DOC - Department of Coal NPTC - National Power Transmission Corporation

DOEF - Department of Environment and Forests NTPC - National Thermal Power Corporation

DCP - Department of Power P-R - Project Completion Report

DTEPG - Daharu Taluka Environmental Protection PFC - Power Finance Corporation

Group REB - Regional Electricity Board

EIA - Envirormentat Impact Assessment REC - Rural Electricity Corporation

ERR - Economic Rate of Return SEB - State Electricity Board

ESP - Electrostatic Precipitator SEC - Surat Electricity Company

FAC Fuel Adjustment Charge S02 - Sulphur Dioxide (subscript SOZ)

FGD - Flue Gas Desulphurization TCE - Tata Consulting Engineers

GM - General Manager TCS - Tata Consultancy Services

GOI - Government of India TDP - Tribal D^velopment Plan

GOM - Government of Maharashtra TEC - The Tat lectric Companies

IciCt - Industrial Credit and Investment THE ACT - Electric-cy Supply Act of 1948

Corporation of India THE LICENSE - Bombay Suburban Electric License

106l - Industrial Development Bank of India TPP - Thermal Power Plant

IFCI - Industrial Finance Corporation of India tpy - tons per year

IPR - Industrial Policy Resclution UP - Uttar Pradesh

LCB - Local Ccmpetitive Bidding UTI Unit Trust of India

Guarantor's and Borrower's Financial Year: April 1 - March 31

(In this report FY.. refers to the Guarantor's and the Borrower's fiscal year,

which runs from April 1 of the previous year to March 31 of the indicated

year; for example FY92 would mean the fiscal year from April 1, 1991 to March

31, 1992).

FOR OFFICIAL USE ONLY

INDIA

PRIVATE POWER UTILITIES (BSES) PROJECT

Lo n/Investment and Proiect Summarv

Borrower: Bombay Suburban Electric Supply Limited (ESES; theCompany).

Guarantor: IBRD Loan: India, acting by its President. TheGovernment of India (GOI) would charge a guarantee feeof 2.75Z p.a. on the principal amount of the IBRD Loanwithdrawn and outstanding.

IBRD Loan: US$200 million equivalent.

Terms: Repayment over 20 years. including five years of grace,at the IBRD standard variable interest rate.

IFC Investment: A Loan: US$50 million equivalent (for IFC's ownaccount);

B Loan: Up to US$18 million equivalent (for the accountof participants).

Terms: A Loan: Fixed interest rate of 10.75Z p.a.Front-end fee 1S.Commitment fee 1 p.a. on the undisbursedbalance.Repayment in 20 semi-annual installments ofUS$2,500,000 due from September 15, 1996 throughMarch 15, 2006.

B Loan: Syndication fee: 0.50? of the amount syndicatedpayable to IFC.Administration fee: US$2,500 per participant inIFC's B Loan, payable semi-annually to IFC;however, the total Administration fee not toexceed US$15,000 annually.Other terms to be negotiated.

Overall maturity of 15 years, including five years ofgrace. The maturity of the B Loan is expected to beshorter than the maturity of the A Loan; in that event,the repayment installments of the A Loan will beadjusted so that the aggregate repayments for the A Loanand B Loan are approximately US$6,800,000 per year.

Foreign Exchangeand Interest Risks: The interest rate risk on the IBRD loan, and the foreign

exchange risk on IBRD loan and IFC investment will beborne by the Borrower.

Mortgage andSecurity: IBRD loan and IFC investment wili be secured against

first charge on all of BSES's assets, subject to certainprior charges on current assets in favor of workingcapital lenders, pari passu with other senior lenders.

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

-ii

Prolect Objectivest The Project's objectives are to provide additionalgeneration, transmission and distribution capacity tomeet increasing electricity demand in the Borbay area,maintain good service quality provided to BSES'sconsumers, support GOI's endeavors to increase privatesector participation in the supply of power, and assistBSES in its transformation from a distribution companyto an integrated power utility which operatesgeneration, transmission and distribution facilities.

Project Description: The Project comprises: a) a power plant comprising two250 MW coal-fired units located at Dahanu, including aflue gas desulphurization plant (FGD) as mandated byGOI's environmental clearancl; b) two double circuit220 kV transmission lines of about 105 km, to transmitpower from Dahanu to BSES's license area, and three220/33 kV receiving stations; and c) strengthening andextension of BSES's 33 kV and 11 kV subtransmission anddistribution system.

Estimated Cost: a/Local Foreign Total

Project Components ----------us$----------

I. Dahanu Thermal Power Plant b/ 238.8 134.1 372.9II. 220 kV Transmission Lines and Substations 23.0 23.1 46.1III. Strengthening and Extension of BSES's

Subtransmission and Distribution System 57.9 - 57.9

Total Base Costs 319.7 157.2 476.9- Physical Contingencies 22.4 8.0 30.4- Price Contingencies 12.5 14.3 26.8

Total Contingencies 34.9 22.3 57.2

Total Project Cost 354.6 179.5 534.1

Working Capital Margin andDebenture Issue Expenditures 1 6 - 12.6

Interest During Construction (IDC)- IBRD and IFC Loans - 63.2 63.2- Other 43.4 - 43.4

Total - IDC 43.4 63.2 106.6

Total Financing Required 410.6 242.7 653.3==Wu=== YD =XX=_== 0==u3-

a/ Including taxes and duties of about US$42.3 million.h/ Includes the FGD plant as mandated by GOI's environmental clearance.

On account of the low sulphur content of Indian coal and the use ofa 275 meter stack, the project would meet GOI, GOM and World Bankambient air quality standards without arr FGD plant. Nevertheless,GOI required the installation of an FGD plant as part of itsenvironmental clearance but is now reviewing whether to amend thesaid clearance. If GOI decides to amend the clearance to remove theFGD requirement, IBRD and IFC would not have any objection.

-iii-

Financing Plan:(US$ million)

Internal Accruals 65.6Special Reserves 47.5Fully Convertible Debenturess

- First Issue 47.5- Second Issue 69.6

Long Term Loans:- Indian Financial Institutions 155.1- IBRD 200.0- IFC Investment (A Loan) 50.0- IFC Syndication 18.0

Total 653.3

Estimated Disbursements:

IBRD/IFC Fiscal Year FY92 FY93 FY94 FY95 FY96 FY97-(------- (US million) -------------------

IBRD Loan:

Annual 46.5 38.0 68.2 22.4 22.4 2.5Cumulative 46.5 84.5 152.7 175.1 197.5 200.0

IFC Investment:

Annual 17.2 19.2 19.3 6.9 5.4 -Cumulative 17.2 36.4 55.7 62.6 68.0 -

Rates of Return: Economic : 222 (The proposed project);25? (1990-2000 time-slice of the Western Region

Interconnected Development Program).

Financial: 15? (The proposed project).

Benefits: (a) Technical: The project would increase generating andtransmission capacity in the Bombay area and would help tomaintain BSES's good service quality. BSES's losses will bedecreased following the strengthening and extension of thedistribution network.

(b) Institutional: Bank Group's participation would encouragegreater private investment in the development of the powersector in India by mobilizing private savings for thesector.

Risks: (a) Technical: The physical project components, which are basedon conventional technology, do not represent unusualtechnical risks. The Bank Group is satisfied that allnecessary measures to mitigate the environmental and socialeffects of the project will be implemented.

-iv-

Environmental groups sought at. injunction to stop theproject on the grounds that it posed undue ecological risks.This generated risks of cost overruns and loss in revenue.However, following recent rejection of the injunctionrequest by the Supreme Court of India, it is unlikely thatthe case would be reopened. Possible institutional risksinclude the inability .f BSES to effectively manage theimplementation and operation of the project. To minimizethis risk, BSES has engaged competent consultants to managethe project. Furthermore, BSES's reorganization andstrengthening efforts will be closely monitored.

(b) Financial: BSES has been gran:ed permission to accumulatecertain special reserves required in accordance with thefinancing plan of the project and assurances were obtainedfron. GOI that it would ensure that GOM would permit BSES tocollect special reserves during the operations stage aswell, including special reserves for repayment of debt.With the approval of these special reserves, the project isfinancially and economically viable even without GOI's newpolicies on private investments in the power sector beingenacted. The promulgation of the new incentives wouldgenerally enhance BSES's financial position. Increases inBSES's fuel costs or in Tata Electric Companies' (TEC)tariffs would be passed on to BSES's consumers as allowedunder the Electricity (Supply) Act.

INDIA

PRIVATE POWER UTILITIES (BSES) PROJECT

Table of Contents

Page No.

I. SECTORAL CONTEXT ................ ........ . 1

Overview . . . . . . . . . . . . . . . . . . . . . . . 1Organization of the Power Sector.. . . . . .* . . 3

Private Utilities .. . . . . . . . .......... .. 4GOI Strategy in the Power Sector . . . . .. . . 6Bank G-oup Strategy in the Power Sector . . . . . . . . . . . . . . 7Bank Group Participation.. . . . .* . . . 8

II. THE BORROWER.. . . . . . . . . . . . . . 9

Introduction ...................... .. . ... 9BSES's Activities . . . . . . . . . . . . ... . . 10Ownership.. . . . 11

Organization and Management .11Maintenance. .. i... 12Accounts and Audit 12Billing and Collections . . . . . . . . . . . . .. 2Insurance . . . . . . .. . 13

Income Tax .. . . . . . . . . . . 13

Dependence on TEC and MSEB . .......... .. .. . . .. 13

This report is based on the findings of a joint IBRD and IFC appraisalmission to India in February 1991. Mission members from IBRD were Messrs. A.

Ceyhan (Senior Power Engineer), C.K. Teng (Financial Analyst) and Mrs. M.

Manzo (Energy Specialist); and, from IFC Messrs. D. Lilaoonwala (InvestmentOfficer) and H. Riddle (Chief, Environmental Unit). Mr. S. Guggenheim(Anthropologist) contributed to the report.

The report has been reviewed by Messrs. J. Besant-Jones (Principal Energy

Economist), E.W. Moore (Consultant) and T. Storm van Leeuwen (Senior FinancialAnalyst) of IBRD, and R. Gale (Principal Regional Economist) and D. Fenton(Principal Engineer) of IFC.

The report was endorsed by Messrs. H. Vergin (Director, Asia, Country

Department IV - India) and J.F. Bauer (Chief, Transport and Energy OperationsDivision, Asia, Country Department IV - India) for IBRD, and Messrs. J. Kassum

(Director, Department of Investr.ants - Asia II) and A. Tharmaratnam(Divisional Manager, Division I, Department of Ini'estments - Asia II) for IFC.

-i i.- ~ ~ ~ ~ ~ t8e

III. THE PROJECT.. . . ........ . . . 14

Project Objectives .. .......... . . . .. . ... . 14Project Description ....... .. ...... . . . . . . . . 14Cost Estimates . . . . . . . . . . . . . . . . . . * . . . 15Basis for the Estimates . . . . . . . . . 15Project Financing ........ ..... . . . . .. . .... 16Project Implementation Schedule ..... . . . . . . . . .. . 17Status of Engineering and Project Management . . . . . . . . . . 18Procurement . . . . . . . ....... . . . . . . 19Disbursements from the IBRD Loan . . . . . . . . . . . . . . . . 20Security Arrangements ....... . . . . .. . . . . . . . . . 20Fuel Supply for the Dahanu Thermal Power Plant . . . . . . . . . 21Water Supply .... . . . . .. . .. . 22Land Acquisition .... . . . . . . ..... ........ . 22Environmental and Social Aspects . . . . . .. . . .. . .. . 23Project Benefits .... . . . . . . . . . .. .. .... . . 29Project Risks . . . ... . . 30Project Monitoring and Supervision . . . . . . . . . . . . . . . 30

IV. FINANCIAL ANALYSIS ..... ........... . 30

Special Reserves and Approved Institutions Status . . . . . . . . 30Past and Projected Financial Performance . . . . . . . . . . . . 31Financial Internal Rate of Return.. . . . . . . . 32Sensitivity Analyses.. . . . . . . . . . . . 33

V. ECONOMIC ANALYSIS.. . . . . . . . . . . . .. 33

Western Region Market Profile... 34BSES Market Base ...... . . 35Least-Cost Analysis . . 35Program Analysis . . . . . . . . . . . . . . . . . . . . . . . . 36Project Economics ...... . . . 37

VI. AGREEMENTS AND RECOMMENDATION. . . . . . . . . . . . . . . . . . 38

Agreements Reached between IBRD, and GOI and BSES . . . . . . . 38Agreements Reached between IFC and BSES . . . . . . . . . . . . . 39Recommendation . . . . . . . . . . . . . . . . . . . . . . . . . 39

-ili-

ANNEXES

1.1 All-India: Electricity Supply and Demand and Energy Consumptionby Main Consumer Category

1.2 Comparison of Average Tariffs1.3 Previous Loans and Credits to Indian Power Sector

2.1 BSES Electricity Sales and Consumption Pattern2.2 BSES Corporate Organization Structure2.3 BSES Project Management Structure2.4 BSES Power Purchase from TEC

3.1 Project Description3.2 Project Cost Summary3.3 Project Implementation Schedule3.4 Engineering and Management Consultants Employed by BSES3.5 Procurement Arrangements3.6 Procurement Schedule3.7 Schedule of Disbursements for IBRD Loan and IFC Investment3.8 Statement of BSES's Secured Borrowings3.9 Main Characteristics of the lb Valley Coal3.10 Executive Summary of the Environmental Assessment Document3.11 Environmental Monitoring Plan and Ongoing Additional Baseline Studies

4.1 BSES's Income Statements4.2 BSES's Balance Sheets4.3 BSES's Statements of Sources and Uses of Funds4.4 Estimation of Financial Internal Rate of Return4.5 Sensitivity Tests4.6 Main Assumptions for Financial Projections

5.1 Western Region Power and Energy Demand5.2 Western Region Interconnected Power System5.3 Estimation of Consumer Surplus5.4 Western Region Expansion Program -- Summary of Assumptions5.5 Results of Sensitivity Analysis of Western Region Program5.6 Energy Dispatch from Dahanu Thermal Pcwer Plant to the Western Grid5.7 Estimation of the Project's Economic Internal Rate of Return --

Summary of Assumptions5.8 Results of Sensitivity Analysis for the Proposed Project5.9 Evaluation of Combinied Cycle Alternative

6.1 Documents in Project File

MAP

No. IBRD 22938

INDIA

PRIVATE POWER UTILITIES (LSES) PROJECT

I. SECTORAL CONTEXT

Overview

1.01 The principal challenge facing the Govermment of India (GOI) inthe power sector for the 19909 is to improve the balance in sector developmentbetween efficiency improvement and supply expansion. This will require GOI toensure that the sector's institutional development, including financialreforms, keeps pace with the physical expansion of power supplies. Even withmore efficient utilization of the installed capacity, electricity demand isproiected to increase by 7 to 92 a year through 2000 and to continue to besupply constrained. To meet a higher proportion of demand and improve thequality of supply, GOI plans to install an additional 80,000 MW of capacity bythe year 2000 at a cost of about US$150 billion. This is equivalent tobetween 252 and 302 of expected allocations under the Eighth and Ninth Plans.These enormous investment requirements would place great pressure on GOI'sfinances and pose many managerial and technical challenges for GOI and theState utilities. During the finalization of the Eighth Plan, these estimatesare likely to be reduced due to the acute shortage of public funds.Nonetheless, the investments still represent a sizeable expansion. To satisfythis level of investment GOI recognizes that it must harness more resourcesand managerial skills from the private sector.

1.02 At present, India's power systems have an installed capacity ofover 62,000 MW (Annex 1.1). This makes India's system comparable to those ofFrance, the United Kingdom, and all the power systems in Sub-Saharan Africacombined excluding the Republic of South Africa. The per capita consumptionof electricity in India (about 270 kWh per year) is one of the lowest in theworld. In FY90, India's systems generated 245,000 GWh -- about 70% from coalstations, 25% from hydro stations, and 5Z from gas, oil and nuclear stations.Public supply has expanded quickly: in FY81 installed capacity was only 30,000MW and generation was 104,000 GWh. Even so, India faces a shortage of peakingcapacity of about 27Z, and approximately 1OX of total energy demand is leftunserved.

1.03 The quality of electricity supplies also remains unsatisfactory.Interruptions and reductions in supply and voltage are common. The poorquality and unreliability of public supplies cause consumers to purchasecostly back-up generating capacity which uses scarce liquid fuels.Furthermore, technical and commercial losses are about 21% of net generation.Approximately 75Z of total supplies are provided by the State ElectricityBoards (SEBs) and 20% are provided by GOI-owned utilities -- principally theNational Thermal Power Corporation (NTPC) and the National Hydro PowerCorporation (NHPC). Private utilities, which are among the largest and mostdynamic utilities in developing countries, provide less than 5X of publicsupplies in India. They have a combined capacity of some 2,500 MW and arepresently undertaking projects that will soon add 1,200 MW to capacity, on topof the 1,000 MW commissioned since 1986. Private captive generation, whichdoes not enter into the above statistics, is extensive, particularly inindustry. It is estimated to be about 15% of public supplies.

2

1.04 In parallel with expanding supply, the sector has made someencouraging efficiency gains. For example, plant load factor has increasedfrom 442 in FY81 to 552 in FY90. This means tha' every 1 kW of capacity nowprovides 1,031 kWh (272) more electricity per year than in FY81. In addition,the rate of coal consumption by power stations has been cut by about 1OZ sinceFY81. It now requires 720 tons of coal to generate 1 GWh, compared with 802tons in FY81. This saves aDnroximately 13 million tons of coal annually(about 8z of the sector's total consumption) and Is worth about US$300million/year. These improvements reflect a strengthening of plant ma....-nanceand operations and are commendable in view of the deteriorating quality ofcoal the sector is receiving. A significant institutional gain is the one-third reduction in the ratio of employees to consumers at the power utilities.This ratio has declined from 29 employees per 1,600 consumers in FY81 to 19employees at present. Many of the efficiency and institutional improvementsmay be attributed to the rapidlv expanding shares of NTPC and the privateutilities in India's power system since FY83. These utilities have a muchbetter performance than the SEBs.

1.05 Retail tariffs have increased slightly since FY821 in constantprice terms. They also increased slightly as a proportion of long runmarginal costs (LRMC) from about 50% to less than 60% of LRMC. Increases inreal costs (particularly for fuel and wages) have largely neutralized theincreases in efficiency and real tariffs. In the meantime, tariffdifferentials among consumer groups have widened. Industrial consumers havetaken the brunt of the increases over the last ten years and their tariffs arenow close to, or in cases even above, LRMC in most states. The rise in selfsupply of power needs by industries is attributed to this trend as well as topoor service quality. Agricultural tariffs, on the other hand, actually havefallen in absolute terms and now cover less than 102 of their supply rosts.The large financial burden agriculture already imposes on the power bystem isincreasing. Partly as a result of this subsidization, agriculture's share intotal consumption has grown from about 15% in FY81 to 23X in FY90, and thisrise is expected to continue throughout the 1990s (Annex 1.1). A similarsituation applies to the case of residential uses of electricity.

1.06 With the power sector doubling in size every eight years or so,the combined financial losses of the SEBs have been steadily increasing, eventhough in real terms financial losses per unit of electricity sold have beenchecked or even have fallen somewhat. These losses have increased from US$1.3billion in FY81 to US$1.8 billion in FY90. Losses of this magnitudematerially affect public finances and, because of late payments to suppliers,create major financial problems for NTPC, NHPC, Indian Railways, Coal Inudia,and Bharat Heavy Electricals Limited (BHEL -- the largest local manufacturerof electrical equipment). As a consequence, GOI has recently been forced toearmark central transfer assistance to these entities, funds which otherwisewould have been allocated to the budgets of the delinquent states. Thesituation in a few states, including Maharashtra is an exception. TheGovernment of Maharashtra (GOM) has allowed the Maharashtra State ElectricityBoard (MSEB) and the private utilities operating in the state to functionunder a satisfactory regulatory and financial environment. As a result, MSEB

1 Using FY82 figures, from 40 Paise/kWh in FY82 to 47 Paise/kWh inFY90.

3

has become one of the most efficient and financially strongest of the SEBs.It has done this partly bv setting a remunerative level of tariffs.

1.07 Notwithstanding the efficiency gains secured by the SEBs in reLentyears, there is urgent need for major improvement. Key constraints remain,for example, in the lack of financial autonomy for publicly owned utilities,and in the poor financial discipline of the utilities. Physically, theseconstraints cause India's power systevs to provide less power and power of apoorer quality, at higher cost, than they otherwise would be able to provide.The economic costs of shortages and poor quality supply are exacerbated byinefficient end-use of power. The latter result from P lack of commercialincentives in many markets and subsidized power prices. GOI is aware of theseproblems and has taken steps to alleviate them.

1.08 In response to the serious difficulties of the SEBs, GOI hasrelied increasingly on the central generating companies and private utilitiesfor the expansion of supply. Since commissioning its first generating unit InFY83, NTPC has raised its capacity tenfold -- to about 10,000 MW. GOIrecently set up the Power Finance Corporation (PFC) to finance those SEBs thatare willing to undertake, with their state governments, needed financial andinstitutional reforms. GOI has caused the relatively more efficient centralutilities (particularly NTPC) to improve cost recovery and ensure thatpriority projects are implemented on schedule. CMI has recently establishedthe National Power Transmission Corporation (NPTC) to rationalize theconstruction and operation of India's bulk transmicsion systems. GOI alsoplans to establish Regional Tariff Advisory Committees. These committees willprovide advice to state governments, SEBs and central generating utilities onthe level and structure of tariffs needed to assure the financial viability ofall agencies in the sector. GOI also plans to stimulate private sectorinvolvement in power supply, in order to achieve the desired expansion ofcapacity, recognizing resource constraints and the continuing need to increaseefficiency. To rap private sector potential for additional resourcemobilization, in :;d-1990 GOI formulated a policy package containingincentives for potential local and foreign investors (para. 1.15). Thepackage foresees amendments to the existing legislation which would removemany of the financial and .egulatory disincentives to private investment inthe sector. GOI also is reviewing its fuel use policy for the sector. Forexample, 8,000 MW of gas-fired plant is to be added under the Eighth Plan.

Organization of the Power Sector

1.09 Responsibility for electricity supply is shared between GOI andthe States. Through the Department of Power (DOP) of the Ministry of Energy,GOI controls the Central Electricity Authority (CEA), NTPC, NHPC, the RuralElectricity Corporation (REC), and, through CEA, the Regional ElectricityBoards (REBs). DOP also controls PFC and the newly-created National PowerTransmission Corporation (NPTC). CEA's tasks are to develop a national powerpolicy and coordinate sector development. Its effectiveness, however, isseverely limited by shortages of financial and human resources. NTPC and NHPCare bulk supply utilities which sell power to the SEBs. NTPC provides about13? of India's total power supplies, and has a track record of efficiency andfinancial strength. NHPC has yet to enjoy the same success and is developingrelatively slowly. REC plans and finances most investments in ruralelectrification. The REBs coordinate dispatch and interstate power exchangesin each of the country's five regional power systems. The effectiveness of

4

the REBs presently is limited by their lack of statutory authority and byweaknesses in the structure of bulk power tariffs. This structure fails toprovide incentives for rational interchanges of power within and among theregions. PFC mobilizes additional resources for the SEBs and pursuesinstitutional strengthening of its borrowers through conditionality linked tofinancing. NPTC will coordinate the development and operation of transmissionsystems. Initially these will be systems associated with NTPC's and NHPC'spower stations; later, systems owned by the SEBs also will be covered.

1.10 The States control the SEBs, which generate about 752 ofelectricity supplies and provide most of the distribution to final consumers.Although they are supposed to be autonomous, in practice the SEBs must obtainstate approval for decisions on investments, tariffs, borrowings, salary andpersonnel policies. The SEBs are grouped into five regional interconnectedsystems. The activities coordinated regionally through the REBs includegeneration schedules, overhaul and maintenance programs, power transfers, andconcomitant tariffs. The SEBs also license India's private power utilitiesand licensed local authorities.

Private Utilities

1.1i At Independence, privpte utilities and licensed local authoritiestogether provided about 80? of public electricity supply. The Electricity(Supply) Act of 1948 (the Act) created the SEBs and entrusted the Boards withprimary responsibility for public powet supply. The Act also made the SEBsresponsible for regulating private utilities. The Industrial PolicyResolution (IPR) of 1956 subsequently defined aspects of generation anddistribution which were to be the exclusive responsibility of the states. Allbut the few remaining licensees consequently were taken over when theirlicenses expired. No new licenses have been granted since 1956. However, theIPR did not rule out expansion of the remaining licensees, or the possibilityof joint ventures with the private sector when these could be shown to be inthe national interest. Only five private utilities and one local authorityremain; these provide about 5? of public supply. The private utilities are:Bombay Suburban Electric Supply Limited (BSES), Tata Electric Companies (TEC),Ahmedabad Electricity Company (AEC), Surat Electric Company (SEC), and CESCLtd. (formerly Calcutta Electric Supply Corporation).

1.12 BSES is a distribution company serving the northern suburbs ofBombay. The Bombay Electric Supply and Transport Ltd. (BEST), the onlyremaining local authority, is a municipal corporation which supplies thesouthern areas of Bombay. TEC, AEC and CESC generate at least some of thepowez they distribute. SEC is in charge of distribution in the town of Suratin the State of Gujarat. At present, BSES and BEST purchase their power fromTEC. However, with the proposed project BSES will be generating some of itspower from its 500-MW thermal power station by 1995. Unlike the SEBs, theremaining private utilities have been alio4ed by their respective stategovernments to operate autonomously and in a technically and financiallyviable manner. They have not suffered from the institutional and financialproblems of the GOI-owned central entities because the powar they generate islargely fed Into their own distribution networks which _upply urbanresidential and industrial consumers.

1.13 The Act allows private power utilities and licensed localauthorities to pass on all of their costs to consumers through tariffs. These

5

costs include depreciation (at 3.6Z p.a.) and interest plus special reservesas allowed by the State Government and plus profit equal to a 12Z return ontheir remunerable capital base. Special reserves, like depreciation, arecharged on tariffs, thus increasing revenues. However, unlike cash costs,the special reserves are not paid out. The capital base comprises sharecapital and free reserves, but excludes the special reserves. The rate ofreturn is currently set at 12? p.a. If a utility makes higher profits, it canretain only 20? of the excess. The private utilities maintain that the 12Zp.a. rate of return is inadequate. Their cost of borrowing is now 15? p.a.for long-term loans and 172 p.a. for working capital. In order to compensatefor the lower return on capital base, GOI agreed to ensure that GOM willpermit BSES to create special reserves through its tariffs (para. 4.01).

1.14 Tariff adjustments by private utilities are permitted annually anddo not require state approval. Only 60 days notice by the licensee isrequired. The tariffs comprise a demand charge, a fixed component designed torecover the utility's fixed costs, and an energy charge for actualconsumption, reflecting the utility'- variable cost of generation. The lattercomprises a basic energy charge and _. fuel adjustment charge (FAC), reflectingthe increases in the cost of fuel between two successive tariff revisions. Indeciding on the amount and timing of their increases, the utilities also takeinto account economic and political factors (for example, the state of theeconomy in their area and the attitude of consumers and of the authorities).Petitions by consumers requesting stays of the increases are common, as commonas the rejection of these petitions by the courts. BSES and BEST normallyfollow MSEB and TEC in raising tariffs (Annex 1.2).

1.15 Prospective Policy Adjustments. The serious institutional andfinancial problems of the SEBs and their inability to expand in line withdemanc have prompted GOI to reassess the environment in which the privatesectcr invests in public power supply. Several reforms were articulated inthe new policies formulated by GOI in mid-1990. These reforms included: (i)an increase from 122 to 15? in the maximum allowable rate of return on thecapital base for new investments; (ii) an increase in the allowed debt:equityratio to 4:1; (iii) capitalization of the interest during construction atactual cost for the initial project as well as subsequent expansions; (iv)extension of the initial licensing period .rom 20 to 30 years and subsequentextensions for 20 years on each occasion; and (v) exemption from the clearancerequired under the Monopolies and Restrictive Trade Practices (MRTP) Act.

1.16 GOI is still considering an increase in the depreciation allowancewhich would permit the licensees not to use special reserves to bridge the gapbetween the debt redemption requirements and resource generation throughdepreciation and retained earnings, as laid down in the Act. The Act willalso be amended to permit privately owned "generating cimpanies"2 to enterinto contractual agreements for specified periods in order to sell power tothe SEBs. The sale of power would be regulated through a two-part tariff,which would be determined in a manner so as to encourage efficient operations.Local and foreign investors would be required to provide at least 11? of thetotal project cost. The equity component would be at least 20? and the amount

2 The companies formed jointly by the private sector and GOI, NTPC,NHPC, or one or more State Governments or SEBs would also beconsidered "generating companies".

6

of financial resources to be obtained from the Indian Financial Institutionswould not be more than 40Z of the total project cost. The companies alsowould be required to operate within the interconnected systems and to abide bythe operational grid discipline to ensure optimal grid operation.

1.17 The above stipulations would serve to stimulate private sectorinterest in and mobilize additional funds for the power sector. However, itis not certain whether the SEBs would be able to pay for the energy boughtfrom the "generating companies". GOI might not be suiccessful in attractingadditional private investment in the power sector unless the SEBs improvetheir payment record, sinice the SEBs will be purchasing most of the powergenerated by the new ate power utilities. The new incentives also arelikely to be incremert :i nature and to be sponsored by the states unevenly.The more progressivct- .'f.J, such as Haharashtra, already have a privatesector presence an- encouraged the private utilities to expand byproviding the incent-1 -; irmitted within the existing framework. Maharashtraundoubtedly will take the iead. Overall, it is difficult to predict howquickly private participation might increase. GOI-IBRD/IFC dialogue on theissue is under way. For BSLS, the incentives already provided by GOM withinthe existing legal framework are adequate to meet the financing needs of theproject (para. 4.01).

1.18 The progress of reforms in the power sector has been temporarilyinterrupted by the change of administration and revisions in formulating theEighth Plan. In an interim initiative before the policy changes areannounced, GOI and several state governments have invited selected privateinvestment houses to present proposals for build, own, operate and transfer(BOOT) generation projects. These projects fall within the provisions of theIPR (para. 1.11), which allows SEBs to enter into joint ventures with theprivate sector for projects believed to be in the national interest. Newjoint ventures of this type have not been launched however since the groupsapproached are waiting for the new legislation to be enacted.

GOI Strategy in the Power Sector

1.19 The Five-Year Plan constitutes the only formal statement ofIndia's energy and power policies. Under the Eighth Plar., the roles forenergy conservation and the private sector in the supply of power are likelyto be enhanced. The principal energy objectives are likely to be: (a)developing supplies at rates which will facilitate growth in other sectors andmeet particular economic and social objectives assigned to the energy sector(for example, extending irrigation pumping and meeting the energy needs of therural poor); (b) substituting indigenous energy for imported fuels wherevereconomically feasible; and (c) promoting rational and more efficient energyuse. The objectives of the power sector are similar. The short-termobjectives are likely to focus on easing supply shortages and improvingfinancial discipline in the sertor.

1.20 Specific investment objectives under the Eighth Plan are likely toinclude: (a) accelerating the completion of ongoing projects, particularlyhydroelectric investments; (b) encouraging the construction of energyefficient and environmentally benign gas-based combined cycle plants; (c)rehabilitating existing plants; (d) improving the quality of coal suppliesthrough better coal preparation; (e) increasing investments in transmissionand distribution relative to investments in generation; and (f) continuing the

7

modest development of nuclear power. Less clearly defined are theorganizational, institutional and financial strategies needed to achieve theseinvestment objectives. Given the magnitude of the task at hand, it isessential that GOI and the state governments tackle the sector's financialproblems with renewed vigor. GOI's recent initiative in forming the PFC isexpected to begin yielding results under the Eighth Plan. In line with itsoperational policies, the PFC is entering into agreements with the SEBs underwhich the SBEs commit themselves to follow action plans to improve theiroperational efficiency and financial position as a condition for PFC lending.Although GOI is constrained in its ability to act unilaterally in the powersector, key initiatives it is likely to pursue will be to; (a) acceleratedevelopment of the relatively efficient GOI-owned utilities; and (b) promotemore extensive private sector participation in power supply.

1.21 GOI's strategy toward public and private interests in the powersector is basically sound. However, in practice the results have not beenencouraging. The public utilities require substantial efforts in order tostrengthen their institutional development, planning, financial discipline,resource mobilization, pricing, and load management.

Bank Group Strategy in the Power Sector

1.22 In recent past, IBRD followed a three-pronged btrategy in itslending operations in the power sector in India. As a means to effect sector-wide improvements, it supported agencies owned by GOI. It also supported aselected number of SEBs whose managements and state governments were committedto reforms. In addition, and in close cooperation with IFC, it providedsupport to existing private power utilitias to improve their financial andeconomic efficiency, and to encourage GOI to lower eutry barriers for newinvestors. IFC has approved loans to three of the five private utilities overthe past two years. In dealing with both public and private utilities inIndia, IBRD and IFC are also promoting more comprehensive and vigorousanalyses of environmental inputs in project design and improved implementationof project components which support the environment. Through syndications,IFC proposes to mobilize additional resources for the power sector.

1.23 IBRD's support for the central agencies has provided manyopportunities for institutional strengthening. IBRD helped NTPC to grow intoone of India's model utilities and in the process IBRD also helped to improveoperational efficiency nationwide. However, GOIPs and our efforts to developthe power sector into an efficient and commercially viable part of the economyhave fallen considerably short of the objective, mainly because of the SEB'sweak institutional and financial performance. The pervasive nature of thesector's constraints and the relative autonomy of the states limit what can beachieved through involvement exclusively with central agencies. Beginning inthe mid-1980s, IBRD emphasized direct involvement with state governments andSEBs, attempting to influence selectively the commercial orientation of theBoards. Tariffs and financial performance will continue to be key componentsof IBRD's sector strategy. However, these are also the areas in whichprogress is most difficult to achieve since the state governments at this timewould rather provide additional financial support to the SEBs than imposeunpopular tariff increases.

1.24 IBRD's close lending relationship with the SEBs has beensuccessful in the case of the stronger SEBs, such as MSEB, which has shown

8

improved efficiency, financial performance, and willingness to innovate. Itwas always recognized that projects with institutionally and financiallyweaker SEBs would carry a correspondingly higher risk, as shown by thefollowing actions which have had to be taken due to poor performance: (a) in1989, the loan to Delhi Electric Supply Undertaking (DESU) was cancelled; (b)in April 1991, disbursements under the Uttar Pradesh (UP) Power Project weresuspended; and (c) the SEBs in the States of Karnataka, Kerala and HimachalPradesh have been advised that disbursements would have to be suspended unlesstariff actions to meet the financial covenants are taken. Furthermore, inresponse to SEBs' continued poor payment records on their bulk power purchaseswhich are now seriously straining NTPC's finances, IBRD hae alerted GOI andNTPC that our continued funding to their projects would no longer be possibleunless actions to correct NTPC's finances are taken. In view of the severityof the sector's financial problems and the adverse repercussion on the fiscaldeficit, IBRD will now have to apply the legal remedies available whenever theSEBs and central entities are unable to comply with the rate of returncovenants and with their other commitments to the IBRD.

1.25 Due to the sector's institutional and financial problems, IBRD isat this time refraining from further commitments to central agencies,including proposed loans to NTPC (US$375 million) and to PFC (US$265 million)which had been fully negotiated and scheduled for FY91. Unless power tariffsare increased in real terms, bill collection is improved, and the managementof the SEBs is strengthened, lending for power projects will be substantiallyreduced and will be limited to support for: (i) viable private sectorinvestments in generation and transmission; (ii) the few better managed andfinancially stronger SEBs; and (iii) innovative, small scale developments suchas mini hydro and cogeneration schemes. In addition, IBRD intends to continueits dialogue with NTPC and may finance the most critical components of thisimportant agency's core investment program.

1.26 IBRD will also continue to pursue the following key objectives:(a) assist the Indian power sector with development of a strategy to addressin a uniform and co-ordinated way the environmental and sociological aspectsof power development (including through a proposed loan to mini-hydro andalternative energy development which are likely to receive support from theGlobal Environment Facility); and (b) support developments requiringcoordinated actions within and outside the power sector -- priority areasbeing improving coal quality and transport.

Bank Group Participation

1.27 IBRD has made 31 IBRD loans (US$6.3 billion) and 18 IDA rredits(US$2.3 billion) for power projects in India (Annex 1.3). Twenty-sevenprojects have been completed: 20 for generation; 4 for transmission; and 3 forrural electrification. Ongoing projects include nine for generation (three ofwhich are for hydro power plants); three for transmission; and seven whichinclude a mix of generation, transmission and distribution. Five of the IBRDloans have been extended to one private utility (TEC), in 1954, 1957, 1979,1984 and 1990. The implementation of Bank power projects in India hasproceeded broadly according to expectations. However, loan and creditdisbursements continue to show large outstanding balances (US$3,965.7 million,as of February 28, 1991). These are due primarily to the very longconstruction periods for generation projects compounded by frequent delays inprocurement and in foreign exchange and import license clearances by the

9

various ministries, and the increasing number of projects underimplementation. Undisbursed balances have been pushed up further by frequentcost under-runs on major equipment contracts. The latter are due to thesoftening of international markets in the mid-1980s and the rapid realdevaluation of the Rupee.

1.28 IFC has made four investments totalling US$153 million to three ofthe five priva e power utilities in India. These investments were made in AECand TEC in FY89, and in TEC and CESC in FY90. All the projects areprogressing satisfactorily.

1.29 Bank Group participation in these projects has strengthened thefinancial performance of these borrowers, by bringing in additional financingand encouraging improvements such as the extension 3f operating licenses andthe establishment of special reserves. Joint preparation of the proposedproject by IBRD and IFC underscores the commitment of the World Bank Group tothe development of private power supply in India. The association has beenfundamental in advancing the Group's dialogue with GOI on regulatory and otherconstraints to extended private sector participation in public power supply(para. 1.15).

1.30 The Project Completion Report for IBRD's most recently completedprivate utility project in India, the Third Trombay Power Project (Loan 1549-IN) executed by TEC, rates the project a success, even though there wore costincreases and implementation delays, because an unsatisfactory contractor hadto be replaced. The financial performance of the utility remainedsatisfactory throughout project implementation because GOM diligently allowedTEC to continue to collect the special reserves permitted under the Act.

II. THE BORROWER

Introduction

2.01 BSES is a corporate entity governed by the Companies Act of 1956.Its electricity distribution business is governed by the Indian ElectricityAct of 1910, and the Electricity (Supply) Act of 1948. BSES is licensed todistribute electricity in the northern suburbs of Bombay. The Bombay SuburbanElectric License, 1926 (the License), initially was granted by GOM to Messrs.Killick, Nixon and Company Limited. The License was assigned to BSES in 1930,and the management of BSES remained with Messrs. Killick, Nixon and CompanyLimited under a managing agency agreement. In 1970, the system of managingagency was statutorily abolished and majority control was transferred to theLife Insurance Corporation (LIC), General Insurance Corporation (GIC) and itssubsidiaries, and the Unit Trust of India (UTI). The management of theCompany was taken over by a professional Board of Directors comprisingrepresentatives from the LIC, GIC, UTI, GOM, and public shareholders. TheLicense was,init5ally valid for 50 years. In 1976, GOM extended the Licensefor 10 years on the condition that BSES install a 500 MW generation project inMaharashtra to meet the growing power requirements in the company's licensearea. By initiating actions to build the generation project, BSES got GOM toextend the License to 1993.

2.02 GOM has the option to revoke the License if BSES fails to complywith its terms and conditions. It is very unlikely that GOM will revoke the

10

License, given the growing requirement of power and prevailing power deficitin the state, and the emphasis on increased private participation in powersupplies. Nevertheless, GOI agreed to ensure that GOM will extend BSES'slicense at least up to August 15, 2011, the maturity of the proposed IBRDloan. This is a condition of effectiveness for the loan (para. 6.03.a).Furthermore, GOI agreed to ensure that GOM will not take any actions thatwould adversely affect BSES's operational performance or financial position,including restricting BSES's license or supply area (para. 6.01.b.i).

BSES's Activities

2.03 BSES has a solid customer base. This base has grown from about1,700 consumers in FY30 to about 1.2 million in FY90. The largest consumergroup is made up of residential users (872). It is followed by commercial(112) and industrial (2Z) users. Residen.ial users pur hase about 44Z ofenergy sold, industrial users 38%, commercial users l -, and other users 2%(Annex 2.1). BSES estimates that energy consumption in its license area isincreasing by 7Z to 8Z a year.

2.04 BSES's record in the availability and reliability of electricitysupply is good. This is primarily due to proper maintenance and upgrading ofits distribution system. BSES's physical assets for electricity supplyinclude an installed power transformer capacity of about 679 MVA. Thiscapacity serves a maximum system demand of 618 MVA. BSES also has about 1,437km of HT cables, 1,671 km of LT cables, 7 bulk supply receiving stations, andover 2,257 substations. The proposed project would help BSES to reduce itsdependence on purchased power as demand grows over time. During the firstfull year of its operation the proposed Dahanu power plant would meet 40% ofthe requirements of BSES's license area. After ten years the plant wouldprovide about 35Z of requirements.

2.05 In addition to electricity distribution, BSES has diversified intoother areas of businesb. In 1966, it entered into the field of electricalcontracting. The following year 4t entered into computer services. BSES'scontracting business encompasses the installation of power stations andauxiliary equipment, and the construction of transmission lines for the SEBs,including contracts in Saudi Arabia and Bhutan. In FY90 contracting businessaccounted for about 5.82 of BSES's revenue.

2.06 BSES's Computer Service Department has computerized its billingsto customers, inventory control, materials management, payroll, shares andfixed deposit accounting, and some aspects of project costing. With itsexperience in software development and the successful computerization of muchof its accounting functions, BSES began marketing its services to other powerutilities. To date, it has completed management information systems (MIS)work for the SEBs, private utilities, financi-l institutions and othercorporations, including an assignment in the Middle East. Receipts from thecomputer services business amounted to about 0.5Z of BSES's revenue in FY90.Since these services are not regulated by the Electricity (Supply) Act, theprofits associated with these services increase the returns to BSESshareholders.

11

Ownership

2.07 As of FY91, BSES's share capital is owned by about 9,000shareholders. Equity shares held by the Life Insurance Corporatioa (LIC)amount to 21.4Z of the total, while 19.9? is held by the General InsuranceCorporation (GIC) and its subsidiaries. Eighteen percent is held by the UnitTrust of India (UTI), a mutual fund that raises funds from the public throughsales of units and invests them in companies on a portfolio investment basis.Four percent is owned by other mutual funds, 8Z by other corporate bodies, andthe balance 28.3? by private individuals (Table 2.1). The largest individualshareholding is 7Z.

Table 2.1: BSES's Shareholders as of FY91

Percent of Shares

Life Insurance Corporation (LIC) 21.4General Insurance Corporation (GIC) and Subsidiaries 19.9Unit Trust of India (UTI) 18.1

Sub-total 59.4

Other Mutual Funds 4.1Other Corporate Bodies 7.7Nationalized Banks 0.5Individuals (About 9,000) 28.3

Total 100.0

2.08 Part of the financing for the proposed project will be raisedthrough two issues of convertible debentures totalling Rs 2,500 million. Thefirst issue of about Rs 1,000 million was made in April 1991. This comprised8,000,000 debentures with individual face value of Rs 125. These debentureswill be convertible one year later into five equity shares with individualface value of Rs 10, i.e., representing a premium of Rs 15 each. The issuewas oversubscribed by about ten times. BSES is permitted to retain Rs 150million out of the oversubscribed portion. As a result of the conversion ofthe first issue of debentures into equity shares in 1992, the number ofindividual shareholders is expected to increase to over 150,000 and theshareholdings of the insurance companies and UTI will drop from 59Z to about51Z. Further reduction in the institutional shareholding is expected to occurafter the project is completed.

Organization and Management

2.09 BSES is managed by a Board of Directors. This board includes aChairman-Managing Director (CMD), one director each from LIC, GIC, UTI andICICI, one GOM representative, two directors nominated from privateshareholders, and two functional directors. The present CMD has more than 30years of experience in the electric utility business. He is assisted by twocompetent functional directors, one for Finance and one for Technical matters.

2.10 BSES's organization has been restructured with the assistance ofmanagement consultants satisfactory to IBRD and IFC (Tata Consultancy Services- TCS). This restructuring was done to meet expected demands during projectconstruction and operation, and to respond to the company's needs for businessdiversification. The new structure largely reflects functional and business

12

responsibilities such as electricity generation and supply, electricalcontracting and computer services, and financial affairs. In addition, BSEShas created a Human Resources Development Department to oversee BSES manpowerrequirements, recruitment, training and vigilance. Two proactive divisionshave been created to handle government liaison, environment%l issues, andexternal relations: the Environmental-Corporate Public Relations Division, andthe local (at Dahanu) Public Relations Division. These divisions report tothe Director of Generation and Supply. The Bank Group has reviewed therestructured BSES and is satisfied that its organization, staffing, andmanagement system are adequate to properly oversee the implementation of theproposed project and to operate the power plant at a later stage (Annex 2.2).

2.11 To reinforce its capabilities in the design, engineering,implementation and management of the proposed project, BSES has retained anumber of consultants satisfactory to IBRD and IFC (paras. 3.09 and 3.10).These consultants will be used to staff the Project Management Division, whichwill carry out overall supervision of the project. The structure and staffingof key positions in BSES's Project Management Division is satisfactory to IBRDand IFC. It is shown in Annex 2.3.

2.12 As of FY91, BSES had about 3,800 employees, about 600 of whom wereprofessionals and 2,200 were skilled and unskilled support staff. Thestaffing is commensurate with the company's present business activities andthe work to be generated in implementing the proposed project.

Maintenance

2.13 In FY90, BSES allocated about 5O of its annual budget (Rs 254million) to maintenance. This amount is satisfactory and is associated with ahigh level of service quality. BSES uses its own work force to carry out wellestablished preventive maintenance routines on its electrical equipment andmachinery. Key installations such as receiving stations, sub-stations,transformers and switchgears are maintained regularly throughout the year.The company also provides adequate resou.ces to carry out preventivemaintenance of its distribution system, which consists mostly of undergroundcables.

Accounts and Audits

2.14 BSES has a computerized accounting system which is adequate forits utility operations and other functions. An independent internal auditingunit reporting directly to the CMD reviews the accounts mainly for compliancewith the Companies and Income Tax Acts. An external auditor completes BSES'saudit of its annual report by July 31st of each year. BSES agreed to furnishits annual financial statements audited by auditors acceptable to IBRD andIFC, within 120 days after the end of each of its financial year. This willinclude annual audits of the Special Account and Statement of Expenditures(paras. 3.14 and 6.02.a). The audited reports for FY90 are unqualified andcomply with the provisions of the regulatory acts.

Billing and Collection

2.15 BSES has a computerized billing and collection system whichefficiently serves the company's more than 1.2 million customers. Industrialconsumers are billed monthly, and residential and commercial consumers

13

bi-monthly based on meter readings. BSES assesses a 32 to 42 penalty onresidential consumers who fail to pay their bills within 15 days of receivingnotice. Industrial consumers who fail to pay their bills and the penalty aredisconnected. For residential and commercial customers, notice ofdisconnection is given following the second time the bill is not paid. If thebill is not paid within one month of notice, service is immediatelyterminated. The strict enforcement of collection policies combined withreliable service allows BSES to collect promptly from its customers. As ofFY90, the company's receivables were at the equivalent of 45 days of sales.In other words, BSES has no problem with arrears.

Insurance

2.16 BSES maintains insuran_e policies on its operating machinery andother assets on a cost replacement basis. These policies protect againstfire, natural hazards, and machinery breakdown. BSES projects underconstruction are covered under marine, storage and erection policies based ontheir estimated contract values. BSE£ also ensures that the contractorsinvolved in the construction of projects have adequate insurance coverage forthe project. IBRD and IFC will request BSES to obtain adequate insurance forthe project from a reputable and financially sound insurance company, withIBRD and IFC as loss payees. BSES also will be asked to furnish IBRD and IFCwith copies of its insurance policies pertaining to the proposed project atthe time when contracts are awarded and when each policy is renewed, includingduring the operational phase of the project.

Income Tax

2.17 The corporate income tax rate applicable to BSES is 40? plus an 8?surcharge. This amounts to an effective rate of 43.2Z. Because BSES willincur large capital costs for the proposed power project, it will not incurany income tax liability for eight years following the commissioning of theproject. Adequate provision for tax liabilities thereafter is being made.

Dependence on TEC and MSEB

2.18 BSES will continue to purchase all of its power from TEC until theproposed project is commissioned in FY96. Thereafter BSES will continue topurchase a sizable amount of power from TEC. In FY90, BSES bought about 3,270GWh of electrical energy from TEC. By FY95, it will be buying about 4,540GWh. TEC sales to BSES will fall to 2,640 GWh when the proposed projectreaches its full generating capacity in FY98, and will gradually increase asdemand in BSES's license area grows (Annex 2.4). Reduced sales to BSES afterproject commissioning should not adversely affect the operations or financialposition of TEC. In response to these reduced sales, TEC would reduce itspurchases from MSEB -- releasing MSEB to increase sales to its own retailcustomers. The expected shortage of power in the State of Maharashtra, and inBombay in particular, will ensure that the power generated by the project isfully utilized. The Dahanu power plant will be operated in synchronism withthe Western Region grid to which MSEB and TEC power plants are connected(para. 5.02). BSES will be dependent on MSEB for the power to be used tostart the Dahanu power plant at the beginning and following any incidentalshutdowns. BSES agreed to conclude agreements relating to the operation ofite plant with both MSEB and TEC, prior to the synchronization of the firstunit of the Dahanu power plant (para 6.02.b).

14

III. THE PROJECT

Project Objectives

3.01 The physical objectives of the project are:

(a) to provide additional generation, transmission anddistribution capacity to meet the increasing demand forelectricity in the Bombay area; and

(b) to maintain the high quality of service to BSES consumers.

The institutional and sectoral objectives are:

(c) to support GGI's endeavors to increase private sectorparticipation in the supply of power; and

(d) to assist in transLorming BSES from a distribution compar,y into anintegrated power utility with responsibilities for generation,transmission and distribution.

Project Description

3.02 The proposed project is part of the least-cost development programfor the Western Region Interconnected System (para. 5.02). It consists of thefollowing three elements which are described in detail in Annex 3.1:

(a) a thermal power plant comprising two 250 MW coal-fired unitslocated at Dahanu, involving steam generators, turbo-generatorsets complete with auxiliaries, a once-through circulating watersystem, coal, ash and oil handling plants, a water treatmentplant, a power station switchyard, miscellaneous electrical andmechanical equipment, environmental safeguard and monitoringequipment3, and associated civil works and consulting services;

(b) two double-circuit 220 kV transmission lines of about 105 km, totransmit power from Dahanu to BSES's license area, and three220/33 kV receiving substations; and

The project originally was approved by GOI and GOM with therequirement that a flue gas desulphurization (FGD) plant would bebuilt at plant start-up to reduce sulphur dioxide (SO2) emissions.An analysis of available data shows that the project would meetGOI, GOM and World Bank guidelines without an FGD plant (para.3.32). BSES's design includes allotment of space for rettrofittingan FGD unit if stack emissions from the plant and resultingambient air quality do not meet any of the above requirements.GOM has amended its clearance along these lines, and GOI iscarrying out its review. If GOI decides to amend its clearance tOremove the FGD requirement, IBRD and IFC will not have anyobjection.

15

(c) strengthening and extension of BSES's 33 kV and 11 kVsubtransmission and distribution system.

Cost Estimates

3.03 The estimated cost of the proposed project is summarized in Table3.1. Details are given in Annex 3.2.

Table 3.1: EstImated Project Costs/

Project Description Local Foqrotln Total Local for-ign Total-Rs MVl]Ton -US- us Iion-------

I. Dahanu Thermal Power Plant a/ 4,641 2,649 7,090 288.8 184.1 372.9

II. 220 kV Transmission Linesand Substations 436 439 875 28.0 28.1 46.1

1I1. Strengthening and Extensionof BSES*s Sub-transmissionand Distribution System 1,100 - 1,100 57.9 - 67.9

Total Base Costs b/ 6,077 2,988 9,066 819.7 167.2 476.9

- Physical Contingencies 427 162 679 22.4 8.0 80.4- Price Contingencies 1,067 729 1,798 12.6 14.8 26.8

Total Contingencies 1,494 881 2,876 84.9 22.8 67.2

Total Project Cost 7,671 8,889 11,440 854.6 179.5 654.1_= a:= s===

Working Capital Margin andDebenture Issue Expenditure 270 - 270 12.6 - 12.6

Interest During Construction- IBRD and IFC Loans - 1,358 1,868 - 68.2 68.2- Other 932 - 982 48.4 - 48.4

Total - Interest During Construction 932 1,868 2,290 48.4 68.2 So0.6

Total Financing Required S/ 8,778 5,227 14,000 410.6 242.7 658.8

- - ~~~~~~Cm= c== =

s/ Includes the flue go- desulphurization (FOD) plont (para. 8.80).k Includes taxes *nd duties of about USt42.3 million.s/ The total financing requirement Includes USt39 million for the fOD Plant.

Basis for the Estimates

3.04 The cost estimates for the civil works are based on offersreceived by BSES and on data available from other projects engineered byBSES'o consultants in India. The cost estimates for the main contract packageare based on the contract signed between the manufacturer and BSES (para.3.08). Estimates for the other power plant and transmission equipment andmaterials are based on the budgetary offers received from a number ofmanufacturers; these offers were compared with the most recent quotationsreceived by the consultants for similar projects. Estimates for thedistribution packages are based on BSES's experience. The estimated cost ofconsulting services is based on already signed contracts. Base prices wereupdated to January 1991. Based on the above, physical contingencies wereestimated at 10 for civil works and 5Z for equipment and materials. Physicalcontingencies amount to about 6.4Z of the total base cost. Price

16

contingenctes, which amount to about 192 of base cost, are based on expectedannual domestic and international inflation rates. The domestic inflationrates used for the cost estimates are as follows: 8.8% for FY91, 8.3Z forFY92, 6.62 for PY93, 6.5% for FY94 and PY95, and 6.22 for FY96. Theinternational inflation rates used are 6.3Z for FY91 and 3.4% for PY92 andthereafter.

Project Financing

3.05 The proposed IBRD loan of US$200 million would cover about 33% ofthe financing requirements for the project, net of taxes and duties. The loanwould be mainly used to finance the main contract package for the Dahanu powerplant (paras. 3.08 and 3.12). The loan would be issued directly to BSES andwould be guaranteed by GOI, which would levy a guarantee fee of 2.75% p.a. TheIFC investment of US$68 million, which would be made directly to BSES, wouldcover about 11X of financing requirements. Of the IFC portion, US$50 millionwould be lent from IFC's own resources (A Loan) and up to US$18 million wouldbe obtained through a syndication comprising participations in an IFC B Loanand/or through parallel financing from other sources arranged by IFC. Theamount of the syndication is based on BSES's requirement for an overallmaturity of 15 years balanced with the shorter maturities available fromcommercial sources. Pre-marketing inquiries by IFC indicate that at thepresent time there is a difficult market environment for syndicating fundswith commercial sources, stemming from the market's perception of thecountry's current economic and political difficulties. IFC, therefore,proposes to await a suitable marketing opportunity after the 1991 GeneralElections for formally undertaking the syndication of the US$18 million. Inthe event that IFC is unable to syndicate the full US$18 million by September30, 1991, IBRD Management will be prepared to propose to the Board ofExecutive Directors a supplementary IBRD loan covering the shortfall up toUS$18 million. The above date was determined in accordance with BSES'sprocurement schedule. The interest risk on the IBRD loar. and the foreignexchange risk on the IBRD loan and IPC investment would be borne by BSES. TheIBRD loan and IFC investment are cross effective with each other (para.6.03.b). The financing plan for the proposed project is shown in Table 3.2.

Table 3.2: Financing Plan for the Proiect

Total Expenditures(Rs million) (US$ million)

Internal Accruals 1,386 65.6Special Reserves 1,000 47.5Fully Convertible Debentures:

- First Issue 1,000 47.5- Second Issue 1,500 69.6

Long Term Loans:- Indian Financial Institutions 3,270 155.1- IBRD Loan 4,363 200.0- IFC Investment (A Loan) 1,089 50.0- IFC Syndication 392 18.0

Total 14,000 653.3

17

3.06 The financial analysis summarized in Chapter 4 shows that BSESwould be able to contribute US$65.6 million equivalent from its internalresources over the construction period of the proposed project (1990 to mid1995). In April 1991, BSES raised US$47.5 million equivalent from the publicby way of convertible debentures. A second issue of US$69.6 millionequivalent is planned for 1994. BSES agreed to complete by June 30, 1994, thesubscription of the second debenture issue, underwritten to the extent offeredto the public (para. 6.02.c). In accordance with the above financing plan,GOM has already allowed BSES special reserves for the duration of theconstruction period amounting to US$47.5 million. The Indian FinancialInstitutions4 complet?d their appraisal of the project with a view to makinga loan of US$155.1 million equivalent. This loan would cover about 33Z of thecost of the generation and transmission components.6 The loan from theIndian Financial Institutions will carry an interest rate of 14? during thefirst two years and 15X thereafter, and will be repayable in 40 quarterlyinstallments commencing on May 15, 1997. The remaining US$268.0 million wouldbe obtained from IBRD and IFC. The major shareholders of BSES have confirmedthat they will ensure that the necessary finances are raised fromshareholders, public, financial institutions or banks to cover any costoverruns.

Project Implementation Schedule

3.07 The project will be implemented over a period of five years. BSESinitiated preparation of the design manuals and bidding documents for thepower plant contracts in 1989. After a period of controversy, BSES obtainedenvironmental clearances from GOI and GCA for the construction of a 2 x 250 MWcoal-fired power plant et Dahanu, 125 km north of Bombay. Despite aninjunction issued by the Bombay High Court based on a petition byenvironmental groups (para. 3.24), BSES lost only about two months withrespect to the schedule defined in February 1990. The contract for the mainpackage was awarded on January 29, 1991 (para. 3.08). Contracts for pilingand foundations will be awarded in April 1991. Physical works except for theerection af the transmission lines will be carried out by contractors. Thetransmission lines will be built by BSES's Contracts Division, which isexperienced and competent in this field. Most of the other contracts arescheduled to be awarded in 1991 in accordance with the Implementation Schedulesummarized in Annex 3.3. Erection of the boilers will begin during the lastquarter of 1992. The first unit is scheduled to be synchronized in July 1994and to be commercially operational by January 1995. The second unit will bebrought in service in January 1995 and should be operational by July of thatyear. If still required by GOI (para. 3.30), the contract for the FGD plantwill be awarded by July 1992, in order to have it ready for operation byJanuary 1995 -- when the first unit begins commercial operation. The proposedproject will be completed by December 31, 1995 and the last payments will bemade during the first half of 1996. The implementation schedule is reasonablein view of the nature of the project and actions already taken by BSES.

The Industrial Credit and Investment Corporation of India (ICICI),the Industrial Development Bank of India (IDBI), and theIndustrial Finance Corporation of India (IFCI).

Under the proposed legislation, the limit for a loan from theIndian Financial Institutions would be 402.

18

3.08 The contract for the main package covers the supply of boilers,turbines, generators, electrostatic precipitator, power cycle piping, andcontrols and instrumentation. The contract includes complete manufacture andshop testing, packaging for shipment, coordination and integration of thesupply of equipment, and provision of engineering drawings, manuals, etc. Thecontract also includes 1,040 man-months of supervisory services for erection,testing, commissioning of the equipment, and supervision of related civil andstructural works based on designs provided by the contractor.

Status of Engineering and Project Management

3.09 With the assistance of constiltants, BSES will implement theproject. In the implementation of the power plant, Development ConsultantsLimited (DCL) of Calcutta will serve as their 'main consultants", providingdetailed engineering and procurement assistance, and NTPC will function as'review consultants' for the design manuals, bidding documents, and qualityassurance. Under a separate contract, NTPC will manage consulting servicesfor the design and engineering of the transmission lines and associatedsubstations, including related protection and communication systems. The listof the other consultants employed by BSES is given in Annex 3.4. All theconsultants are acceptable to IBRD and IFC. BSES agreed to establish andmaintain a project management structure satisfactory to IBRD and IFC (paras.3.09, 3.10 and 6.02.d).

3.10 In order to establish a single point of responsibility foradherence to the project schedule, BSES is negotiating a contract with BHEL toappoint it as project manager for the er:tire project. This contract wouldcover full-time monitoring of project supervision activities, planning andmonitoring, management of materials, co-vstruction, and commissioningactivities, quality assurance, monito.iag of inspection activities, andaudit i.ng of project results. BHEL will employ a full-time project managementgroup reporting to an experienced Project Manager. BHEL staff assigned tothis contract will be experienced in the fields of civil, mechanical, andelectrical engineering, and other disciy ines. A master schedule of criticalpath networks will monitor the progress .;A the project, including manpower andcosts, and will be continually updated aF each phase of the work is completed.BSES's own full-time managing team will co-rdinate with the BSEL team and themanufacturers and consultants. The BSES tea--l will ensure that standards ofquality are maintained, will closely monitor project costs, and will notifymanagement of any deviations from the project budget. Approval ofconstruction cost increases will Le handled by BSES. Equipment supplied bythe manufacturers will be inspected at their site of manufacturing by aseparate agency to be appointed by BSES. BSES's proposed project managementstructure is shown in Annex 2.3. These arrangements are acceptable to .BRDand IFC.

19

Procurement

3.11 The procurekment arrangements for the project are summarized inTable 3.3. More complete details arc shown in Annexes 3.5 and 3.6.

Table 3.3: Procurement Arrangements a/(US$ millions)

Project Element ICB LCB Other N.A. Total Cost

Civil Works - - 51.9 - 51.9Equipment 200.0 5.0 231.0 - 436.0

IBRD: (190.6) (4.0) - (194.6)IFC : - _ (68.0) b/ - (68.0)

Erection - - 17.9 - 17.9Supervisory Services 6.4 - - - 6.4

IBRD: (5.4) c/ - - - (5.4)Consultants' Services 3.3 3.3Administrative Expenses - - - 9.9 9.9Land - - - 8.7 8.7

---- … -----Total: 206.4 5.0 304.1 18.6 534.1

IBRD: (196.0) (4.0) - - (200.0)IFC : - - (68.0) - (68.0)

a/ Contract values include contingencies, taxes and duties (US$42.3 million).b/ IFC funds will not be used to finance the FGD plant.c/ Part of the equipment supply contract.ICB: International Competitive Bidding.LCB: Local Competitive Bidding.Other: Direct imports and locally procured items.N.A.: Not Applicable (Administrative Expenses).Note: The figures in parenthesis are the respective amounts to be financed

by the IBRD loan and the IFC investment.

3.12 The proposed IBRD loan to BSES would be mainly used to finance alarge single contract covering equipment for the power plant. Thisprocurement approach was designed to overcome BSES's inexperience inimplementing such a large project. The contract was awarded in January 1991,under international competitive bidding (ICB) procedures in accordance withIBRD's Procurement Guidelines. Advance procurement action was duly notifiedto the Executive Directors through the Monthly Operational Summary (DocumentNo. M91-118 of February 1, 1991). IBRD will provide retroactive financing ofup to US$30 million for the project, to reimburse expendltures made before theLoan AbLeement is signed. The Indian authorities and BSES were alerted toassume and manage all financial risks associated with any advance contracting,in the event the Board does not approve the project. Other equipmentcontracts would be procured under ICB procedures in accordance with IBRD'sProcurement Guidelines. Contra ts for equipment worth less than US$200,000each and with an aggregate value of US$4 million may be procured on the basisof local competitive bidding in accordance with procedures satisfactory toIBRD. Bidding documents and recommendations for the award of contracts wouldbe prepared by BSES with the assistance of consultants. Contracts financed

20

under the IBRD Loan worth US$2 million or more would be subject to priorreview by IBRD. The smaller IBRD financed contracts under ICB would besubject to selective post-award review. A domestic preference of 15Z or thecorresponding import duty, whichever iF less, would be applied in thecomparison of bids for equipment contracts. Consultants would be selected inaccordance with IBRD Guidelines on the selection of consultants.

3.13 The foreign currency requirements for direct and indirect importspertaining to the other generation and transmission packages are estimated atabout US$64 million, including US$17 million in foreign currency requirementsfor the FGD plant. With the exception of the FGD plant, funds provided by IFCwould be used to finance both direct and indirect import components. Contractsfinanced by IFC will be procured under limited international bidding. Therest of the equipment and works will be financed by BSES and procuredfollowing established private sector procedures.

Disbursements from the IBRD Loan

3.14 Disbursements from the proposed IBRD loan would be made against:(a) 100X of the foreign currency expenditures and 100Z of local expenditures(ex-factory cost if manufactured in India) for equipment; and (b) 1002 oftotal expenditures for supervisory services for erection, testing,commissioning of equipment, and for supervision of related civil andstructural works. Disbursements for equipment under contracts valued lessthan US$200,000 equivalent would be made against statements of expenditures(SOE), the documentation of which would not be sent to the Bank but would beretained by BSES for inspection by supervision missions. All otherdisbursements by BSES would be fully documented. Retroactive financing, in anaggregate amount not exceeding US$30 million and for expenditures made afterJanuary 31, 1991, will be provided for in the IBRD loan. To facilitatedisbursements, a Special Account would be established for the IBRD loan. Thisaccount would have an authorized allocation of US$13 million, equivalent to anestimated four months of disbursements (para. 2.14). Annex 3.7 shows theestimated disbursement schedule as derived from the construction programs ofthe project components. The aggregated disbursement profile for the projectis five years. This is faster than the standard profile for an IBRD loanbecause of the actions already taken by BSES (para. 3.07). Furthermore, thecomponents of the project do not have any unusual characteristics. The lastpayments are estimated to be made during the second half of 1996.Accordingly, the closing date for the IBRD loan would be December 31, 1996.

Security Arrangements

3.15 The proposed IBRD and IFC loans would be secured by first chargeon all of BSES's assets, subject to certain prior charges on current assets infavor of working capital lenders, shared pari passu with other senior lenders.Annex 3.8 shows BSES's borrowing position and the priority of existing lienson its properties as of March 31, 1989. BSES agreed to the following securityarrangements for the proposed loans (para. 6.02.e):

(a) A mortgage over all the immoveable properties of BSES;

(b) A floating charge hypothecation on all moveable assets of BSES,including the BSES's License; and

21

(c) An assignment by way of mortgage of BSES's License, includingextensions and renewals thereof.

The proposed security will be shared pari passu with BSES's existing seniorliea holders, the Indian Financial Institutions, and other senior lenders forthe proposed project. The security will be obtained in the form of anequitable mortgage with an assurance from BSES that, at the request of IBRDand/or IFC, BSES will convert such security to an English Mortgage and forthis purpose will also execute a Power of Attorney in favor of IBRD and IPC tofacilitate conversion of the mortgage. The creation of an equitable mortgageand execution of a Power of Attorney are conditions of effectiveness for theproposed IBRD loan (paras. 6.03.c and 6.03.d). Partial disbursement of theIFC loan would be permitted against hypothecation on BSES's moveable assets.

Fuel Supply for the Dahanu Thermal Power Plant

3.16 In view of the present unavailability of long-term supplies ofgas, the Dahanu power plant will be a conventional coal-fired plant. Aproposed Gas Flaring Reduction Project (tentatively planned for IBRD financingin FY92) will make substantial additional supplies available in Western India.However, all these supplies have been committed by GOI to prospectiveconsumers. In case, some of these commitments are not utilized, the Dahanupower plant would be a good candidate to use these supplies. To cover for thepossibility of availability of gas supplies in the Bombay area in the future,the boilers of the Dahanu plant are being designed to burn coal and gas. Inthis case, a pipeline to Dahanu from either the Hazira terminal in the northor the Uran terminal in the south will be constructed.

3.17 The Dahanu power plant will burn run-of-mine coal from the IbValley mines of the South Eastern Coal Fields Limited, located 1,400 km to theeast in the State of Orissa. The Department of Coal (DOC) of GOI hassanctioned the linkage of the Dahanu power plant with the Gopalpur opencastmines of the Ib Valley fields. Main characteristics of the coal are shown inAnnex 3.9. The coal would be moved to Dahanu by the railways viaBrijrajnagar-Nagpur-Jalgaon-Udhana. BSES's consultants have confirmed thistransportation to be feasible within the existing railway network. In thecase that the opencast mine and railway siding at the Gopalpur mine are not upto capacity by the time the Dahanu power plant goes into operation, DOCdecided that South Eastern Coal Fields Limited will supply coal from theLakhanpur mines of the same coal fields until the situation is remedied. GOIreaffirmed its commitment to provide adequate and timely supplies of suitablefuel for the proposed power plant (para. 6.01.a).

3.18 Consultants have carried out a study on coal deshaling andbeneficiation in the lb Valley. This study found that it was not economicallyfeasible to wash Ib Vailey coal even though the ash content of the best coal

e Within the context of existing gas allocations, a separatevariable-load combined cycle power plant has been programmed forthe Western Region grid, to make maximum use of the current highvalue of gas and in view of operational flexibility offered bythis type of plant. The Dahanu power plant, on the other hand,will be operated as a base-load plant, and would complement,rather compete with the proposed combined cycle schemes.

22

is 412 and involves the transport of a high volume of inert matter. It is notadvisable for BSES to commit itself to beneficiation of coal from the fieldslocated 1,400 km away, as this might prevent BSES from being linked to closercoal fields in the future. Low sulphur heavy stock (LSHS) fuel oil would beused for start-up, warming-up, for low load operation of the plant. This fueloil would be supplied by rail tank wagons through the Bombay-Surat railways.

Water Supply

3.19 Seawater for the plant would be taken from the Dahanu Creek andemployed in a once-through condenser system. The total seawater requirementis estimated to be about 80,000 m3lh. Warm water from the condensers would bereleased to the creek system through a 3 km channel. The intake and outfallstructures would be located in such a way as to prevent recirculation of warmwater from the outfall to the intake. The design of the cooling water system,based on computer modelling studies by the Central Water and Power ResearchStation (CWPRS) at Pune, would cnsure that the temperature of water in thecreek would not rise by more than 3 °C above the ambient water temperature atany location (para. 3.33).

3.20 Freshwater for the plant would be obtained from the Surya PrakalpReservoir, located about 31 km from the Dahanu site. The water would bedelivered through a pipeline which would be laid alongside existing publicroads. The total freshwater requirement is estimated to be about 2 millionma/year. This repreaents less than 1Z of the 285 million m8 storage capacityof the reservoir. The allotment for the project would be taken from the 21million m3/year allocated for industrial uses. In other words, the projectwould not compete for water reserved for irrigation (247 million ms/year).

Land Acquisition

3.21 BSES has acquired 816 ha of land for the project from GOM. Theproject does not involve any resettlement of displaced residents or activitiesat this location. Other characteristics of this site are given in paras. 3.26and 3.27. About 216 ha is to used for construction of the power plant and aresidential colony, and 536 ha is to be used for the ash deposit area. GOMpreviously had leased part of this area to salt pan owners. Through GOM thesalt pan owners agreed to terminate their long-term leases against suitablecompensation by BSES. The route of the two transmission lines covers acorridor about 70 m wide and 105 km long, occupying &bout 567 ha of land. Thesurvey is complete and the route would pass through or.ly about 2.8 km ofdegraded forest land. BSES is in the process in obtair.ing the environmentalclearance for this route from the Ministry of Envirr- -tt and Forests (MOEF).The route of the water pipeline from the Surya Prakai, :tservoir, which wouldrun alongside the existing roads and would not require any forest clearance.

23

Environmental and Social Aspects7

3.22 As required by GOI, BSES prepared an Environmental Assessment (EA)in 1987. Subsequent to this EA, a number of other studies were initiated.BSES now has completed and revised the EA which has been reviewed by IBRD,IFC, and IBRD/IFC consultants. Based on IBRD/IFC recommendations, BSES alsoprepared an Environmental Due Diligence Plan which it is revising regularlyAfter many exhaustive reviews, the proiect has received environmentalclearances from the MOEF of GOI, the Department of Environment of GOM, arsd theMaharashtra Pollution Control Board (MPCB).

3.23 Although the Dahanu site would not involve any resettlement ofdisplaced persons, opposition to the project surfaced over other environmentalissues. Principal objections raised include: (a) the potential disruption tothe local community from the in-migration of large numbers of workers and thepotentially uncontrollable development of industries in an area devoted mainlyto agriculture (paras. 3.27 and 3.28); (b) potential effects of air emissionsfrom the plant on local tree crops (chickoo) (para. 3.29); (c) potentialeffects of liquid effluents and the discharge of the cooling waters on theaquatic life of the Dahanu creek system (paras. 3.32-3.36); and (d)construction of power plant structures within 500 meters of the high tide line(HTL) (para. 3.37).

3.24 In October 1989, two non-government organizations (NGOs) -- theBombay Environmental Action Group (BEAG) and Dahanu Taluka EnvironmentalProtection Group (DTEPG) -- took GOI, GOM and BSES to court, seeking aninjunction to stop the project. At one stage of the court proceedings, thetwo NGOs tried to petition IBRD as a respondent, but the Bombay High Courtrejected this petition. Issues raised in the court petitions referred to theproject's impacts on water and ambient air quality, as well as localagriculture. In December 1990, the Bombay High Court rejected the petitionfollowing a thorough review and in March 1991, the Supreme Court of Indiaupheld this decision. The Supreme Court ruled that the thermal power plantshould be built in accordance with GOI's clearance order, and if there wereany changes in the order, during the process the NGOs should be given anopportunity to be heard.

3.25 Regardless of the legal questions involved, BSES has adopted aproactive position in addressing the issues raised by the NGOs. BSES hasinitiated a number of environmental studies aimed at thoroughly assessing thepotential impacts of the project and assuring that these impacts are keptwithin levels deemed acceptable by GOI, GOM, and the World Bank Group. Theproject complies with the environmental standards of GOI and GOM and with theapplicable environmental policies and guidelines of the World Bank Group.

7 Details are provided in the Environmental Assessment Document forthe Dahanu Thermal Power Station (dated May 14, 1991). Thisdocument was prepared by IBRD/IFC based on information provided byBSES and is included in the Project File (Annex 6.1). TheExecutive Summary of said document was agreed upon by GOI and IBRDin the course of negotiations, and is given in Annex 3.10.

24

3.16 Site Selection. After extensive and thorough study, the Dahanusite was selected for the following reasons. It has seawater available foronce-through cooling of the condenser. It has a secure freshwater supplywhich does not take water from agriculture. It occupies a large area ofunproductive land. It will not require any resettlement of displaced persons.The project will have a minimal socio-economic impact on the area. There isan adjacent railway to facilitate deliveries of coal. The site is highlyaccessible.

3.27 At first, BSES and its consultants (Tata Consulting Engineers),limited themselves to sites in the vicinity of Bombay and carried out adetailed study on nine alternative sites. Seven of these sites werelandlocked and two were coastal. BSES selected the Bassein alternative, butthe site was not approved by GOM because it fell within the BombayMetropolitan Area. Thus, BSES was asked in 1986 to locate the thermal powerplant at an alternative site. BSES then studied the coastal area north ofBassein and eventually selected the Dahanu site. The Dahanu site ispositioned on a large, degraded salt flat approximately four kilometers southof the town of Dahanu. Unfit for agriculture, it lies about one kilometerfrom the closest human settlement. The project is not expected to have anyadverse impacts on the area's rich agricultural or fishing industries.

3.28 Social Impact. Dahanu is a commercially active town of some100,000 people, and town services can easily absorb the influx of 300-600workers during the construction and operation phases. BSES plans to use about3,000 local laborers for unskilled activities during construction. The locallabor pool is of sufficient size to meet the expected demand without promotingextensive in-migration to the area. Nevertheless caution will be exercised toprevent permanent settlement around the plant after construction activitiesare completed. Material and equipment for construction of the plant will beshipped in by rail rather than road. The overall social impact of the projectis expected to be positive because BSES wages for unskilled labor areapproximately double the prevailing agricultural rate. Nevertheless, GOM ispreparing an incremental tribal development program (TDP) to provideadditional support to GOM's ongoing development activities in the tribalcommunities in the immediate vicinity of the plant. The program will commencein mid-1992 and will be financed by grant funds of about US$0.3 million to bechanneled through GOI and implemented by GOM's Department of TribalDevelopment. IBRD and IFC will help GOI obtain such a grant from bilateralagencies. GOI agreed to ensure that GOM will formulate and furnish to IBRDfor review by March 31, 1992, a tribal development program and implement thisprogram in a manner satisfactory to IBRD (para. 6.01.b.ii). In addition, BSESis providing about 20 scholarships a year for local tribal students to study

The second pre-appraisal mission, in November 1990, visited onceagain the Bassein site and noted that housing and light industrialdevelopments are occurring adjacent to the originally proposedsite for the power plant. In summary, Bassein has become asatellite of Bombay. In addition, Bassein is a much richermarshland in biological terms than the impoverished salt flats ofDahanu. Furthermore, the land for Bassein is no longer availablebecause of private sector purchases of land and long-termgovernment leases to salt panners. BEAG had also objected to theoriginal proposal to build the power plant at the Bassein site.

25

at the local Industrial Training Institutes to allow them to be employed inskilled positions on the project, Although Dahanu was already experiencingrapid growth and some industrialization, partly as a result of good road andrail access to Bombay, GOM will check further industrial growth in the area inline with the environmental clearance of the project.

3.29 Air Emissions. The plant complies fully with all World Bankenvironmental guidelines and the pollution control regulations of GOI and GOM.Sulphur dioxide (SO ) stack emissions for the 500 MW plant (without flue gasdesulphurization) will come to about 50 tons per day. With a 275 meter stack,this will result in average annual SO groundlevel concentrations ofapproximatelj 0.25 micrograms/mr. This compares to Bank guidelines of 100micrograms/m and a GOI limit of 30 micrograms/ma for sensitive areas (80micrograms/m3 for residential and rural areas). Particulate emissions fromthe power plant will be controlled through the use of electrostaticprecipitators (ESPs) designed to operate at 99.8Z efficiency. This willresult in ground level concentrations of particulates of 0.22 micrograms/m8.This compares to Bank guidelines of 100 micrograms/mg and a GOI limit of 100micrograms/m3 for sensitive areas (200 micrograms/mr for residential and ruralareas). According to an expert horticulturalist, the minimal reduction inambient air quality as a result of the project is unlikely to have any impacton the chickoo.

3.30 Flue Gas Desulphurization. The project was originally approved byGOI and GOM with the requirement that an FGD plant with 90? efficiency bebuilt at plant start-up to reduce sulphur dioxide (SO2) emissions. Given theenvironmental concerns expressed by the local organizations, particular carewas taken in the air quality evaluation work. After reviewing the stackemission data and ambient air quality modelling conducted by BSES, andconsidering the low sulphur content of Indian coal and the use of a 275 meterstack, IBRD and IFC believe that the project could be built and operatedwithout an FGD plant and would meet the most stringent ambient air qualityguidelines of GOI, GOM and the World Bank. Without the FGD plant, the projectcould result in a 24-hour groundlevel S02 concentration of 3.2 micrograms/m3for the worst coal quality (0.9? sulphur content), at a distance of about 4 kmeast of the plant site. For average coal quality (0.475? sulphur content),the maximum 24-hour SO concentration drops to 1.7 micrograms/m8. Annualaverage SO2 groundievef concentrations are estimated to be 0.46 micrograms/m8

for the worst quality coal and 0.25 micrograms/mr for average quality coal.These concentrations are well within the ambient air quality requirements ofthe GOI, GOM, and the World Bank Group, as shown in Table 3.4.

26

Table 3.4: Comparison of Ambient Air Quality Requirements

-S2 Groundlevel Concentration

Annual Maximum 24-hourAverage Peak-micrograms/m 3-

Government of India:- Industrial and Mixed Use Area 120- Residential and Rural Area 80- Sensitive Area 30

Government of Maharashtra: a/ 5World Bank Group: 100 500Project without FGD:

- Worst Coal 0.46 3.2- Average Coal 0.25 1.7

a/ GOM normally implements the ambient air quality standards of GOI,but for this project GOM has developed a more stringent SO2 requirement.

3.31 Comparing the expected ambient S02 concentrations with the abovelimits indicates that an FGD plant is not required. Nevertheless, GOI'senvironmental clearance requires the installation of an FGD unit to beoperational at the time of commissionirg of the thermal power plant. BSES hasrequested GOI and GOM to amend the clearances so that BSES may provide spacefor an FGD plant, monitor the ambient air quality on commencement ofoperations, and build the FGD unit which involves an additional cost of aboutUS$39 million9 only if the results show that such a plant is necessary. GOMhas amended its permit on these lines. GOI is reviewing the need for the FGDplant and is taking into account the Supreme Court's recent ruling that if theconditions of the clearance are changed, then GOI must first provide to theNGOs who have opposed the project an opportunity to be heard (para. 3.24). Inorder not to delay the generation project, IBRD and IFC have included the FGDcomponent in the project to be consistent with GOI's existing environmentalclearance. If GOI decides to amend its clearance to remove the FGDrequirement, then IBRD and IFC will not have any objection. In this case, theeconomic internal rate of return (EIRR) would be marginally higher at 26Z,instead of 25Z, and the average tariff levels would be Rs 0.03/kWh lower.During negotiations, understandings with GOI and BSES were reached that:

(a) GOI will make a final decision on the requirement of the FGD plantsoonest in order to allow BSES to have the FGD plant, if required,in operation at the start up of the Dahanu power station;

(b) in case the requirement to build the FGD plant is relaxed, GOIwill, consistent with the Supreme Court decision of March 1991,amend its environmental clearance suitably; and

(c) in case the requirement to build the FGD plant is not relaxed:

Including additional interest during construction.

27

(i) IBRD and IFC funds will not be used to finance the FGDplant;

(ii) BSES will take all the necessary actions to build the FGDplant, in order to have this plant in operation at the timeof start up of the first 250 MW unit of the Dahanu powerstation. BSES will inform the Bank and IFC of its choiceof technology and progress in implementation.

3.32 Liquid Effluents. The major liquid effluents will be water fromthe ash disposal area, blowdown from the water treatment plant and surfacerunoff (particularly from the coal storage areas). These liquid effluentswill be treated to ensure compliance with World Bank guidelines, which aremore stringent than GOI and GOM requirements. The relevant World Bankguidelines are: (a) pH: 6 to 9; (b) BOD5 50 mg/l; (c) Total Suspended Solids:60 mg/l; (d) Oil and Grease: 10 mg/l; (e) Total Heavy Metal: 5 mg/l.Compliance with these guidelines will ensure that these effluents have noadverse impact on the aquatic environment in the Dahanu creek system.

3.33 Cooling Water Discharge. The cooling water, drawn from the Dahanucreek and warmed through the condenser system where heat is transferredthrough conduction, will then be discharged back to the creek system through achannel 3 km long (para. 3.19). The cooling water will increase intemperature by about 7 0C to 8 °C within the plant (the condenser is designedfor a temperature rise of 7.2 °C) and will then cool further as it flows downthe channel prior to discharge to the estuary. The design of the dischargechannel is such that computer modelling carried out by the Central Water andPower Research Station (CWPRS) indicates that the cooling water reintroducedto the creek system will be a maximum of 5 °C higher than the ambienttemperature of the receiving creek waters, even under low tide conditions. Asa result of dilution by the creek waters, the maximum creek water temperaturerise at the discharge point would be about 3 °C. Results also show that,depending on tide conditions, heat loss coefficient, and ambient watertemperature, any increase in creek water temperature caused by the dischargeof cooling water is quickly dissipated (normally to less than 0.5 °C overambient water temperature within 1,000 m of the discharge point). Under worstcase conditions (a K value of 0.01 calories/m2/second/°C), the maximum watertemperature rise at the proposed cooling water intake structure would be0.83 °C, substantially less than the seasonal variation in water temperatureof the creek.

3.34 These results indicate that the discharge of cooling water isunlikely to create any environmental problems. In addition, from arecirculation standpoint, the proposed locations of the cooling water intakestructure and the cooling water discharge channel are acceptable. Siltationhas not been a problem historically in this creek system. However, CWPRS arecurrently constructing a physical model of the creek system to study theeffects of siltation on alternative cooling water intake structureconfiguration. This study will be completed by May, 1991.

3.35 The only risk from the thermal discharge is likely to come if arapid temperature change occurs in the tidal creeks. The design of thecooling system and associated discharge channel, in addition to dilution inthe creek will basically eliminate the risk of thermal shock as a factorinfluencing the viability of aquatic organisms utilizing the tidal creek

28

system. The aquatic species which utilize the tidal areas in the region areadapted to warm temperature. Some species may, in fact, benefit from theincreased heat input and there may be an opportunity to utilize the coolingwater discharge channel as a site for intensive aquaculture production.However, to ensure that the injection of water at a temperature of 5 °C abovethe creek ambient water temperature, does not adversely affect the creek'saquatic -ystem, BSES has appointed consultants (National EnvironmentalEngineering Research Institute at Nagpur -- NEERI) to carry out a biologicalstudy of the creek system. The study which began in March 1991, would becompleted in September 1992. The terms of reference for the study areincluded in the Project File (Annex 6.1). An understanding with BSES wasreached that in case the results show the presence of aqu,tic speciessensitive to a difference of temperature of 5 °C and thus the need to furtherdecrease the temperature of the cooling water discharged to the creek system,BSES will implement all precautionary measures to reduce the difference oftemiperature between the discharge water temperature and ambient creek watertemperature. The cost of these measures is small when compared to totalproject costs.

3.36 World Bank guidelines state that effluent temperatures should notbe more than 3 °C higher than that of the receiving waters. Where thereceiving water temperatures are at 28 CC or less, the effluent temperaturemay be a maximum of 5 0C above that of the receiving waters. The temperaturesof the waters of Dahanu creek change from 25 0C during the monsoon season(June to September) to 35 0C during the dry season (October to May). In itsenvironmental clearance GOI required that the temperature of the water comingout of the condenser should not exceed 5 0C at the point of discharge. Basedon the above and BSES's assurances, IBRD and IFC are satisfied that BSES willcomply with the World Bank guidelines and GOI's requirements.

3.37 Construction of Structures within 500 Meters of the High Tide Line(HTL). In providing environmental clearance, GOI noted that the power plantstructures should not be built within 500 meters of the high tide line. Therehave been differences between the NGOs and project as well as stateauthorities on the precise definition of the high tide line. Some years agoGOM built extensive dykes or bunds in the area, which protect the site fromtidal flows. The main thermal power plant has been designed so that it is atleast 500 meters on all sides from these dykes. However, certain minorstructures -- i.e. water pump house -- will be located within the 500 meterarea because it would be uneconomic to build them elsewhere. These exceptionswere taken into account by the Bombay High Court and the Supreme Court.

3.38 Environmental Management Program. BSES has developed acomprehensive environmental management program to prevent any harmful effectson the environment from the plant. The program is based on state-of-the-arttechnologies for controlling stack emissions and for treating liquideffluents. Extensive monitoring programs will ensure that necessary pollutioncontrol systems are operated efficiently, with regular maintenance. Themonitoring program involves continuous monitoring of stack emissions and thechemical composition of liquid effluents. In addition to continuous andefficient monitoring, sixteen stations will be installed by June 1992 tomonitor a variety of environmental parameters. These stations will include:one meteorological station; five ambient air quality me&suring stations (threestationary and two mobile); and ten ambient water quality measuring stations

29

(six around the ash disposal lagoons, three further downstream in Dahanu creekand one further upstream in the Savta creek),

3.39 BSES has initiated an extensive greenbelt program. A treeplanting program for the project's large buffer zone already has commenced.This program includes a 5 acre mangrove development component for the degradedarea flanking the estuary. BSES has appointed the Salim Ali School of Ecologyof Pondicherry University as consultants for environment-related issues,especially those concerning agricultural impacts and reclamation of the ashdisposal lagoons. Baseline studies on surface and groundwater quality, airquality, vegetation and agriculture have been completed. Baseline studies forthe aquatic resources are under way. The environmental monitoring plan andongoing additional baseline studies are summarized in Annex 3.11.

3.40 Audit of BSES's Environmental Monitoring. ESES will submit itsmonitoring data to the MPCB monthly. MPCB, under GOM's supervision, willprepare semi-annual audit reports written in non-technical language. Thesereports will evaluate the monitoring information with respect to requirementsand their compliance with legal norms, and will recommend any needed changesto the BSES monitor'ng program. GOM will make these reports publiclyavailable, and will promptly send them to community organizations in Dahanuand to the Bank Group. The project thus builds in an early warning system forpollution control failures which is accessible to all concerned parties. Thefirst audit report will be prepared by MPCB, based on BSES monitoring datacollected from January 1, 1991 to June 30, 1991. GOI agreed to ensure thatGOM, through MPCB, will follow the above procedure (para. 6.01.b.iii).

3.41 Environmental Impact at the Ib Valley Coal Mines. The Dahanupower plant will, have an average load factor of 702 and will generate 3,000GWh per year at full capacity. At this level of production, the plant willrequire about ̂ million tons per annum (tpa) of coal. The Ib Valley coalfields are projected to be producing about 9 million tpa of coal in FY96. AWorld Bank mission has visited the site, examined the situation against therequirements for this project, and concluded that this project will result inminimal incremental environmental and socio-economic impacts.

Project Benefits

3.42 The primary benefit of the project consists of the additionalelectricity demand to be met by commissioning additional generating capacity.In the context of the Western Regional grid requirements, this will ease theforecast gap in power supply and help support the expanding economicactivities in the region. BSES's losses will be decreased following thestrengthening and extension of the distribution network. The project will alsoenable BSES to maintain the relatively high level of quality of its service,despite growing demand, thus providing a positive demonstration effect for thesector. Likewise, the training and management of plant personnel under afinancially competitive environment will help demonstrate the value ofpursuing efficiency in power plant operation. The Bank Group's participationwill also encourage a greater private sector role in the development of thepower sector in India by mobilizing private savings to the sector. This inturn, will reduce the reliance on GOI and state budgetary support and in thelonger term increase the sector's capabtlity to contribute to the national andstate treasury.

30

Project Risks

3.43 The physical project components, which are based on conventionaltechnology, do not present unusual technical risks. The main contract packagehas been awarded, and bid specifications for the remaining packages have beenprepared. Contracts will include commonly purchased power plant, transmissionand distribution equipment, and erection services would be routine in nature.As a result, risks of having cost overruns are estimated to be small. TheBank Group is setisfied that all necessary measures to mitigate theenvironmental and social effects of the project will be implemented.Environmental groups s ught an injunction to stop the project on the groundsthat it posed undue ecological risks. This generated risks of cost overrunsand loss in revenue. However, following recent rejection of the injunctionrequest by the Supreme Court, it is unlikely that the case would be reopened.Possible institutional risks include the inability of BSES to manageeffectively the implementation and operation of the project. To minimize thisrisk, BSES has engaged competent consultants. Furthermore, BSES'sreorganization and strengthening efforts would be closely monitored.

3.44 BSES has been granted the special reserves required in accordancewith the financing plan of the project and assurances have been obtained fromGOI and GOM for the operations stage (para. 4.01). Given the approval ofthese special reserves, the project is financially and economically viableeven without GOI's new policies on pr_vate investments in the power sectorbeing enacted. The promulgation of the new incentives would generally enhanceBSES's financial position. Increases in BSES's fuel costs or in TEC's tariffswould be passed on to BSES's consumers as allowed under the Electricity(Supply) Act.

Project Monitoring and Supervision

3.45 BSES agreed to furnish quarterly reports on the project beginningwith the quarter in which the loans are signed. These reports will cover thework of consultants, physical progress, results of environmental monitoring,costs, disbursements and administrative aspects of the project. BSES willalso furnish copies of the environmental monitoring audits, semi-annualupdates of the Environmental Due Diligence Plan, and annual financial andadministrative reports. GOM agreed to furnish annual progress reports on theTDP.

IV. FINANCIAL ANALYSIS

Special Reserves and Approved Institution Status

4.01 BSES carries out its electricity activities under the Electricity(Supply) Act. Therefore, as a regulated utility, it is allowed to recoverthrough its tariff all operating costs, depreciation, interest expenses, areturn of 12? on its net remunerable capital base (as defined under the Act)and any additional special reserves allowed by GOM. Regarding the latter, GOMalready has granted BSES permission to create special reserves in order to

31

meet Rs 1,000 million of the proposed project cost requirements.10 GOIagreed that it will ensure that GOM will allow BSES to collect specialreserves as are permissible, including a special reserve for repayment ofBSES's debt, at least equal to the difference between the principal repaymentsand the depzeciation as allowable under the Electricity (Supply) Act (para.6.0l.b.iv). These special reserves are needed to allow BSES to meet itscashflow requirements, which include the payment of dividends and servicing ofdebts after project commissioning. Moreover, GOI also agreed to ensure thatGOM will treat the loans made by IBRD, IFC and the Indian FinancialInstitutions for project financing as loans from "approved institutions" inaccordance with the Act (para. 6.01.b.v). This designation would allow BSESto charge the interest plus a 0.5Z extra return on the opening balances ofthese loans through its tariff. IBRD and IFC estimate that the additionalcharges resulting from the special reserves and the 0.5Z loan markup for"approved institutions" status would increase BSES's tariff only marginally.Therefore the charges should not unduly burden BSES's customers, given thegood quality and reliability of BSES electricity supply.

Past and Projected Financial Performance

4.02 Given that GOI has agreed to ensure that GOM will grant BSES theright to accumulate special reserves (para. 4.01), and assuming that theproject is commissioned on schedule and within projected financingrequirements, BSES's financial position will remain sound in the decade of FY92-2001. BSES's recent and projected financial performance and key assumptionsare detailed in Annexes 4.1-4.6 and its FY 87-2001 performance is summarizedin Table 4.1.

Table 4.1: BSES's Financial Performance

Rs MIirt- kbel - ProJted

FIca 1w traiiq3iSt larcb 196? 19 I199 19 I9m 12 99 1m 99 IM 9 1?im it9 2000 200

Owatlq 1U,U. 3,046 3,257 3,405 4,2" 5,072 5, 6,900 7,934 8,90 9,869 20,873 11,696 12,807 14,031 15,3sfrchiu of hor 2,289 2,433 2,452 3,1 3,622 4,29 4,894 3,55 4,281 4,295 4,37 4,42 5,224 6,073 7,04cut of Coal 0 0 0 0 0 0 0 0 0 1,220 1,550 1,93 2,04 2,171 2,302th1 lwatiU En 64 474 790 903 1,014 1,17 1,339 1,521 1,707 2,328 2,544 2,751 ,9^ 3,28 3,501,roclatlo 37 40 39 4U 3 72 80 8 m 3 3 sao 593 407 42itarot 30 5 n a2 4 59 n 118ie 10 1,0 I,U32 1,082 IO, 924 342Fwda EAclap loou O 0 a 0 0 0 0 0 0 0 81 100 115 12 143at 1sm 71 40 a5 120 328 34 s51 536 350 19 402 782 8t 854 msWutary Iwun ad urorUM 24 IS 32 43 17m 257 27m 2 231 8 86 28 241 249 252Istribotale pdi*t 47 47 53 s9 152 9 237 241 319 53 51 55 575 40 4UH^idads 13 1 IS 2S 23 2a 3 95 201 201 201 201 201 201

Titd Assets 1,93 2,19! 2,616 3,127 4,04 5,839 9,213 13,914 17,32 19,280 19,42 19,2n 19,414 19,559 1,712Tital Ulwe capitua VW i rvn 709 77n 681 1,00 1,340 1,703 S,170 3,448 4,145 6,070 4,52 7,1U3 7,833 1,557 9,317Et 2.9-tv hbt 115 131 147 146 150 1,981 3,7t0 7,707 10,482 9,U11 6,915 8,265 7,53 4,m ,92Nbt ;atura l ioty 0.16 0.17 0.17 0.17 0.11 1.14 :.17 Lit 2.53 1.51 1.31 1.U1 0.94 0.79 0.64Crrlt Ratto 1.39 1.31 1.34 1.27 0.93 1.34 I.39 1.41 1.4 1.32 1.27 1.32 1.34 1.0 1.4

Cash Available fW Odt Sorvice 140 136 IU 220 46 48U5 467 743 828 2,024 2,404 2,540 2,542 2, 2,S0lit fervice SO 35 43 61 61 n 8 I30 137 1,089 1,744 2,047 I,9 2,"7 I',mlit Svice Coewr 4.59 3.92 3.82 3.61 7.14 4.51 7,60 5.71 4.43 1.86 1.38 1.25 2.2 1.30 1.33Averge Tariff, hknA 2.13 1.10 1.13 1.2S I.S9 1.51 1.44 I 2.90 1.9 2.0S 2.0 2.17 2.27 2.

10 GOM has granted the following reserves to BSES during the projectconstruction phase. BSES is allowed to charge to its consumers(through its tariffs) an additional Rs 0.03 kWh. GOM has alsoreduced BSES's purchase price from TEC by Rs 0.03/kWh (TEC will nolonger charge BSES the amounts permitted in the past for TEC tosupport its own project cost financing).

32

4.03 BSES is a financially strong company. It has regularly servicedits debt and has paid dividends of about 18? on its equity capital at par. InFY90, the Company issued bonus shares to its equity shareholders on a 1:1basis, thus doubling its share capital. BSES has also maintained acomfortable cashflow position, mainly as a result of the cost-plus nature ofthe business. It has built up large reserves over the past and its debt levelhas been relatively low. In FY90, BSES's debt to equity stood at about 0.17.Its net income has been steadily increasing -- a pattern expected to continuefrom FY92 to FY95 as interral accruals grow from the special reserves chargedtowards the project costs (para. 4.01). Other than the aberration of a 0.93current ratio in FY91 as a result of including the bridging loan as currentliability in that year (which wil; be paid off with IBRD's retroactivefinancing), its current ratio averaged a comfortable 1.35 between FY87 andFY90.

4.04 BSES's debt-service coverage ratio is projected to average about1.40 during the FY96-2001 period. The ratio will reach a low of about 1.25 inFY98, the first year in which the principal on the Indian FinancialInstitutions' loans must be repaid. The company's current ratio is projectedto average about 1.37 during the next decade, and debt to equity is projectedto reach a maximum of 2.53 in FY95. BSES agreed to obtain IBRD's and IFC'sprior consent before taking on any additional long-term indebtedness otherthan the loans stated in the financial plan, if after such debt has beenincurred the long-term debt-to-equity ratio were to exceed 2.5 (para. 6.02.f).BSES also agreed to set its tariffs at levels sufficient to achieve theprescribed return on its capital base and to recover, through specialreserves, inter alia, the aggregate amount of repayments of principal of itsdebt for that year, as permissible under the Act (para. 6.02.g). In addition,BSES agreed to furnish IBRD and IFC with its financial projections coveringthe current year and the next four financial years, within 120 days of the endof each cf its financial years. These projections will specify BSEScompliance with IBRD and IFC financial covenants and will indicate the actionsBSES may need to take to meet said covenants (para. 6.02.h). IBRD and IFC aresatisfied that with the special reserves (para. 4.01) committed by GOM, BSESwill remain financially sound even within the existing legislation under whichthe private utilities are operating. The promulgation of new incentives toencourage more private investment in the power sector (para. 1.15) wouldenhance BSES's financial position.

Financial Internal Rate of Return

4.05 The financial internal rate of return (FIRR) for the project inconstant terms is 15.0Z. This rate was derived by considering the incrementalcosts and revenue flows associated with construction and operation of thethermal plant at Dahanu and its associated transmission and distributionfacilities. The financial gains to BSES attributable to the project primarilyconsist of revenues from additional electricity sales and reduced bulkelectricity purchases. The financial rate of return is sustainable over theoperating life of the project, as BSES pursues its cost-recovery-based tariffpolicy. Details on the FIRR calculations are presented in Annex 4.4. Theproposed project will provide BSES higher financial returns from itsoperations than if it were to continue relying fully on power purchases fromTEC. Moreover, the latter is not an option opened to BSES, because theconditions attached to its license (para. 2.01) require BSES to contribute itsown share in capacity investments. By so doing, in addition to earning a

33

viable return, BSES gains the advantage of firmer assurance of future supplyas well as a direct control over a large portion of its generation expenses.

Sensitivity Analyses

4.C5 Variations in the cost and revenue profiles were analyzed toconfirm that the project remains financially viable even under adverseconditions. For example, a project cost overrun of up to 25? or a reduction inproject revenues of up to 12? will still yield an FIR above 12Z. If GOIremoves the requirement for the FGD plant, the FIRR will increase to 16.0?.Sensitivity analyses also were performed to gauge BSES's debt-service capacity(Annex 4.5), and to measure the changes in its average tariff arising from thefollowing scenarios: coal cost increase of 12? p.a.; a plant load factor of60? at full commissioning, a 20? project cost overrun due to a one-year delayin project completion, and a 10? devaluation in the Rupee. Since all of itscosts are captured in its tariff, BSES's debt-service coverage would not beadversely affected by the changes.

4.07 If coal costs increased by 12? per annum instead of the projected6?, BSES's tariffs would have to increase by an average of 6.7? p.a. insteadof the 5.5Z p.a. assumed in the base case. Similarly, if BSES's plant loadfactor were 60? at full commissioning instead of the 70? assumed in the basecase, the additional tariff increase would be small (average 6.1? p.a. versus5.5? p.a. in the base case, yielding tariffs of Rs 2.22/kWh versus Rs 2.09/kWhin FY98) and its debt-service coverage would be unaffected. Due to the cost-plus nature of BSES's operations, a project cost overrun of 20? would resultin an average tariff increase of 6.3? p.a. instead of the 5.5? p.a in the basecase. However, debt-service coverage would be marginally depressed to 1.18 inFY98 under this scenario. Forty-four percent of project cost is to be fundedby long-term debt, which is denominated in foreign currencies. A devaluationof the Rupee would increase interest and principal repayments in Rupee terms.If the Rupee were to devalue at 102 p.a. relative to the US Dollar (comparedto the average 4Z p.a. assumed in the base case), then tariffs would increaseby 6.1? p.a. compared to 5.5? p.a. in the base case, and debt-service coveragewould decrease somewhat. In summary, BSES's financial performance isprojected to be quite robust, with debt-service cover remaining acceptableunder a range of adverse scenarios.

4.08 Sensitivity analyses also were conducted to assess the impact ontariffs of GOI removing the FGD plant requirement from its environmentalclearance. This result would have a small favorable impact on BSES's tariffs(Rs 0.03/kWh lower in FY96).

V. ECONOMIC ANALYSIS

5.01 The primary justification for the proposed project is theincreased electricity demand to be met in the BSES service area. In addition,during the project's initial years of operation, it will displace lessefficient thermal-based generation in the Western Regional grid. On thedistribution side, improvement in substation and transformer capacities isexpected to result in reduced transformation and energy losses as well asincreased service reliability. The project's economic viability has beenassessed in terms of whether it yields an adequate rate of return and whether

34

it is an integral part of the Western Regional grid's least-cost powerexpansion program.

Western Region Market Profile

5.02 BSES's service area is part of the inter-connected system of theState of Maharashtra, which in turn is linked to the Western Regional grid.This grid consists of power facilities of the major state-owned utilities ofMaharashtra, Gujarat and Madhya Pradesh augmented by those from the privateutilities (i.e., TEC and AEC). In addition, the grid is supplied with powerfrom NTPC and the Nuclear Power Corporation. In FY90, the grid had a totalinstalled capacity of 19,029 MW of which 692 was operated by the SEBs, 192 byGOI entities and the balance of 122 by private utilities. Thermal stationsaccounted for 85Z of the plant capacity, hydro 13? and nuclear 22.

5.03 The Western Region accounts for nearly 302 of electricitycoiusumption in India. The historical and projected Regional and State demandfor electricity are summarized in Annex 5.1. Since FY82 regional demand hasexpanded at 102 p.a. and in FY90 unrestricted demand was estimated at 12,440MW, of which a peak load of 12,007 MW was served, representing a capacitydeficit of 3.5?. To minimize load shedding, the various SEBs have managed thepea}; loads by enforcing certain regulatory measures (Annex 5.2) includingstaggering of weekly holidays among industries as well as restricting hours ofrural supply. On the other hand, there has been minimal shortfall in energysupply and the grid was able to supply 73,000 GWh in FY90 which largely metthe full demand. The favorable supply conditions obtained last year waspartly due to the successive good monsoons resulting in improved hydrooperations. At the same time, the need for thermal plants to operate atpartial load during off-peak how,rs continues to strain plant equipment and isshortening their operating life. Through FY2000, power and energy demands areexpectcd to increase by 8.82 and 8.4Z per annum, respentively. But whileenergy shortfalls should be minimized with the commissioning of new plantfacilities, the deficit in peaking capacity will be difficult to eliminate inthe medium term. To correct these imbalances in the long term, the generationexpansion plan for the Region includes the installation of a number of peakingplants.11

5.04 Daily system peak in the regional grid occurs in the eveningbetween 7 and 10 p.m., with secondary peaks occurring during the morning. Inview of the heavy industrial load in the region, the system load factors havebeen relatively high, averaging 78Z on an annual basis, and as high as 80? on

The existing 880 MW Koyna hydropower plant, owned and operated byMSEB is being expanded by an additional 1,000 MW capacity, underthe IBRD Maharashtra Power Project (Loan 3096-IN), to allow theentire installation to operate in a peaking mode. Theconstruction of a 150 MW pumped storage (PS) scheme at theexisting hydroelectric power plant at Bhira, situated 95 km south-east of Bombay, is included in the joint IBRD/IFC Private PowerUtilities (TEC) Project (FY90; IBRD Loan 3239-IN; IFC InvestmentNo. 2198-IN). The Bhira Pumped Storage Scheme would provideadditional peak generation capacity and would increase thecapacity utilization of TEC's existing thermal generating units atTrombay, near Bombay.

35

a daily basis. The ratio between the minimum demand and peak demand was 45?for FY90 and the system diversity factor ranged from 1.008 to 1.05.

5.05 Electricity demand in the State of Maharashtra accounts for 48Z ofthe region's requirement and has been expanding at an annual rate of 9Z. InFY90, a peak load of 5,883 MW with a corresponding energy requirement of35,155 GWh was serviced by the power system. The sectoral pattern of demandserved by MSEB in FY90 was 38? industrial, 212 agriculture, lOZ residential,2? commercial, and the balance for railway traction, public services as wellas bulk power transfers. To supplement its system capability to meet theState's growing power requirements, MSEB purchases power from the Regionalgrid. In FY90 this involved net imports of 3,080 GWh.

BSES Market Base

5.06 Electricity sales in the BSES service area represent about 9.52of total electricity demand in the State of Maharashtra or 4.5? in the WesternRegion. In contrast to load curtailment conditions obtaining in the rest ofthe Region, electricity demand in the Greater Bombay Area has largely beenunrestricted since 1980. The city's load requirements have been primarily metthrough generation from plants operated by the Tata Electric Companies (TEC)augmented by supply from the Maharashtra State Electricity Board (MSEB) duringtimes of peak.. The BSES system accounts for about 38Z of the load served byTEC. Energy sales by BSES have expanded at an average annual rate of 11lduring the eighties from 1,140 GlWh in FY81 to 2,899 GWh by FY90, while maximumsystem load has increased by about 8? annually from 314 MVA to 618 MVA duringthe same period. In the medium-term, demand in BSES's service area isprojected to grow by an average annual rate of 7.2? reaching 4,089 GWh by FY95and subsequently increasing at 5.5? per year to 5,344 GWh by year FY2000. Thecorresponding rise in peak load is prcjected at 859 MVA in FY95 and 1,116 MVAby year FY2000.

5.07 The pattern of demand in the BSES service area is characterized bya typical daily peak in the evening at between 6 and 10 p.m., with a secondarymorning peak between 10 and 11 a.m. The system's diversity factor ranges from1.004 to 1.02, and its daily load factor is above 70?. In terms of sectoralconsumption, residential sales presently account for 44? of demand, industrial39? and commercial 16Z. Over the years, residential and commercial sectorshave progressively increased their combined market share froa 44? in 1980/81to 602 today. Conversely, industrial consumption has reduced its share fromas high as 54Z in FY81 to the current 39Z. This trend is expected to continueas population growth in Bombay results in new residential development in thesuburbs served by BSES with attendant expansion of commercial services. Onthe other hand, growth of industries within the Bombay city limits is expectedto be held in check by government regulations.

Least Cost Analysis

5.08 The proposed project is part of the least-cost generationexpansion program developed by the Central Electricity Authority (CEA) for theWestern Regional grid. Given that market projections for the medium termindicate continued supply restrictions for meeting peak load relative toenergy requirements in the regional grid, the alternative of investing fr. acombined cycle facility was reviewed by CEA in view of the operationalflexibility afforded by such plant for meeting intermediate loads. However,

36

available and identified gas supplies in the Bombay area have already beencommitted to other users, including power use, and are expected to be fullyabsorbed. Within existing gas allocations, a 180 MW and a separate 800 MWvariable-load combined-cycle plant are also being planned for the WesternRegional grid under the aegis of TEC and the Maharashtra SEB, respectively,for commissioning at about the same time. The Dahanu plant as a base-loadfacility would therefore complement, rather than compete with the combined-cycle scheme in the system.

Program Analysis

5.09 The economic returns of the power expansion program for theWestern Region was estimated by taking the FY91 to FY2000 investment time-slice. This plan horizon parallels the period required for construction andinitial years of operation of the project. In addition to the capital outlaysfor generation plants to be built and commissioned during this time-slice,investments for transmission and distribution facilities were includedequivalent to about 60? of the generation investment levels. The operatingand maintenance expense profile were developed based on projected systemoperations. All financial costs were converted to economic costs applying thestandard conversion factor (SCF) of 0.8 on local costs, and by removing taxesand duties. In view of its relatively poor quality, domestic co8l isconsidered non-tradeable and its economic price is based on cost at the pit-head plus transport cost to thermal plants in the system. On the other hand,the economic cost of fuel oil is based on its border price plus internaltransport charges.

5.10 Incremental benefits, on account of additional electricityconsumption, were valued initially in termr of the present average tarifflevel in the grid of Rs 0.86 per kWh. Given the scarcity of power supply,however, the value of electricity service in India is deemed to beconsiderably higher than the rates at which it is sold. Accordingly, theconsumers' willingness to pay has been estimated based on the cost ofelectricity from sources other than the grid, i.e., from autogeneration fromdiesel generators for industries (Rs 2.07 per kWh), and for commercial andresidential consumers (Rs 2.75 per kWh), and from diesel pumps for irrigationrequirements of agricultural users (Rs 3.41 per kWh). Derivation of theseestimates of cost of alternative sources of power are given in Annex 5.3.These costs are considered to be the upper limit of consumers' willingness topay for their particular levels of power use from the public supply system,while prevailing tariffs serve as the lower limit. The consumer surplusattributable to incremental consumption met by the project is estimated to beequivalent to half of the difference between these limits as the higher costof autogeneration is seen to reflect the value of energy to consumers duringthe peak and intermediate load periods when there is load shedding, but not

12 On the premise that gas is available, comparative economics of acombined-cycle plant vis-a-vis the proposed project was separatelyevaluated (Annex 5.9). Because of the relatively high economicvalue of gas in the Bombay area, and the favorable price receivedfor the Dahanu station's main equipment package, the proposedthermal station at Dahanu remains competitive against a combined-cycle plant costing US$600 per kW installed (US$730 per kW hasrecently been quoted for combined-cycle projects in the country).

37

necessarily during the rest of the day when energy from the grid is normallyavailable.

5.11 The expansion program for the time-slice FY91-FY2000 is estimatedto yield an economic rate of return (EIRR) of 25Z, a net present value (NPV)at 12Z of Rs 187 billion. If the consumer surplus value were excluded fromthe stream of benefits, the return would be 7% reflecting the relatively lowtariffs charged for recovering the costs of power service. Derivation of theregional program's EIRR is given in Annex 5.4. Variations in cost and benefitprofiles have been analyzed indicating that program investments remaineconomically viable even under relatively adverse operating conditions (Annex5.5). Specifically, the program can withstand capital cost overruns exceeding25Z, or similar reductions in benefits and still yield an economic rate ofreturn exceeding 122.

Project Economics

5.12 To assess whether the project itself yields adequate investmentreturns, identified benefits accruing from the project were compared with theproject costs and other associated expenses required in delivering theadditional electricity service to the final end-users. For this purpose, thesimulation runs performed by CEA on generation dispatch in the grid was usedas the basis for determining the levels of unserved energy in the region withand without the project. Annex 5.6 illustrates the projected dispatch ofenergy from the Dahanu plant vis-a-vis the interconnected grid and theconsequent additions to system input as well as displacement of less efficientexisting thermal stations in the Western Region. The incremental electricityconsumption met by the operation of the Dahanu plant is valued in terms ofprevailing tariffs charged to BSES's customers. In addition, consumersurplus value attached to these usage are included.

5.13 The economic costs of power supply from the project included thecapital costs and corresponding operating and maintenance expenses for thethermal station and associated transmission and distribution facilities,subject to exclusion of taxes and duties and application of the 0.8 SCF onlocal cost components. The economic price of coal is taken to be the pricecharged at the pit-head of Rs 167 per ton plus transport costs of Rs 443 perton. In addition, wiring costs normally incurred by BSES's power customersare considered at Rs 1,300 per additional kW load connected.

5.14 The resulting EIRR is estimated at 22.0? and its NPV at a 12Zdiscount rate is Rs 6,501 million (Annex 5.7); the project is thus deemedeconomically viable. Exclusion of the consumer surplus from the benefitstream would yield a rate of return of 13.3Z. If the FGD plant were excludedfrom the project cost, the EIRR would be higher at 22.9Z yielding an NPV at122 of Rs 6,853 million.

5.15 The robustness of the project's economic rate of return was testedagainst adverse variations in cost and benefit assumptions assuming capitalcost overruns, reductions in benefits, and delays in project commissioning.Results, shown in Annex 5.8, indicate that the project can withstand projectcost increases of up to 5O? and still yield a favorable rate of return of16.5Z. Erosion of benefits up to 352 or a 3-year delay in plant commissioningcan occur without impairing the project's ability to earn at least 12%.

38

Combined effects of up to 282 project cost overrun and up to 28Z benefitreduction would still preserve the project's economic viability.

VI. AGREEMENTS AND RECOMMENDATION

Agreements Reached between IBRD, and GOI and BSES

6.01 GOI has:

(a) Reaffirmed the availability of adequate and timely supplies ofsuitable fuel for the proposed power plant (para. 3.17); and

(b) Agreed to ensure that GOM will:

(i) not take any actions that would adversely affect BSES'soperational performance and financial position, includingrestricting BSES's area of supply (para. 2.02);

(ii) formulate and furnish to IBRD for review, by March 31,1992, a Tribal Development Program and implement thisprogram in a manner satisfactory to IBRD (para. 3.28);

(iii) through MPCB, to carry the audit of BSES's environmentalmonitoring program (para. 3.40);

(iv) allow BSES to accumulate certain special reserves as arepermissible, including a special reserve for repayment ofBSES's debt, at least equal to the difference between theprincipal repayments and the depreciation allowable underthe Electricity (Supply) Act (para. 4.01); and

(v) treat IBRD, IFC and the Indian Financial Institutions'loans toward the project financing as loans from "approvedinstitutions" in accordance with the Act (para. 4.01).

6.02 BSES has agreed to:

(a) furnish its annual financial statements and the status of theSpecial Account for the IBRD loan, audited by auditors acceptableto IBRD, within 120 days after the end of each of its financialyears (para. 2.14);

(b) conclude agreements relating to the operation of the BSES plant,with both MSEB and TEC prior to the synchronization of the firstunit of the Dahanu power plant (para. 2.18);

(c) complete by June 30, 1994, the subscription of the seconddebenture issue, underwritten to the extent offered to the public(para. 3.06);

(d) establish and maintain a project management structure satisfactoryto IBRD (para. 3.09);

39

(e) execute the security arrangements for the proposed loan (para.3.15);

(f) obtain IBRD's prior consent to incur any additional long-termindebtedness, other than the loans stated in the financial plan,if after such debt has been incurred the long-term debt-to-equityratio exceeds 2.5 (para. 4.04);

(g) set its tariffs at levels sufficient to achieve the prescribedreturn on its capital base and to recover, through specialreserves, inter alia, the aggregate amount of repayments ofprincipal of its debt for that year, as permissible under theElectricity (Supply) Act (para. 4.04); and

(h) furnish to IBRD its financial projections covering its currentyear and the next four financial years, within 120 days of the endof each of its financial years, specifying its compliance withIBRD financial covenants and indicating the actions it may need totake to meet the said covenants (para. 4.04).

6.03 The following would be conditions of effectiveness of the proposedIBRD Loan:

(a) Extension by GOM of BSES's license to at least up to the maturitydate of the proposed IBRD loan (para. 2.02);

(b) Fulfillment of all conditions precedent to disbursement of the IFCInvestment have been fulfilled (para. 3.05);

(c) Creation of an equitable mortgage in a form satisfactory to IBRD(para. 3.15); and

(d) Execution of a Power of Attorney in favor of IBRD (para. 3.15).

Agreements Reached between IFC and BSES

6.04 The terms and conditions of the Investment Agreement between IFCand BSES are consistent with the above.

Recommendation

6.05 On the basis of the project justification and the agreementsreached, the proposed project would be suitable for an IBRD loan of US$200million and IFC investment of US$68 million equivalent, of which up to US$18million would be syndicated, to Bombay Suburban Electric Supply Limited.

_40- Annex 1.1Page 1 of 2

INDIA

PRIVATE POWER UTILITIES (BSES) PROJECT

ALL-INDIA: ELECTRICITY SUPPLY AND DEMAND

Actual Estimated............ .... ..... , ........................................... ..

Annual AnnualFY82 a/ FY90 Increase b/ FY91 FY95 FY2000 Increase.......... ....... ....... . ... ....... ........... ....... ............ ... .................. ....

FY90-FY20001. Capacity (tW) tNW) (X) (KW) (KW) (KW) (X)

a. Installed Capacity 32,347 62,700 8.6X 66,894 103,916 165,481 10.2X

b. Peak Capability 20,121 35,425 7.3X 37,527 61,418 99,365 10.9K

c. Peak Load 20,121 47,014 11.2K 50,945 71,711 112,319 9.1X

d. Deficit n.a 11,589 13,418 10,293 12,954

as % of Peak Load - 24.7X 14.4K 11.5K

2. Energy (GWh) (GWh) (K) CGWh) (GWh) (GWh) (K)

a. Generating Capability 113,827 245,141 10.1% 271,250 381,856 629,087 9.9X

b. Energy Requirement c/ 113,827 249,059 10.3K 269,460 384,764 593,773 9.1K

c. Deficit n.a. 3,918 0 2,908 0

as X of Requirement - 1.6% - 0.8K -

a/ Supply constrained. No estimates are availabLe on extent of suppressed demand.b/ Growth rates are overstated as FY82 data reflect supply rather than demand.c/ Total final demand for energy plus transmission and distribution losses.

Sources: Annual Report on the Working of SEBs and EDs, Planmirng Commissfon (September 1990)Thirteenth Electric Power Survey of India, CEA, December 1987

-41- Annex 1.1Page 2 of 2

INDIA

PRIVATE POWER UTILITIES (BSES) PROJECT

ELECTRICITY SUPPLY AND DEMAND

ALL- INDIA: ENERGY CONSUMPTION BY MAIN CONSUMER CATEGORY

Actual tX) Estimated tX)~~~~~~~~~~~~~~~~~~~,.................... . ....... ................... ....

Consumer Category FY82 FY9G a/ FY91 a/ FY95 b/ FY2000 b/............................. .. .... ........................... ......... ---------..... ......... .............. .........

1. Domestic 11.6 13.8 13.9 19.4 23.6

2. Industry 57.7 41.4 41.8 39.1 30.6

3. AgricuLture 16.9 24.9 24.4 28.1 32.0

4. Commercilat 5.8 4.6 4.7 4.8 4.8

5. Traction 2.8 1.9 2.0 2.4 2.4

6. Public Lighting 0.9 0.9 1.1 1.3 1.5

7. Public Water 2.3 1.8 1.9 2.2 2.4

8. Others 2.0 10.7 10.2 2.7 2.7

......... ......... . .... ......... ---------. .... ......... ....... ........._

Total 100.0 100.0 100.0 100.0 100.0................... ............. ......... . ............. ......... ---------

...........................

a/ Provisionalbl Bank estimates

Source: Annual Report on the Working of SEBs and EDs, Planning Commissfon (September 1990)Thirteenth Electric Power Survey of India, CEA, December 1987

INDIA

PRIVATE POWER UTILITIES (OSES) PROJECT

COMPARISON OF AVERAGE TARIFFS

MSEB TEC SSES BESTDemand Energy Demand Energy Purchase Selting Purchase SelLingRevision Date Charge Charge FAC Charge Charge FAC Cost Rate Cost Rate

Rs/kVAJmo P/kWh P/kWh Rs/kVA/month P/kWh P/kWh P/kwh P/kWh PfkWh P/kWh

Jasuary 28, 1977 16 11 5.3/5.3March 16, 1979 18.4 - 22.6 10.1 - 11.8 9/9March 17, 1981 21.4 - 26.4 11.7 - 13.7 14/17 33.25 45.54 4-Septeber 16,1961 22 20 10/10 24 - 27 20.0 - 20.8 23.5/23.5 46.46 62.14Janiary2, 1986 35 84 44/ 2 28 - 34 68 - 83 50/0 73.53 92.27 72.91 104.84unie 1, 1987 35 88 6/6December 1,1967 28 - 34 68 - 85.5 3/0.5March 24, 1988 85.58 110.00 85.32 121.85February 1, 1989 40 110may 1, 1989 34 97.5 97.29 125.00 97.70 1.35nay 1, 1990 60 125-130August 1, 1990 55 85.5 - 106.5 110.00 142.00 110.00 149.00

Source: NSEB, TEC, BSES and BEST

I-a

N

-43-

ANNEX 1.3INDIA

PRIVATE POWFR UTILITIES COSES) PROJECT

Previous Loans ond Credits to Indian Power Sector Cas of April 30, 1*#........................................................................

(Amount in USS Millon)

Borrower IBRD Loans Number Date Date Amount Disbursed status............................. ........ ............ ............. ............ ......... ............. ......... ............. .........

1 India First DVC Bokaro Konar 23 4/50 2/56 18.5 16.7 Complete2 India Second DVC - Maithon - Panchot 72 1/53 6/58 19.5 10.5 Complete3 Tata Trombay Power 106 11/54 9/66 16.2 13.9 Conpleot4 India Second Trombay 164 5/57 9/66 9.8 9.7 Coaplete5 India Third DVC Durapur 203 7/58 6/65 25.0 22.0 Colplete6 India Koyna Power 223 4/59 4/65 25.0 18.7 Complete7 India Power Transmission 416 6/65 12/70 70.0 50.0 conplete8 Tata Second Kothagudem Power 417 6/65 12/70 14.0 13.8 Comptlte9 India Third Trombay Thermal Power 1549 4/78 12/84 105.0 105.0 Complete10 India Ramagundam Thermal Power CU) 1648 1/79 6/87 50.0 45.6 Completo11 India Farakka Thermal Power (*) 1887 6/80 6/89 25.0 2.5 Complete12 India Second Ramagundam Thermal Power C') 2076 12/81 6/90 280.0 /a 270.413 India Third Rural Electrification 2165 6/82 6/88 304.5 295.5 Conplete14 India Upper Indiavati Hydro 2278 5/83 6/94 156.4 0.415 India Central Power Transmission t*) 2283 5/83 3/90 250.7 118.416 India Indira Sarovar 2416 5/84 6/92 17.4 /b 4.917 India Second Farakka Thermal Power C') 2442 6/84 12/91 300.8 176.518 Tata Fourth Trombay Thermal 2452 6/84 6/90 135.4 123.819 India Chandrapur Thermal Power 2544 5/85 12/92 300.0 169.320 India Rihand Power Transmission (M) 2555 5/85 12/89 250.0 183.121 India Kerala State Power 2582 6/85 9/91 176.0 35.922 India Combined Cycle 2') 2674 4/86 12/91 485.0 443.923 India Karnataka Power 2827 6/87 12/95 330.0 36.324 India National Capital Power Suuply C') 2844 6/87 6/95 425.0 /c 185.625 India Talcher Thermal Power C') 2845 6/87 3/96 375.0 44.226 India Second Karnataka Power 2938 5/88 12/96 260.0 26.227 India Uttar Pradesh Power 2957 6/88 12/96 350.0 45.528 India Nathpa Jhakri Power 3024 3/89 12/97 485.0 36.729 India t4aharahstra Power 3096 6/89 12/96 400.0 20.730 India Northern Region Transmission 3237 6/90 9/98 485.0 20.031 India Private Power Utilities 3239 6/90 6/95 98.0 0.0

Total 6242.2 2545.7(Total Loans for NTPC Projects) C 2501.3 )............... r

/a Out of originat loan amount of LISS300 mtilon, USS20 million were cancetlled./b Out of original loan amount of USS157.4 million, USS140 million were cancelled./c Out of original loan amount of USS485 million, USS60 million were cancelled.

IDA Credits

1 India Fourth DVC - Durapur 19 2/62 12/69 21.9 19.9 Comeplte2 India Second Koyna Power 24 8/62 9/70 21.1 21.1 Complete3 India Kothagudem Power 37 5/63 12/68 24.1 24.1 Complete4 India Beas Equipment 89 6/66 6/74 26.6 26.3 CompleteS India Second Power Transmission 242 4/71 3/77 75.0 72.9 Conplete6 India Third Power Transmission 377 3/73 9/78 85.0 85.0 Complete7 India Rural Electrification 572 7/75 12/80 57.0 57.0 Complete8 India Fourth Power Transmission 604 1/76 6/83 150.0 149.9 CoaMlete9 India Singrauli Thermal Power (') 685 3/77 6/84 150.0 150.0 Coaplbte10 India Korba Thermal Power C') 793 4/78 3/86 200.0 199.9 Complete11 India Ramagundam Thermal Power (M) 874 1/79 6/87 200.0 200.0 Comptote12 India Second Rural Electrification 911 5/79 3/84 175.0 171.7 Complete13 India Second Singrauli Thermal Power C') 1027 5/80 3/89 300.0 292.8 Complete14 India Farakka Thermal Power (M) 1053 6/80 12/88 225.0 225.0 Cotplote15 India Second Korba Thermal Power ') 1172 7/81 12/89 400.0 370.3 Complete16 India Upper Indravati Hydro 1356 5/83 6/91 170.0 158.517 India Indira Sarovar SF020 5/84 6/92 13.0 /d 0.618 India Indira Sarovar 1613 5/86 6/92 13.2 0.0

Total 2306.9 2225.0(Total CrWits for NTPC Projects) c 1475.0 )

................

(*) UTPC Projects/d Out of original credit of USS129.8 equivalent, USS116 equivalent were cancelled.

-44-

Annex 2.1

INDIAPRIVATE POWER UTILITIES (BSES) PROJECT

Electricity Sales and Consumption Pattern

Financial Residential Commercial Industrial Street Lighting TotalYear Gwh Consumer Gwh Consumer Gwh Consumer Gwh Consumer Gwh Consumer..... ....... . ........ ........... ....... .............. .......................................... ....................................................

1980 454 524 147 57 676 17 38 - 1315 5981981 501 569 165 63 733 19 40 - 1439 6511982 543 617 181 69 754 20 42 - 1520 7061983 606 671 200 75 805 21 42 -- 1653 7671984 677 728 222 81 861 21 46 -- 1806 8301985 773 777 257 88 942 23 48 -- 2020 8881986 854 822 292 96 1007 24 49 -- 2202 9421987 897 872 318 103 1014 25 50 - 2279 10001988 1041 921 368 111 1016 26 52 -- 2477 10581989 1111 980 405 120 1096 26 54 2666 11261990 1268 1051 456 131 1119 27 56 -- 2899 1209

Number of consumer figures in thousands.

goi

11 a

I~~~~~~I~-~~i7 -M.

INDIAPRIVATE POWER UTILMES (BSES) PROJECT

PROJECT MANAGEMENT STRUCTURE

ICMD I

OIR tECH DINR (FNGM (GEC N TANTTS

DIR (TECH)

TECHNIJCAL RtEVIEWPROJECT PLAN?4NG & ITCH&ITE IMONITORING CELL - GM(CORPORWE OFFICE) CHIEF ENGNEEP

SENOR MANAGERS

GENERAA G.SDtACMM ANAGERL S.MA|

TRANSAMSSION~ & EERTO

220 KV SUBSTATION

D | | Snr OFFIE | U;USO CELLClBEMEG CUSTOhilMORT

SFL O.S.D.(CML)~~~~~~~~~~~w ELECER N STCRU & F8GE FTGE RELATIONSI |OFFICER|ENVIRONMENTALJST I~~~~~~~~~NENTRUMENTAIO MEHNIA ATE L |H|ANU

'Thze po t11w1 be NWy bwaed at Xm Pml EMMO O m "eInOZ 6yardO FAdydW 0tdie dw skpss"hIns kcd V

-47- Annex 2.4

INDIAPRIVATE POWER UTILITIES (BSES) PROJECT

BSES Power Purchase from TEC

......... .............. ......... .................. ...... ........... .... .... ...... ................ ......................

Financial Power Requirements Energy Input from Purchase from TECYear Gwh Dahanu to BSES's Gwh

Distribution SystemGWh

1990 3273 32731991 3516 35161992 3761 37611993 4015 40151994 4276 42761995 4543 45431996 4816 1953 28631997 5093 2344 27491998 5373 27j4 26391999 5655 2734 29212000 5938 2734 32042001 6220 2734 34862002 6506 2734 37722003 6796 2734 40622004 7091 2734 43572005 7393 2734 46592006 7703 2734 49692007 8023 2734 52892008 8352 2734 56182009 8690 2734 59562010 9038 2734 6304

-48-

Annex 3.1Page 1 of 12

INDIA

PRIVATE POWER UTILITIES (BSES) PROJECT

Project Description

A. Dahanu Ther.wal Power Plant

1. The proposed Dahanu TPP would be built in the Thane District of State ofMaharashtra, near the town which bears the same name. Dahanu is located about125 km north of Bombay (about 80 km from BSES's licence area). The site isaccessible from the National Highway No. 8 and the nearest railway station isat a distance of 5 km. The site is surrounded by the Dahanu Creek and its twoarms, on its south (Dandi creek), and north (Savta creek). The Bombay-Suratrailway forms the site's eastern boundary. The power station would comprisetwo coal-fired units of 250 MW each. The salient features of the project aregiven in the following paragraphs.

2. Land: The land is predominantly flat, marshy, non agricultural wasteland and devoid of any vegetation, because it was recently used as salt pans.The land is also uninhabitated. As such no felling of tress and displacementof people is involved. BSES has bought the land from the Government ofMaharashtra. Of a total area of 816 ha., 280 ha. would be used for theconstruction of the power plant and the residential colony; 536 ha. would formthe ash dumping area (from Agwan and Asangaon villages).

3. Railway Siding: The railway siding of about 5 km between the Dahanurailway station and the power plant would not pass through any agriculture orforest land nor involve the displacement of population. RITES have beenappointed as consultants for the design and project management of the railwaysiding.

4. Road Accesss An access road of about 5 km will be built from the Dahanutown. The road and railway siding will cross the Savta creek on two separatebridges. A level crossing on the mainline railway has also been built for theinitial construction period.

5. Coal Supply: The proposed 500 MW Dahanu TPP would burn about 2 milliontonnes of run-of-mine coal per year. The Department of Coal of GOI hassanctioned the coal linkage for the project from the Gopalpur opencast minesof the South Eastern Coal Fields Limited (SECL) in the lb Valley in Orissa,about 1,400 km from Dahanu. It is expected that Gopalpur mines will startproduction in 1992-93, however the railway siding of about 40 km which wouldbe required to deliver this coal to the Indian railway network will not becompleted until 1994-95. As the Dahanu power station would require coaldeliveries in middle 1994, this program is suitable for the project. However,in case the railway siding is delayed, SECL have agreed to meet during theintervening period, BSES's requirements from Lakhanpur mines in the samevalley. The production at the Ib Valley is projected to be about 18 milliontonnes in FY96, the resulting increase for the Dahanu TPP would be about 112.

-49-

Annex 3.1Page 2 of 12

Characteristics .-f the coal are given in Table 4.1 of the companion documenttitled Environmental Assessment for the Dahanu Thermal Power Station. BSEShad a study on the deshaling and beneficiation of the Ib Valley coal carriedout by consultants (CMPDI). The study did not establish the technical andeconomic feasibility of washing this coal and then transporting to Dahanu.

6. Transportation of Coal: The run-of-mine coal would be transported toDahanu by rail. The movement would be normally via the Nagpur-Jalgaon-Surat-Tapti valley link. BSES's consultants (RITES) have che'ked that movement of 2million tonnes/year of coal would be feasible through the existing railwaynetwork. The coal will be transported in wagons of about 58 tonnes capacity.

7. Coal Handling Facilities: For unloading of these wagons, two rotarywagon tipplers, one working and other standby of 800 t/h capacity would beinstalled. This would handle the peak receipt of a day in about 12 hours andMCR requirement of a day in about 10 hours. Coal will be stored in the coal-yard and sprayed with water and compacted by bulldozers to prevent coal dustbeing air borne. Wagon tipplers will be provided with dusttrapping/suppression equipment. Other characteristics would be:

Coal Bunkers: Type: Cylindrical - cone type;Number: Three sets per boiler;

Net storage capacity: 12 hours full load operation;

Coal Feeders: Type: Gravimetric type;Number: Six sets per boiler;

Pulverisers: Type: Tube mills;Number: Three sets per boiler;

Reinforced concrete raft foundations will be provided for the conveyorsupports, crusher house, junction towers, trestles, etc. Conveyor tunnels,reclaim hoppers, wagon tippler will, however, be founded directly on suitablestrata. The superstructure of the crusher house, junction towers and conveyorsupports will, however, be in structural steel with AC sheet cladding in wallsand roofs. Two wagon tipplers with two streams are envisaged. AstaCker/reclaimer will be provided for stacking and reclaiming the coal.

8. Fuel Oil Supply: Low sulphur heavy stock (LSHS) fuel oil would be usedfor start-up, warming up and for low load operation. The fuel oil systemwould be designed to meet 30? MCR requirement of the two steam generators.High energy ignitors will be used for ignition of the heavy oils directly.For the black (cold) start-up of the units, when no external auxiliary steamis available, each of the steam generator will be provided with light oilfiring system, having a minimum capacity of 7.52 BHCR to be installed on thelower-most burner elevation. A burner design utilizing same burner tip forboth heavy oil and light oil will be used.

9. Cooling Water Supply: Sea water would be used in once through condensersystem. The total sea water requirement is estimated to be about 80,000m /hr. The intake for drawal of water will be in the Dahanu creek, which has

-50-

Annex 3.1Page 3 of 12

a width of approximately 220 meters and average depth of about 6 m at thecenter. Five vertical pumps, four running and one standby, each of about20,000 m8/hr. capacity will be provided for pumping sea water to the plant.There will be separate intake pipi..g system for each unit and a commondischarge channel for both the units. A chlorination system is envisaged toprevent marine growth inside the circuit. Coarse bar screens and travellingscreens are proposed on the suction side to prevent debris from entering thesystem. The release of warm water will be made to Dandi creek through achannel of 3 km long; the water temperature will decrease by about 4 to 5 °Cin the channel; the temperature increase of water in the creek will be lessthan 3 °C. The intake and outfall to the creek will be located in such a waythat there should be no recirculation of hot water from the outfall to theintake. Tidal flow and all other conditions were studied by consultants (theCentral Water and Power Research Station (CWPRS) at Pune, Maharashtra). Thedesign of the CW system would ensure that the temperature of water would notrise more than 3 °C at any place in the creek. Actual temperature rise wouldbe very minimal and as such there would be no effect on the aquatic life andfishing in the creek would not be affected.

10. Fresh Make-up Water System: The total fresh water requirement isestimated to be about 2 million m3/year. This will be obtained from the SuryaPrakalp Reservoir, which has a storage capacity of 285 million mi. Theallotment for the project is less than 1Z of the storage capacity and will bereserved out of the 21 m8/year allocated for industries; i.e. the projectwould not compete for the water reserved for irrigation (247 million m3/year).Fresh water from the reservoir would be brought to the plant area bl apipeline and stored in a tank having a capacity of about a 16,000 m . Threepumps, two working and one standby, each with a capacitl of 160 m8/h will pumpfresh water into a clarifier having a capacity of 320 m /h.

11. Steam Generators: Two conventional two-pass boilers with a single drum,radient type membrane walled furnace, superheater, reheater and horizontalmulti loop economizer would be built. The boilers would be equipped to burn10OZ coal or 100Z natural gas (if and when available). Low sulphur heavystock (LSHS) fuel oil would be used in conjunction with pulverised coal firingduring start-up and at low loads for warm up and flame stabilisation. Thecirculation would be natural. The boilers would be designed for loading asfast as practicable subsequent to synchronization after cold or warm or hotstart up. They would also be designed for continuous operation with oneheater or all the HP heaters out of service. Burners would be designed forlow NOX emissions. Other characteristics would be:

Boilers:Evaporation at MCR: 805 t/h;Steam pressure at MCR S/H outlet: 155 kg/cm2

Steam temp. at MCR S/H outlet: 540 °C;Feed water temp. at MCR: 246 *C;Air temperature: 30 °C (for performance calculation);Draft system: Balanced draft system;Fuel: - Main fuel: Coal, Natural Gas;

- Start-up fuel: LSHS;

-51-

Annex 3.1Page 4 of 12

Steam temp. control range: 60Z boiler MCR to 100t boiler MCR(for coal firing);

Steam temp. control method: Burner tilt/spray attemperation, gasbiasing and gas mass flow control(Gas mass flow control is fornatural gas firing);

Furnace: - Type: Membrane wall furnace;Steam drum: - Number: One per one boiler;

- Main steam pressure: 155 kglcm ;- Main steam temp.: 540 °C;- Reheat steam temp.: 540 C;- Flue gas velocity: 9 m/sec;

Temperature at outlet of air heater: 135 °C;Boiler feed pumps: Two per unit.

12. Electrostatic Precipitators (ESPs): Each boiler would be fitted withESP of 99.8Z efficiency and having four streams, with one stream out formaintenance and under worst coal conditions. The ESPs would be of horizontalgas flow, outdoor type and installed on the cold end side of regenerative airpreheaters.

13. Chimney: The emission of the fly ash would be through a chimney of 275m high. The stack foundation would be in reinforced concrete resting on piles.NTPC are designing the chimney and will prepare detail specifications as wellas carry out detail engineering.

14. Turbine-Generator (TG) Building: The two TG units, each having a 250 MWand associated auxiliaries, would be housed in a building 183 m long with aclear span of 25 m. In line with this building, one maintenance and unloadingand service bay, of 12.0 m length would be provided. The building and theadjacent workshop would be served by two EOT cranes of 115/25 tonnes capacityeach. Along the length of the building, a bay 12 m wide and of adequatelength would be provided to house the electrical switchgear, control room, theoperators' office and shift charge engineer's office.

15. Turbine-Generator Units: The steam TG unit would be suitable for directconnection to the reheat type steam generator designed to provide steam at 150kg/cm2 (abs) pressure and 5370 C temperature at the turbine inlet. Auxiliarysteam requirement (approximately 5 t/h under normal operating conditions)would be tapped off from the HP turbine exhaust (cold reheat line). Eachgenerator would be connected to its own unit step-up transformer. Theauxiliary power requirement would be drawn from unit auxiliary transformertapped off from generator bus duct. The TG units would be designed to operatesatisfactorily under prevailing tropical conditions.

16. Turbines: Two turbines of 250 MW each, would have high pressure (HP)and intermediate pressure (IP) modules. The steam turbine will be of tandemcompound, single reheat, regenerative, condensing, multi-cylinder design, withseparate H.P. and I.P. casings with six uncontrolled steam extractions forregenerative feed heating and directly coupled to a generator suitable for

-52-

Annex 3.1Page 5 of 12

indoor installation. The unit will be provided with HP-LP (low pressure) ByPass System having a capacity of 420 t/h. for cold starts, house loadoperation, quick hot restart and suddedload throw-off. In the LP cylinder,the profiles of the last stage blades would be of the type normally fitted ona 500 MW turbine, so as to permit the unit to produce 250 MW. Othercharacteristics would be:

a. Output under Economic MaximumContinuous Rating (EMCR) atGenerator terminals: 250,000 KW

b. Turbine throttle steam pressure: 150 kg/cm2 (abs)c. Turbine throttle steam temperature: 537 °Cd. Turbine reheat stream temperature: 537 *Ce. Condenser cooling water temperature: 33 °Cf. Turbine speed: 3000 RPMg. Frequency variation: 47.5 Hz to 51.5 Hzh. Quantity of D.M. water make-up to

thermal cycle: 3Z of throttle steamflow

The unit will be guaranteed to generate 250,000 KW continuously with max. CWtemperature 35 deg. C with 3Z make-up to the cycle. The turbine will becapable of operating continuously with valve wide open to swallow 105Z of EMCRsteam flow to the turbine. It shall also be capable of operating continuouslyunder HP heaters out of service and generating maximum output (not less than250,000 KW). In case continuous over pressure operation of the turbine, itwill be capable of accepting variation in steam pressure and temperature asper IEC-45 from the over pressure condition.

Turbine throttle pressure: 150 kg/cm2Turbine throttle steam temperature: 537 °CTurbine reheat steam temperature: 537 °CCondenser cooling watertemperature at inlets 33 °C

17. Generators: Two generators of 250 MW (294 MVA) each would be installed.The stators and rotors would be directly cooled by hydrogen. The excitationsystem would be brushless. Other characteristics would be:

Power factor s 0.85Terminal voltage s 16.5 kVFrequency : 50 HzSpeed s 3000 RPMS.C. ratio s Not less than 0.5

18. Control and Instrumentation (C & I): The C & I system would beDistributed Digital Control System (DDCS), which is the latest proven state ofthe art in the field. The system will be designed to operate satisfactorilyunder the environmental conditions experienced in coal-fired generating unitsand will be tropicalized for high ambient temperature and high humidity.Overall unit control will be from the BTG board through a network ofcoordinated control systems. The BTG board will be of the functional type

-53-

Annex 3.1Page 6 of 12

with selection and grouping of instruments designed for convenient and safeunit operation. The design will be such that manual remote operation of theplant will be possible if automatic controls fail or are temporarily taken outof service.

19. Transportation of Plant and Machinery: Indigenous plant and machinerywill be transported to site by rail over the railway siding. Imported plantand machinery will be unloaded at Bombay harbor and will be transported tosite by railway. Some minor equipment will be transported by road; this isnot expected to cause significant traffic problems.

20. Storage of Equipment: A covered warehouse and open storage yard tostore the spares, consumables and equipment will be built and provided for theoperation and maintenance of the plant. The location of these facilities willtake into account proximity to the railway track area, the access road and themain plant. Sufficient open space is available for unloading of materialsduring construction and storage in open yards and covered sheds.

21. Service Building: The administration building, the canteen, the servicepremises and the workshop will be provided adjacent to the TG building.

22. Green Belt: BSES will create a green belt around the power station, ashdump and coal storage areas which will act as a screen and will prevent dustmigration from the power station.

23. Solid Waste Disposal: Ash, to the extent of 2,400 t/day from the powerplant would be dumped in the bunded area to ensure that ash slurry does notflow into the creek. BSES has acquired 400 ha. of land for this purpose; thisland would be adequate to store ash over a period extending beyond 25 yearswith ash deposition upto 4 meters height. For locating ash pipeline acrossDandi creek, a suitable trestle bridge on piles will be provided.

24. Noise Control: All equipment will be designed and operated to have thetotal noise level not exceeding 90 dbs. Additionally, since most of the noisegenerating equipment will be in enclosed structures, the noise outside will bestill lower. The plant is not expected to add to the present ambient noiselevels.

25. General Buildings: Building for pump houses, DM plant, switchgearrooms, bulldozer workshop and loco sheds will be in reinforced concrete framewith brick walls and RCC roof slabs with water-proofing. Building forwarehouse will have similar construction except roofing which will be of ACsheets over steel trusses.

26. 220 kV Switchyard: Switchyard structures will be in galvanisedstructural steel supported on reinforced concrete raft foundations. The cabletrenches will be of reinforced concrete construction. The switchyard willhave roads as required.

27. Plot/Yard Drainage: Storm water drains will be provided to take care ofthe plot drainage. The drains will discharge by gravity, into specially

-54-

Annex 3.1Page 7 of 12

created holding ponds inside the plot. Drainage within the plant area will bethrough drain trenches/underground pipes. Drains outside the plant area willbe trapezoidal open lined drains. Drains will not be covered except withinthe main turbogenerator building and boiler area. In this case, the drainswill be covered 25 MM thick cast iron grills. The drains will be sized on thebasis of permissible velocity a::d maximum intensity of precipitation.

28. Demineralized Water (DM) System: It is proposed to use DM water(condensate quality) in a closed cycle for cooling of the hydrogen coolers ofthe TG. The coolers will be designed for the shut off head of auxiliarycooling DM water pumps. The DM water will be cooled by sea water.

29. Steam Condensing Plant: Exhaust steam from the steam turbine, HP-LPbypass system, heater drains, vents boiler drain flash tank drains and othermiscellaneous drains will be condensed in the condenser. Sponge rubber balltype on-load tube cleaning system will be provided with each half of thecondenser to keep the condenser tubes clean during operation. 2xlOOZ vacuumpumps will be provided for air evacuation duty. Provision will be made forstandby pump to cut in automatically in case the running pump fails and whencondensate pressure falls back to present level.

30. Regenerative Cycle: The regenerative cycle will consist of two highpressure feed water heaters, a constant pressure deaerating heater, three lowpressure feed water heaters, one gland steam cooler, one drain cooler, twocondensate pumps, two boiler feed pumps, and two booster pumps. The turbinecycle will have a gross heat rate of not more than 2000 Kcal/Kwhr.

31. Fire Fighting System: The storage and design of the fire fightingsystem will be as per Fire Protection Insurance Rules. The source of waterfor fire fighting will be clearwell which stores the clarified water. Thesystem will have both AC motor driven and diesel engine driven horizontalpumps. The system will be kept pressurised by jockey pumps. This system willbe common for both units.

32. Potable Water System: The potable water requirements will be met by theclarified water from clearwell after filtration. This will be stored in astorage tank located in power station area and chlorinated. The system willbe common for both units.

33. Ash Handling System: (i) The proposed ash handling system will beprimarily designed for three shift operation with a capacity to handle 2000tonnes of ash/day/unit. There will be two parallel streams for bottom as wellas fly ash. The bottom ash and the fly ash will be sluiced in wet form to theash disposal area. (ii) The bottom ash from the unit will be collected in awater impounded bottom ash hopper which will have a capacity to store eighthours of bottom ash. Once a shift the bottom ash will be crushed by theclinker grinders and sluiced by hydro ejector to the sumps of the ash disposalpump house. The time for removal of bottom ash in each shift will not exceedone hour. (iii) Fly ash hoppers will be divided into two groups. Fly ashfrom the hoppers will be conveyed by an air stream which will be created bythe vacuum produced by the hydro ejectors, and the ash will be mixed with the

-55-

Annex 3.1Page 8 of 12

water and will be pumped to the sumps of ash disposal pump house. (iv) Thebottom and fly ash slurry collected in sumps will be pumped out to the ashdisposal area by one or more slurry pumps working in series.

34. Fuel Oil Storage and Handling System: Fuel oil will be brought to thepower station siding by rail tank wagons, each having a capacity of about 20tonnes. The tank wagons will be equipped with steam coil heaters tofacilitate unloading of high viscosity fuel oil. The proposed fuel oilunloading, pumping and storir.g system will be designed for 30Z fuel oil firingand will consist of: rotary, positive displacement type fuel oil transferpumps and capable of pumping the fuel oil from the tank wagons to the storagetanks. One pump will normally be working and the other will be standby. Thefuel oil storage tanks, each having adequate storage capacity are proposed.The tanks will be provided with floor coil heaters and suction heaters.Complete piping with steam tracing and insulation, valves and flexible hoseswill be provided. Fuel oil from the storage tanks will be pumped to theboiler by a set of pumping and heating units.

35. Light diesel oil required for ignition will be received in rail tankwagons. The proposed light oil unloading, pumping and storing system willconsist of the following equipment:

i) Two 100Z capacity, rotary, positive displacement type transferpumps, each having a capacity of 50 tonnes/hr.

ii) Two storage tanks having a capacity of 250 m3 each.

iii) Two 100Z capacity pumps to pump oil from the storage tank to theboiler, with necessary valves.

36. Electrical Systems: (i) Generator transformers: The generators will beconnected to the 220 kV switchyard through the generator transformers whichwill step up the generator voltage to 236 kV. The connections between thegenerator transformers high voltage terminals and the associated switching bayin the 220 kV switchyard will be by overhead lines anchored at the staion andto the station building wall. The generator transformers will be rated at 300MVA ON/OB/OFB cooled, 900 kV BIL. The high voltage windings will have gradedinsulation and the neutral will be solidly earthed. Lightning arrestors willbe provided near the generator transformers, connected to the high voltageterminals. (ii) 220 kV Switchyard: A 220 kV switchyard with two main and oneauxiliary bus will be provided. A total of ten 220 kV bays will be providedin the 220 kV switchyard. These will provide for two generator transformercircuits, 4-220 kV lines, 2-start up transformer bays and transfer-bus couplerbays. Adequate protection gear, monitoring and metering system shall be

provided.

-56-

Annex 3.1Page 9 of 12

B. Dahanu - Licence Area Transmission Lines and Substations

37. To evacuate power generated at the TPS, two double circuit 220 kVtransmission lines are planned. The length of each line from Dahanu TPS tothe receiving stations in area of supply would be about 105 km. Threereceiving stations 220 kV/33 kV are proposed at Ghodbunder, Malawani andVersova in area of supply. For start up supply from MSEB, one of the fourcircuits will be looped in and out at 220 kV substation of MSEB at Boisar(near Tarapur). Salient features are given below:

i) The design permits outage of one circuit for maintenance withoutloss of transmission capacity.

ii) The lines will be constructed with galvanised lattice structuresand All Aluminium Alloy Conductors (AAAC) to avoid corrosion dueto saline coastal atmosphere. The size of conductor will beequivalent to ACSR "Zebra".

iii) The Transmission Line Towers will be as per IS-802 and will takeinto account Security Class, Gust Response Factors, TerrainCategory, etc.

iv) One line before reaching Ghodbunder will be looped in and out atthe Boisar 220 kV substation owned by the Haharashtra StateElectricity Board. Boisar substation is at a distance of 20 kmsfrom Dahanu thermal power station and is also inter-connected witlTarapur power station and rest of the MSEB network. The inter-connection from Boisar will be utilized for start-up power forDahanu thermal power station.

v) The lines will enter into ISES's licence area of supply at thenorthern tip, i.e. at Ghodbunder and terminate at central pointVersova.

vi) The terrain of the line route is plain. Lines will cross riversat four locations and creeks at three locations.

vii) The lines pass through notified forest area over a distance of 2.8kms. A corridor of 35 meters has to be provided for each line.The area involved in reserved forest for right of way is 20hectares. However, this portion does not involve any treecutting. BSES has already applied to the forest authorities forpermission to construct the lines through the forest area; theforest authorities require equivalent non-forest land to be handedover to them for the purpose of afforestation in lieu of forestland affected by the lines. Such non-forest land has beenidentified and land is being procured.

-57-

Annex 3.1Page 10 of 12

viii) There will be three 220 kV/33 kV Receiving Stations withtransformer capacities as given belows

Ghodbunder 2 x 100 MVA - 200 HVA (220/33 kV)Malawani 2 x 100 MVA * 200 MVA (220/33 kV)Versova 3 x 100 MVA - 300 HVA (220/33 kV)

2 x 200 MVA - 400 HVA (220/110 kV)

ix) Ghodbunder and Malawani each will have 8 Nos. of 220 kV bays, viz.

Incoming 2 Nos.Outgoing 2 Nos.Transformer 2 Nos.Bus Coupler 1 No.Transfer Buis Coupler 1 No.

x) Versova will have 11 Nos. of 220 kV and 7 Nos. of 110 kV bays asunder:

220 kV 110 kV

Incoming 4 Nos. 2 Nos.Outgoing -- 4 Nos.Transformer 5 Nos. --

Bus Coupler 1 No. 1 No.Transfer Bus Coupler 1 No. --

Space will be kept for spare bays for future expansion.

xi) The Receiving Stations would have outdoor equipment for 220 kV and110 kV but 33 kV controlling breakers would be indoors. The SF6switchgear of 40 kA short circuit capacity with the ratedcontinuous current of 2500 Amps. and 1250 Amps. would be used for220 kV and 110 kV, respectively.

xii) The 220 kV busbars would be sectionalized main and transfer bus.The 110 kV busbars would be only sectionalized bus, while the 33kV busbars would be indoor single sectionalized.

xiii) 33 kV outlets would be through underground cables.

C. Strengthening and Development of BSES Subtransmission and DistributionSystems

38. Distribution transformer capacity will be augmented by 346 MVA to 1,025MVA by PY96. BSES's 33 kV subtransmission lines and 11 kV and 0.4 kVdistribution networks will also be strengthened and developed accordingly.The delivery of the distribution equipment being of the order of six months,distribution development will be defined on annual basis.

-58-

Annex 3.1Page 11 of 12

D. Flue Gas "osulphurization Unit at Dahanu Power Plant

39. GOI, GOM and MPCB stipulated that an FGD plant with 90? efficiencyshould be built in accordance with timetable to be in operation when the powerplant units are commissioned. Due to the low sulphur content of the Indiancoal and 275 meter high stack being built, the project would comply with GOI,GOM and World Bank Group standards and guidelines, without an FGD plant. Inview of available data, GOM agreed to amend its clearance. GOI is stillreviewing the issue. If GOI also amends its clearance, IBRD and IFC would nothave any objection. If GOI does not amend its environmental clearance, BSESmight build an FGD unit which uses the Seawater Process developed by Flakt(Norway). A smaller unit was built in 1988 by TEC based on the know-howobtained from Flakt at their Trombay power plant. This plant has beenoperating successfully since its commissioning in March 1988.1

40. Flue gases from the existing discharge fan are conveyed to a concretescrubber using a booster fan. Inside the scrubber, the gases flow countercurrent to seawater. Sulphur dioxide is absorbed due to the naturalalkanility of the seawater and clean flue gases leave the top of the scrubberat approximately 4 0C. They are then mixed with part of the raw gases in areheat mixer. The reheated gases at 57 'C exit through the existing 275 mtall stack. Seawater required for absorption is provided from the condensercooling water system seal well, by a siphon system to a distribution chamber.It is them pumped to the top of the scrubber. Acidic liquor from the scrubberflows by gravity into a mixing chamber located near the seal well, where itmixes with excess seawater again drawn from the seal well and then overflowsinto the aeration basin. In order to bring the quality of this effluentwithin the permissible limits, the effluent is aerated by supplying air withthe help of aeration fans and aeration grid. The treated effluent is thendischarged to the Dahanu creek. In order to have gases leaving the stack athigher temperatures, resulting in higher plume rise and less condensation ofacidic water in ducts and stack, the clean gases exiting the scrubber would beheated to 45 °C by using the heat content of the raw flue gas to reheat theclean gases from the scrubber by installing a regenerative heat exchanger.

In May 1988, prior to obtaining satisfactory operational resultsof the Flakt Seawater FGD technology, TEC had Tata ConsultingEngineers (TCE) carry an economic comparison between FlaktSeawater System and the ammonia process (the latter process usesammonia liquor for scrubbing of flue gas and the know-how isprovided by Krupp-Koppers (Germany); ammonia sulphate is abyproduct produced as a saleable fertilizer). TCE's conclusionwas that the seawater and ammonia systems would be comparable innet annual operating costs, if ammonia was made available to TECwith a subsidized price as applicable to fertilizer units.Following the satisfactory operating performance of the initialseawater based stream, TEC opted for its expansion. The BankGroup agreed with this decision and included the expansion of theFGD unit at Trombay in the joint IBRD/IFC Private Power Utilities(TEC) Project.

-59-

Annex 3.1Page 12 of 12

The raw gas, after being cooled in the regenerative heat exchanger, would beconveyed to the scrubber by using a booster fan. The existing pipeline totransfer scrubber liquor from the scrubber to the mixing chamber of theaeration basin would be adequate for the increased flow rate.

41. The design basis for the installation of the proposed FGD stream will bedetermined by BSES's consultants. BSES will reconfirm that the salinity ofthe water is adequate for the application of the Flakt Sea Water Technology.

-60-

Annex 3.2INDIA ..

Page 1 of 5PRIVATE POWER UTILITIES CBSES) PROJECT

Project Cost Summ4ry

Project Components Local Foreign Total Local Foreign Total~~~~~~~~~~~~~~~~....... ........... ....... .......... ....... .......... _ ....... ..............

-- -Re. million --- ----- USS miltion-......2x250 MW Dahanu Thermal Power Station............ .........................

A. Main Package1. Boiler Equipment 926.2 778.1 1704.3 48.7 41.0 89.72. Control and Instrumentation 111.4 96.4 207.8 5.9 5.1 10.93. Turbo-Generator Equipment 705.7 670.1 1375.8 37.1 35.3 72.4

4. Supervisory Services 46.3 0.0 46.3 2.4 0.0 2.4S. Civil Design and Services 25.7 0.0 25.7 1.4 0.0 1.46. Spares 245.6 0.0 245.6 12.9 0.0 12.9

...... ...... .. ...... ...... .. ...... ................... ......... ...

Sub-Total 2060.9 1544.6 3605.5 108.5 81.3 189.8

S. MechanicaL Equipment1. Ash Handling Plant 27.9 83.2 111.1 1.5 4.4 5.82. Coal Handling Plant 93.0 277.4 370.4 4.9 14.6 19.53. Cooling Water System 21.7 64.7 86.4 1.1 3.4 4.54. Chimney Stack Liner 2.5 7.6 10.1 0.1 0.4 0.55. Environmental Monitoring 5.9 17.6 23.5 0.3 0.9 1.26. Misc. Mechanical Equipment 29.8 99.2 129.0 1.6 5.2 6.87. Fuel Oil Handling Plant 43.2 0.0 43.2 2.3 0.0 2.38. Water Treatment Plant 131.2 0.0 131.2 6.9 0.0 6.9

...... ...... . ... ...... ...... ------ ................. ...

Sub-Total 355.2 549.7 904.9 18.7 28.9 47.6

C. Electrical Equipment1. Bus Duct 30.9 0.0 30.9 1.6 0.0 1.62. Transformers 46.5 138.7 185.2 2.4 7.3 9.73. Switch Yard (Oahanu) 10.8 32.3 43.1 0.6 1.7 2.3

Sub-Total 88.2 171.0 259.2 4.6 9.0 13.6

D. Erection1. Ash Handling Plant - Erec. 4.6 0.0 4.6 0.2 0.0 0.22. Coal Handling Plant- Erec. 11.4 0.0 11.4 0.6 0.0 0.63. Ccoling Water System-Erec. 14.9 0.0 14.9 0.8 0.0 0.84. Water Treatment Plant-Erec. 3.5 0.0 3.5 0.2 0.0 0.25. Bus Duct Erection 2.3 0.0 2.3 0.1 0.0 0.16. C & I Erection 9.2 0.0 9.2 0.5 0.0 0.57. TG Erection 23.1 0.0 23.1 1.2 0.0 1.28. Boiler Erection 98.2 0.0 98.2 5.2 0.0 5.29. Fuel Oil Hand. Pl. Erection 3.5 0.0 3.5 0.2 0.0 0.210. Cable Laying 9.2 0.0 9.2 0.5 0.0 0.511. Switchgear Erection 9.2 0.0 9.2 0.5 0.0 0.512. Switch Yard Erection 11.5 0.0 11.5 0.6 0.0 0.613. Transformer (P/S) Erection 4.6 0.0 4.6 0.2 0.0 0.2

...... ...... .. ...... ...... ... ...... ................. ........ ...

Sub-Total 205.2 0.0 205.2 10.8 0.0 10.8

E. Civil Works1. Ash Handling Plant - C.U. 16.1 0.0 16.1 0.8 0.0 0.82. Coal Handling Plant- C.W. 55.1 0.0 55.1 2.9 0.0 2.93. Cooling Water System-C.W. 50.5 0.0 50.5 2.7 0.0 2.74. Water Treatment Plant-C.W. 14.9 0.0 14.9 0.8 0.0 0.8S. Chimney 63.5 0.0 63.5 3.3 0.0 3.3

6. Piling 53.2 0.0 53.2 2.8 0.0 2.87. Railway Siding 167.0 0.0 167.0 8.8 0.0 8.8

8. Colony 57.8 0.0 57.8 3.0 0.0 3.09. Land Develop- 77.9 0.0 77.9 4.1 0.0 4.1

10. Misc. Buildinc. 150.1 0.0 150.1 7.9 0.0 T.911. Foundations 75.1 0.0 75.1 4.0 0.0 4.0

...... ...... ...... ...... ...... ......

Sub-Total 781.2 0.0 781.2 41.1 0.0 41.1

-61-

Anex 3.2

Page 2 of 5

Project Components Local Foreign Total Local Foreign Total........................ ------- ........... ....... . ... ............ ....... .............. .....................

-- -Rs. million ----- ---USS million-------

F. Other Equipment1. 6.6 kV Swltchgear 42.3 0.0 42.3 2.2 0.0 2.22. LT Switchgear 35.4 0.0 35.4 1.9 0.0 1.93. LT & NT Cables 117.9 0.0 117.9 6.2 0.0 6.24. Switch Yard CDahanu) 11.8 0.0 11.8 0.6 0.0 0.65. Illumination (S & E) 49.5 0.0 49.5 2.6 0.0 2.66. LP Piping 53.3 0.0 53.3 2.8 0.0 2.87. Misc. Mechanical Systems 53.5 0.0 53.5 2.8 0.0 2.88. Misc. Tool & Plant 94.3 0.0 94.3 5.0 0.0 5.0

... .. . ...... ...... ----- _ ...... ... .... ....... .... ...

Sub-Total 458.0 0.0 458.0 24.1 0.0 24.1

G. Lard, Training, Etc.1. Fresh Water 73.6 0.0 73.6 3.9 0.0 3.92. Training 11.5 0.0 11.5 0.6 0.0 0.63. Establishment 178.0 0.0 178.0 9.4 0.0 9.44. Land Cost 29.2 0.0 29.2 1.5 0.0 1.5S. Consultancy 29.5 0.0 29.5 1.6 0.0 1.6

. ...... ........... ...... ...... ........ ......

Sub-Total 321.8 0.0 321.8 16.9 0.0 16.9

total Base Costs (1) 4270.5 2265.3 6535.8 224.8 119.2 344.0VZOAZZ MMUZ3 3anana ===3n= =c3ca3 3=3=33

- Physical Contingencles 314.0 113.2 427.2 16.5 6.0 22.5- Price Contingencies 800.9 546.9 1347.8 9.4 10.9 20.3

...... ...... .. ...... ...... ... ...... ...... ........ .............

Total Contingencies 1114.9 660.1 1775.0 25.9 16.9 42.8

Total Project Cost (1) 5385.4 2925.4 8310.8 250.7 136.1 386.8533333 33a533 =33=33 =D==3 at==== 3====5

- Taxes and Duties (2) 542.5 0.0 542.5 25.3 0.0 25.3- Transport and Erection (2) 415.0 0.0 415.0 19.3 0.0 19.3=3==35=33333 3333333333333333333331-33533-33533533833

Flue Gas Desulphurization Unit.... ........... .....................

Base Costs t1) 270.8 283.0 553.8 14.0 14.9 28.9

- Physical Contingencies 16.0 17.0 33.0 0.8 0.9 1.7- Price Contingencies 72.0 76.0 148.0 1.2 1.2 2.4

...... ...... .. ...... ...... ... ...... ........ .................. ...

Total Contingencies 88.0 93.0 181.0 2.0 2.1 4.1

Total Project Cost (1) 358.8 376.0 734.8 16.0 17.0 33.0=3353 3a333= 333383 ca3ncan 3a33a3 53335

- Taxes and Duties (2) 116.3 0.0 116.3 5.4 0.0 5.4- Transport and Erection C2) 36.7 0.0 36.7 1.7 0.0 1.733533 3333353333333333Z533333383333333335sst33:3333 as5a3,333353

33

3a-3

53al-a- -

3-

2 35

2x250 Mu Oahanu Thermal Power Station([net. Flue Gas Desulphurizatfon Unft)

Total Base Costs t1) 4541.3 2548.3 7089.6 238.R 134.1 372.9

- Physical Contfngenfets 330.0 130.2 460.2 17.3 6.9 24.2- Price Contingencies 872.9 622.9 1495.8 10.6 12.1 22.7~~~~~~...... ........ ...... ........ ...... ......

Total ContIngencies 1202.9 753.1 1956.0 27.9 19.0 46.9

Total Project Cost (1) 5744.2 3301.4 9045.6 266.7 153.1 419.8M33333 33s333 3B3335 333353 333333 3a5333

- Taxes and Duties (2) 658.8 0.0 658.8 30.7 0.0 30.7- Transport and Erection (2) 451.7 0.0 451.7 21.0 0.0 21.0

-62-

Armex 3.2

Page 3 of 5

Project Components Local Foreign Total Local Foreign Total.......... ........ ....... .... .... ...... . . .... ... .... .... .. ..... .

-------Re. million ...... ------- lUS mitton.-------Transmission Lines and Receiving Stations

A. Equipment1. Transmission Line Towers 41.4 129.4 170.8 2.2 6.8 9.02. Hardwares and Conductors 38.5 120.2 158.7 2.0 6.3 8.43. Rec. Stations Switchyards 31.1 97.0 128.1 1.6 5.1 6.74. Rec. Stations Transformers 29.6 92.4 122.0 1.6 4.9 6.45. Rec.Statfons Switchyard 41.6 0.0 41.6 2.2 0.0 2.26. Rec.Stations Nisc. Equipment 7.0 0.0 7.0 0.4 0.0 0.4

... . ... . .. .. . . . . ... ... .

Sub-Total 189.2 439.0 628.2 10.0 23.1 33.1

B. Rec. Station Land Cost 115.5 0.0 115.5 6.1 0.0 6.1

C. Civil Works1. Rec.Stations Build. & Colony 17.3 C.0 17.3 0.9 0.0 0.92. Rec.Stations Foundations 23.1 0.0 23.1 1.2 0.0 1.2

.. .. . . . . . .. ... . . . . - - -

Sub-Total 40.4 0.0 40.4 2.1 0.0 2.1

D. Erection1. Rec.Sta. Transformers-Erect. 7.0 0.0 7.0 0.4 0.0 0.42. Rec.Sta. S/yard-Erection 34.7 0.0 34.7 1.8 0.0 1.83. Transmissfon Line Erection 49.7 0.0 49.7 2.6 0.0 2.6

Sub-Total 91.4 0.0 91.4 4.8 0.0 4.8

Total Base Costs tl) 436.5 439.0 875.5 23.0 23.1 46.13=333 Mc3an3 =3333 =3333 3_nc==3 3a==3=

- Physical Contingencies 33.0 22.0 55.0 1.7 1.2 2.9- Price ContingencIes 81.9 106.0 187.9 0.9 2.2 3.1

Total ContingencIes 114.9 128.0 242.9 2.6 3.4 6.0

Total Project Cost t1) 551.4 567.0 1118.4 25.6 26.5 52.1333w 333333 3333s 3=3333 3333 C33===

- Taxes and Duties (2) 178.2 0.0 178.2 8.3 0.0 8.3- Transport and Erection (2) 56.0 0.0 56.0 2.6 0.0 2.6

Distribution

1. Bulk Trans. & Switchgears 127.6 0.0 127.6 6.7 0.0 6.72. Subtransmissfon 221.2 0.0 221.2 11.6 0.0 11.63. 11 kV DistributiOn 153.9 0.0 153.9 8.1 0.0 8.14. Dlstr. Substation Equipment 102.0 0.0 102.0 5.4 0.0 5.45. Low Tension DistributiOn 247.4 0.0 247.4 13.0 0.0 13.06. St.Lightirn & MIsc.Works 247.4 0.0 247.4 13.0 0.0 13.0

Total Base Costs (1) 1099.6 0.0 1099.6 57.9 0.0 57.9

- Physical Contingencies 63.7 0.0 63.7 3.4 0.0 3.4- Price Contingencies 112.7 0.0 112.7 1.0 0.0 1.0

Total ContIngencies 176.4 0.0 176.4 4.4 0.0 4.4

Total Project Cost (1) 1276.0 0.0 1276.0 62.2 0.0 62.23333-3 .-- 333 333333 * 33-m3 333333 3s3333

- Taxes and Duties (2) 69.7 0.0 69.7 3.4 0.0 3.4- Transport and Erection (2) 64.0 0.0 64.0 3.1 0.0 3.1

-63-

Annex 3.2

Page 4 of S

Project Corponents, Local Foreign Total Local Foreign Total---------- ---- ------- ....... . .... ....... ........... .......

-------Rs. million ------- -------USS million-------

TOTAL PROJECT COST

Base Costs

2x250 Mu Dahanu Thermal Power Station 4270.5 2265.3 6535.8 224.8 119.2 344.0

Flue Gas Desulphurization Unit 270.8 283.0 553.8 14.0 14.9 28.9

Transmission Lines and Receiving Station 436.5 439.0 875.5 23.0 23.1 46.1

Distribution 1099.6 0.0 1099.6 57.9 0.0 57.9

Total Base Costs (1) 6077.4 2987.3 9064.7 319.6 157.2 476.8_===== === === 333=== ====== ====== =C

- Physical Contingencies 426.7 152.2 578.9 22.4 8.0 30.4- Price Contfngencies 1067.5 728.9 1796.4 12.5 14.3 26.8

Total Contingencies 1494.2 8P1.1 2375.3 34.9 22.3 57.2

Total Project Cost (1) 7571.6 3868.4 11440.0 354.5 179.5 534.1

Working Capital Margin andDebenture Issue Expenditures 270.0 0.0 270.0 12.6 0.0 12.6

Interest During Construction 932.0 1358.0 2290.0 43.4 63.2 106.6

Total Financing Requirements 8773.6 5226.4 14000.0 410.5 242.7 653.3

-Taxes and Duties (2) 906.7 0.0 906.7 42.3 0.0 42.3- Transport and Erection (2) 571.7 0.0 571.7 26.7 0.0 26.7

Total Base Costs excl. Taxes & Duties 5170.7 2987.3 8158.0 277.3 157.2 434.533333= 333333 =3=33s Bs33=== S =3=3 3=;=3=

Total ;.,ntingenefes 1494.2 881.1 2375.3 34.9 22.3 57.2

Working Capital Margin andDebenture Issue Expenditures 270.0 0.0 270.0 12.6 0.0 12.6

Interest During Construction 932.0 1358.0 2290.0 43.4 63.2 106.6~~~~~~~~~ ....... ... ... ...... ..... . ...... ......

Total Project Costs excl. Tax. & Dut.,but including Interest During Const. 7866.9 5226.4 13093.3 368.2 242.7 610.9

(1) Including Taxes and Duties and Transport and Erection expenses as given below.

(2) Included in Base Costs.

-64-

Arnex 3.2Annual Investments ------------------------------ Page 5 of 5

Project Components FY91 FY92 FY93 FY94 FY95 FY96 Total---------- . ...................... ----- .. .... . ----- -------.... ---- ---

-------------------------Rs. million-------------------------2x250 KW Dahanu Thermal Power Stationand Trans. Lines and Receiving Stations 680.0 970.0 2250.0 3050.0 1540.0 939.2 9429.2

Flue Gas Desulphurization Unit 0.0 0.0 100.0 319.8 255.0 60.0 734.8

Distribution 226.0 240.0 250.0 260.0 300.0 0.0 1276.0.......... ....... ........... ....... ........... ------- ....... .................

Total Costs, inct. Contingencies (1) 906.0 1210.0 2600.0 3629.8 2095.0 999.2 11440.0&==&=c = ==== = ====== = = Z= ======

Working Capital Margin andDebenture Issue Expenditures 0.0 70.0 0.0 0.0 200.0 0.0 270.0

Interest During Construction 0.0 410.0 520.0 645.0 715.0 0.0 2290.0........ ...... ------... .. .. .. -- -- ------ ..........

Total Financing Requirements 906.0 1690.0 3120.0 4274.8 3010.0 999.2 14000.0cm=o== c1=s= *U===== == ==& Common ==-a ===a==

Project Coqmonents FY91 FY92 FY93 FY94 FY95 FY96 Total---------- . ... ..... .. ...... . ------- .......... ....... ........... ------- .......... .. .

---------------------------USS million-------------------------2x250 MW Dahanu Thermal Power Stationand Trans. Lines and Receiving Stations 34.3 47.4 107.2 140.7 68.8 40.5 438.9

Flue Gas Desulphurization Unit 0.0 0.0 4.8 14.3 11.3 2.6 33.0

Distribution 11.9 12.2 12.3 12.3 13.6 0.0 62.2....... -------... ....... ........... ....... ........... ....... ...... ...................

Total Costs, inct. Contingencies (1) 46.2 59.6 124.3 167.3 93.7 43.1 534.1

Working Capital Margin andDebenture Issue Expenditures 0.0 3.3 0.0 0.0 9.3 0.0 12.6

Interest During Construction 0.0 19.1 24.2 30.0 33.3 0.0 106.6Totl F g Rs....... ....... 8 . ...... ....... 1 . . ..... ....... .......

Total Ffnancing Requirements 46.2 82.0 148.5 197.3 136.3 43.1 653.3*SffzcD C-lm common commont common =aC== commn cmmo

INDIA

PRIVATE POWER UTILITIES (BSES) PROJECT... ........ ..................................

PROJECT IMPLEMENTATION SCHEDULE

... .... ... .... .... ... ... .. . . . . . . . . . .

: 1,990 : 1991 : 1992 : 1993 1994 : 1995................... ......................................... ........ ................ ..................................... ..

Project Cooponent and Activity : 1 2 1 3 1 4 : 1 2 1 3 1 4 : 1 2 1 3 1 4 :1 1 2 1 3 1 4 : 1 2 1 3 1 4 : 1 2 1 3 1 4:*------------------------ *--------- -- - I---I- I--- *.I---I---;.. . I---I....--I.. --- I.. --- I---. I--- -- I...------ 1 § :

: I I I S:BOAI I I I I I I I : I I I I IPilirng d Fourdations : I I I I I I I I I

: I I I : I S IB 01 A: I I I : I I I : I I I : I I IGeneral Civil Works I I I : inminmsininmininu=.m==:=========ininm i I i

:. I I I : I S IB OI A: I I I : I I I : I I I : I I IChimney I I I I

: I I OI R :A I I N : I IN/El : I I IE/T:/L I I TIIL: I I ISteam Generator : inmmmm===inm ==1 1

:8 I O I R :A I I " I : I IN/EI E: I I I :E/TI/L la TI/L :b I I ITurbo Generator : mzmmminminmummm====m=m=n====min:m I I

:B I I O R :A I INI : I I I E: I I I :E/TI/L I TI/L: I I IControl and Instruientation : I=in=== n== = … m===a====-===m== m t I

:B I I O R A I I " : I I I E: I I I :E/TI/L I TI/L: I I IPower Cycle Piping :==========s===========m===mm==m==mm==m======-============================== I I I

: I I I : IS B I A: I I I E: I I I :T I El/TI : I I I ILow Pressure Piping : I I I : I============a=i=-=n==== === ===-===== : I I I : 0'

: I I I :S IB IO IA : I I I : I I I :E/TI I T/L: I I ICoal HaNrdling Ptant : I I I : = === ===3 - 1 I I

: I I I :S I OIA : I I I : I I I :E/TI I TI/L: I I IAsh Handling Plant : I I I : == n Qnina=======3==c S I I I

: I I I :S IB O IA: I I I E: IT/LI I : I I I : I I IWater Treatment Plant : I I I : = = = - ========= 1 I : I I I : I I I

: I I I :S 19 10 IA: I I I E: IT/LI I : I I I : I I IFuel Oit Hardling Plant : I I I :w= urn. u ===3u ====:z= I I : I I I : I I I

: I I I : SBIO I IA: I I I :C I I I :T/PI I TI/L: I I ICooling Water System : I I I : a= 3=3 = =Da=3 1 3 I

: I I I : I S 1 : A I I I : I I I :El/T I I : I I ICoal Bunker : I I I I I ============m=====m: ==========1 1 I I I

: I I I ISI B I IA I I IE I :T IE IT I : I I IGenerator Transformers : I I I === == z====== --=: s=:.as:3 =3 I I I I

: I I I :SI 8 I O IA : I I I E: IE/TI I E:/T I I I : I I IOther Transforuers : I I I : u= 3= 3= srnin3= u3====I I I : I I I

: I I I :SIB OfA : I I I E: I I E/IT/L: TI/L I I : I I I6.6 kV Switchgear : I I I : =I===I I================ =========I== I I : I I

I I I :SI B IO IA: I I I E: I I E/IT/L: TI/L I I : I I ILT Switchgear : I I I : :3::s3= m 3= = g I I I

: I I I : I I S :B 01 Al I :El I E/IT/L: TI/L I : I I IBus Duct : I I I : I I I 3 2 3= 3 3 3= .u 3 =l I ; I I I

: I I I : I I I S: B10 IA I E: I I E/IT: IE/TI I : I I ICables I

: I I I : SBI O IA I : I I I E: IE/TI IT : I I i : I I I XSwitchyard Equipments . I I I I I I

: I I IS B: O IA : IN/Cl I : I I IE/T: I I I : I I I :Transmission Lines I I Isc33= ins3==== == - : I I I :

: I I I : I I I : ISBOIA I : I I I :E I I I T: I I IFlue Gas Desutphurization Unit : I I I : I I I : I= - I I I. ................... .......................................... .............. .............................. ..................................................................................................................

LEGENDS: S: Engineering and Specification; 0: opening of Bids; N: Manufacturing and DeliveryR: Wortd Bank Review A: Award of Contract E: Erection L: TrialB: Bidding C: Construction T: Testinga: Unit I - Synchronization b: Unit 2 - Synchronization Co: Commercial Operation

-66-

Annex 3.4Page 1 of 2

INDIA

PRIVATE POWER UTILITIES (BSES) PROJECT

Engineering and Management Consultants Employed by BSES

BSES would be responsible for implementing the Dahanu thermal powerplant and the associated transmission and distribution development, with theassistance of consultants. BSES has signed contracts with the followingconsulting firms:

(a) Development Consultants Limited (DCL) of Calcutta as "mainconsultants", for the design, engineering, procurement assistance,design office based project management for the power plant;

(b) National Thermal Power Corporation (NTPC) of New Delhi as "reviewconsultants" for the power plant, to draw on NTPC's practicalexperience in the design, construction management, testing,commissioning and quality assurance. NTPC have also been responsiblefor ensuring conformity to tendering requirements of IBRD;

(c) NTPC (under separate contract) for the design and engineering of thetransmission lines and associated substations, including relatedprotection and communication systems;

(d) BHEL for the fulltime monitoring of supervision activities at theDahanu TPP, including planning and monitoring, material management,construction management, quality assurance, monitoring of inspectionactivities and results, commissioning management, monitoring ofutilization of resources including manpower and costs);

(e) RITES for the feasibility study, design, engineering and constructionmanagement for the railway siding and railway and road bridges;

(f) Tata Consulting Services (TCS) for the study of options to reorientBSES from a distribution company to a full fledged power utility,including financial, commercial, personnel, management information,material management systems;

(g) Central Water and Power Research Station (CWPRS) of Pune for thedesign of the circulating water systems, in order to minimize andmitigate the environmental impact of the cooling water on the DahanuCreek and its confluents;

(h) GOM Irrigation Department for the design and engineering of the freshwater pipeline;

(i) CMPDT, Ranchi, for the feasibilty study of beneficiation of theallocated coal;

-67-

Annex 3.4Page 2 of 2

(j) The Salim Ali School of Ecology of the University of Pondicherry forenvironmental related issues, especially those concerningagricultural impact;

(k) NEERI for the study of the aquatic systems of the Dahanu creek andits arms; and,

(1) STUB for the architechtural design of the power plant buildings andthe colony.

BSES will also appoint a separate agency for the inspection of material andequipment to be delivered by various manufacturers. All the consultants and thearrangements are acceptable to IBRD and IFC.

-68-

Annex 3.5INDIA

Page 1 of 3PRIVATE POWER UTILITIES (BSES) PROJECT

Procurement Arrangements

(USS millions) a/

ICB LC8 Other N.A. Total Cost

Contract I1RD Contract IRRO Contrect IBRD Contract Contract IBRDProject Components Value Finance Value Finance Value Finance Value Value Finance........ .......... ..... .. ...... .... ... .... ---- ....... ....... ....... ..... ......... ...... .

2x250 WU Dahanu Thermal Pcwer Station,................................

A. Main Package 206.4 196.0 206.4 196.0(Boiler Equipment. Control andInstrumentation, Turbo-Gen.Equipment, Supervisory Serv.,Civil Design and Services)

B. Mechanical Equipment 5.0 4.0 5.0 4.01. Ash Handling Plant 6.6 6.62. Coat Handling Plant 21.9 21.93. Cooling Water System 5.1 5.14. Chimney Stack Liner 0.6 0.65. Environmental Monitoring 1.4 1.46. Misc. Mechanical Equipment 7.1 7.17. Fuel Oil Handling Plant 2.4 2.48. Water Treatment Plant 7.2 7.2

, ........ ...... .......... ...... ------.... ...... .......... ----. -..... ...... ..

Sub-Total 0.0 0.0 5.0 4.0 52.3 0.0 0.0 57.3 4.0

C. Electrical Equipment1. Bus Duck 1.7 1.72. Transformers 11.0 11.03. Switch Yard (Dahanu) 2.4 2.4

............... ......... ...... ......... ...... ------... ...... ...... ...........

Sub-Total 0.0 0.0 0.0 0.0 15.1 0.0 0.0 15.1 0.0

D. Erect sn 12.4 12.4

E. Civil Works 49.6 49.6

F. Other Equipment1. 6.6 kV Switchgear 2.4 2.42. LT Switchgear 2.0 2.03. LT & NT Cables 6.8 6.84. Switch Yard (Dahanu) 0.7 0.75. Illumination CS & E) 2.8 2.86. LP Piping 3.1 3.17. Misc. Mechanical Systems 3.1 3.18. Misc. Tool & Plant 5.4 5.4

.. ... ...... ......... ........ ...... ......... ...... ......... ...... ...... ......... ......

Sub-Total 0.0 0.0 0.0 0.0 26.3 0.0 0.0 26.3 0.0

G. Land, Training, Etc.1. Fresh Water 4.5 4.52. Training 0.6 0.63. Establishment 9.9 9.94. Land Cost 2.0 2.0S. Consultancy 2.7 2.7

...... ...... ... ...... ...... ...... ... ...... ...... ... ...... ......... ..... .. ...... .........

Sub-Total 0.0 0.0 0.0 0.0 7.8 0.0 11.9 19.7 0.0

H. Flue Gas Desulphurfzation Unit 33.0 33.0

Project Total Cost (Dahanu TPP) 206.4 196.0 5.0 4.0 196.5 0.0 11.9 419.8 200.0Suza3n UaUos3 mammon mammon *Numan =uUI=U noncom *oUUUW noco

-69-

Annex 3.5. ... ,... ...

Page 2 of 3

ICe LCB Other N.A. Total Cost

Contract IBRD Contract IBRD Contract 10RD Contract Contract IBRDProject Components Value Finance Value Finance Value Finance Vatue Value Finance

Transmission Lines and Receiving Stations..̂ ....... .............. ....................

A. Equipment1. Transmission Line Towers 10.0 10.02. Hardwares and Conductors 9.3 9.33. Rec. Stations Switchyards 7.7 7.74. Rec. Stations Transformers 7.5 7.55. Rec.Stations Switchyard 2.5 2.56. Rec.Stations Misc. Equipment 0.6 0.6

,,.,.. ..., ....... ....... .......... .. . ... ...... ...... ......... ...... ...........

Sub-Total 0.0 0.0 0.0 0.0 37.6 0.0 0.0 37.6 0.0

B. Rec. Station Land Cost 6.7 6.7

C. Civil Works 2.3 2.3

D. Erection 5.5 5.5. ...... ......... ....... ......... ...... ............ ...... .. ..... ........ ...

Project Total Cost (Tr.Lines & S/S) 0.0 0.0 0.0 0.0 45.4 0.0 6.7 52.1 0.0

Distribution.. _..........

1. Bulk Trans. & Switchgears 7.2 7.22. Subtransmission 12.5 12.53. 11 kV Distribution 8.7 8.74. Distr. Substation Equipment 5.8 5.85. Low Tension Distribution 14.0 14.06. St.Lighting & Misc.Works 14.0 14.0

. ..... ...... ...... ...... ...... ...... ...... ...... ......

Project Total Cost (Distribution) 0.0 0.0 0.0 0.0 62.2 0.0 0.0 62.2 0.0===C== ===^= ====a= == u unsuz ===a cmmo =CU= ==am=

TOTAL PROJECT COST 206.4 196.0 5.0 4.0 304.1 0.0 18.6 534.1 200.0

IFC Finance t 68.0) ( 68.0)Grant C 0.3) C 0.3)

-70-

Annex 3.5

Pale 3 of 3

ICe LCB Other N.A. Total Cost................. ......................................... ................. .......................... .............. .................

Contract I1RO Contract 91RD Contract IBRD Contract Contract 18RDProject Corponents Value Finance Value Fi'snce Value Finf nce Value Value Finance

Total Project Cost by Summary Accounts

2x2SO MW Dahanu Thermal Power Station.....................................

-Civil Works 0.0 0.0 0.0 0.0 49.6 0.0 0.0 49.6*Equipment 200.0 190.6 5.0 4.0 131.2 0.0 ^.0 336.2 194.6-Erection 0.0 0.0 0.0 0.0 12.4 0.0 0.0 12.4-Supervisory Services 6.4 5.4 0.0 0.0 0.0 0.0 0.0 6.4 5.4-Training and Consultancy 0.0 0.0 0.0 0.0 3.3 0.0 0.0 3.3-Administrative Services 0.0 0.0 0.0 0.0 0.0 9.9 9.9

Land 0.0 0.0 0.0 0.0 0.0 2.0 2.0...... ...... .. ...... ...... ... ...... ...... ... ...... ............ ......_..... .................. ...

TOTAL PROJECT COST -- Dahanu TPP 206.4 196.0 5.0 4.0 196.5 0.0 11.9 419.8 200.0sa33a3 .3.333 Manaus 333s33 M...33 Maca33 ...... 3 338

Transmission Lines and Receiving Stations.................. .............................. ..... ................

Civil Works 0.0 0.0 0.0 0.0 2.3 0.0 0.0 2.3 0.0* Equipment 0.0 0.0 0.0 0.0 37.6 0.0 0.0 37.6 0.0- Erection 0.0 0.0 0.0 0.0 5.5 0.0 0.0 5.5 0.0- Training and Consuttancy 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0- Administrative Services 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

-Land 0.0 0.0 0.0 0.0 0.0 6.7 6.? 0.0,........ ...... ....... .... ........ ...... ........ ...... ......... .......... ......... ....... ...

TOTAL PROJECT COST -- Tr.Lines+S/S 0.0 0.0 0.0 0.0 45.4 0.0 6.7 52.1 0.0

Distribution..........

-Civil Works 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0-Equipment 0.0 0.0 0.0 0.0 62.2 0.0 0.0 62.2 0.0-Erection 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0-Training and Consultancy 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0-Administrative services 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Land 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0...... ...... .. ...... ...... ... ..... .. ..... ...... -........ ..... .. ..... ..... ............... ......... ...

TOTAL PROJECT COST -- Distribution 0.0 0.0 0.0 0.0 62.2 0.0 0.0 6.2 0.0nC=s"s cancSs =anon= =cgan= *-ms saa_- IMMUCU SMIZ

PROJECT TOTALS..............

-Civil Works 0.0 0.0 0.0 0.0 51.9 0.0 0.0 51.9 0.0Equipment 200.0 190.6 5.0 4.0 231.0 0.0 0.0 436.0 194.6-Erection 0.0 0.0 0.0 0.0 17.9 0.0 0.0 17.9 0.0-Supervisory Services 6.4 5.4 0.0 0.0 0.0 0.0 0.0 6.4 5.4

Training and Consultancy 0.0 0.0 0.0 0.0 3.3 0.0 0.0 3.3 0.0-Administrative Services 0.0 0.0 0.0 0.0 0.0 0.0 9.9 9.9 0.0-Land 0.0 0.0 0.0 0.0 0.0 0.0 8.7 8.7 0.0

...... ...... .. ------ ...... .. ...... ...... .. ...... ...... .. ...... .............. .................. ...

TOTAL PROJECT COST - Totals 206.4 196.0 5.0 4.0 304.1 0.0 18.6 534.1 200.0

LFC Finance b/ C 68.0) C 68.0)

a/ Contract values include contingencies and taxes and duties (USS 42.3 million).b/ IFC funds wfil not be used to finance the FGD plant.ICB: International Comp titIve BiddingLC6: Local Coapetitive 8iddingOther: Direct imports and locally procured ItemsN.A.: Not Applicablo (Administrative Expenses)

-71-

Annex 3.6

INDIA Page 1 of 2

PRIVATE POWER UTILITIES (BSES) PROJECT

Procurement Schedule........ ................. ....

BIDDING.................-----------------.............-------. ... CONTRACT

Specs. Ready Invitation Opening Evaluation AWARD

2x250 MN Dahanu Thermal Power Station.. ... .....................................

A. Main Package January 90 February 90 August 90 Oct./Nov. 90 January 91(Boilter Equipment, Control andInstrumentation, Turbo-Gen.Equipment, Supervisory Serv.,CiviL Design and Services)

B. Mechanical Equipment1. Ash Handling Plant March 91 May 91 August 91 September 91 October 912. Coal Handling Plant February 91 April 91 July 91 September 91 October 913. Cooling Water System February 91 March 91 May 91 June 91 August 914. Fuel Oil Handling Plant March 91 April 91 July 91 September 91 October 915. Water Treatment Plant February 91 April 91 June 91 July 91 September 91

C. Electrical Equipment1. Bus Duck December 91 January 92 March 92 April 92 June 922. Transformers April 91 May 91 August 91 September 91 October 913. Switch Yard (Dahanu) February 91 March 91 May 91 June 91 July 91

D. Erection1. Main Package January 91 Feb./March 91 March 912. Cable Laying and Switchgear Er. October 91 December 91 February 92 April 92 June 923. PS Switchyard and Transf. Er. July 91 August 91 October 91 November 91 December 91

E. Civil Works1. Chimney May 91 July 91 September 91 October 91 December 912. Railway Siding January 90 April 90 June 903. Colony

- Phase I May 90 June 90 August 90 September 90 November 90- Phase 11 March 91 April 91 June 91 August 91 August 91- Phase III July 91 August 91 October 91 December 91 January 92

4. Land Development - - August 89 October 89 December 895. Miscellaneous Buildings May 91 July 91 September 91 November 91 December 916. Foundations December 90 January 91 February 91 March 91 March 91

F. Other Equipment1. 6.6 kV Switchgear March 91 April 91 June 91 July 91 September 912. LT Switchgear March 91 May 91 July 91 August 91 October 913. L & HT Cables January 92 February 92 April 92 May 92 June 92- Switch Yard (Dahanu) April 91 June 91 August 91 September 91 October 915. Illumination (S & E) January 92 February 92 April 92 May 92 June 926. LP Piping July 91 September 91 November 91 January 92 February 927. Misc. Mechanical Systems - - - - June 928. Misc. Tool & Plant - - - * January 93

G. Land, Training, Etc.1. Fresh Water - - - - September 902. Consultancy

Review (NTPC) - February 89 March 89 April 89 June 89- Main (DCL) March 89 May 89 July 89 August 89 October 89- Transmission Lines (NTPC) - June 89 July 89 September 89* Colony (STUP) July 89 August 89 September 89 October 89 February 90

H. Flue Gas Desulphurization Unit April 92 May 92 June 92 July 92 July 92

-72-

Amex 3.6

Page 2 of 2

BIDDING..................... -----....................................... CONTRACT

Specs. Ready Invitatfon Opening Evaluatfon AWARD................................... ...........................................................................

Transmission Llnes and Receiving Stations

A. Equipment1. Transmilsson Line Towars October 90 November 90 February 91 March 91 April 912. Hardwares and Conductors February 91 March 91 May 91 June 91 July 913. Rec. Stations Switchyards August 91 September 91 November 91 December 91 January 924. Rec. Stations Transformers Decewber 91 January 92 March 92 May 92 June 925. Rec.Stations Switchyard Septefber 91 October 91 December 91 February 92 March 926. Rec.Statlons Misc. Equipment January 92 February 92 April 92 May 92 June 92

B. Civil Works July 91 August 91 October 91 November 91 Decenber 91C. Erection - - July 91

Distribution............

1. Bulk Trans. & Switchgears ) The order of equipment for distribution is of continuous nature2. Subtransm ssion ) at BSES and are based on standard specifications already prepared.3. 11 kV Distribution ) The delivery of the distribution equipment is of the order of 6 months.4. Distr. Substation Equipment )5. Low Tension Distribution )6. St.Lighting & Misc.Works )

-73-

Annex 3.7I.NDIA.

PRIVATE POWER UTILITIES (BSES) PROJECT

Schedule of Disbursements for IU'RD Loan and IFC Investment..................... ....................................................... ..................................

(USS million)

IBRD Loan IFC Investment...... .............. ........ ..................... ..................... ................................... .........

Total TotalIBRD and IFC Fiscal Years Quarterly QuarterlyQuarters Ending Disbursements Cumulative Disbursements Cunulative............................................... ............. ............. ............. . ....... ............. ............. ............ ..

FY92December 31, 1991 28.8 28.8 5.0 5.0March 31, 1992 9.0 37.8 6.8 11.8June 30. 1992 8.7 46.5 5.4 17.2

FY93September 30, 1992 8.3 54.8 17.2December 31, 1992 9.5 64.3 14.2 31.4March 31. 1993 9.2 73.5 - 3.4June 30, 1993 11.0 84.5 5.0 36.4

FY94September 30, 1993 17.4 101.9 - 36.4December 31. 1993 21.1 123.0 19.3 55.7March 31, 1994 17.7 140.7 - 55.7June 30, 1994 12.0 152.7 - 55.7

FY95September 30, 1994 8.0 160.7 - 55.7December 31, 1994 6.4 167.1 6.9 62.6March 31. 1995 4.8 171.9 62.6June 30, 1995 3.2 175.1 - 62.6

FY96September 30, 1995 2.0 177.1 - 62.6December 31, 1995 2.0 179.1 5.4 68.0March 31, 1996 1.5 180.6 -June 30, 1'96 16.9 197.5 - -

FY97September 30, 1996 1.5 199.0 -December 31, 1996 1.0 200.0

Closing Date of the IFC Investment : June 30, 1996Closing Date of the IBRD Loan : December 31, 1996

INA

PRIVATE POWER UTILIUTES (SES) PROJECT

Statement of BSES's Secured Borrowings

I. 1981f_RESRupees Date of Redemption Type of Mort!agM

10,000 - 61.2X 'AO C..ss 10,000,000 1st July, 1993 or on vesting date, Legal mortgagewhichever is earlier

207,384 - 16X IC Class 20,736,400 ) At the expiry of 7th, 8th and 9th -do-7,818 - 16X WC: Class (Reissuod) 784,800 ) year from 1st June, 1986 or -do-25,421 - 1SX '0 Class 2,642,1W0 ) vesting date, whichever is -do-24,579 - 16X '0' Clase (Reissued) 2,457,900 ) earlier -do-53,950 - 13.5X 'E' Class 5,395,000 ) 1st July, 1992 or on vesting -do-16,050 - 13.5X OE Class (Reissued) 4,606,000 ) date, whichever is oarlier -do-93,637 - 15X 'F' Class 9,363,700 1rt July, 1997 or on vesting -do-

date, whichever is earlier

200,000 - 15X '0' Class 20,000,000 At expiry of 6th, 7th and 8th year Equitabl, mortgagefrom 31st August, 1989 or onvesting date, whichever is earlier

200,000 - 155 OH' Class 20,000,000 18th May, 1991 or on vesting date, -do-whichever is earlier

200,000 - 15% *IO Class 20,000,000 11th October, 1992 or on vesting date, -do-whichever is earlier

____________

Deposited with UCO Bank as 116,884,900collateral security for additional =cash credit facility of Rs 90 lakhs

It. IUM LOAN

Term Loan fromUnited Commercial Bank (UCB) 9,500,000 Equitable mortgage subject

to prior charges created1*1. CASH CREDIT FACIITY

In (I) aboveUnited Commercial Bank (16) 23,500,000 ) Deoe of HypothecationCrera Bank (1IX) 17,600,000 )

41,000,000==w

-75-Annex 3.9

INDIA

PRIVATE POWER UTILITIES (BSES) PROJECT

Main Characteristics of the Ib Valley Coal

Z Parameter Worst Coal Best Coal

Gross Calorific Value Kcal/kg 3,080 3 10

Moisture Z 6.3 6.9

Ash 1 47.2 41.2

Volatile Matter 2 22.4 23.5

Sulphur 1 0.35 to 0.60 0.35 to 0.60

Fixed Carbon 22.4 28.4

Note: 2 - Percentage by weight.

-76-Annex 3.10Page 1 of 6

INDIA

PRIVATE POWER UTILITIES (BSES) PROJECT

Environmental Assessment -- Executive Summary(Agreed between the Government of India and IBRD)

1.1 INTRODUCTION

Bombay Suburban Electric Supply Limited (BSES) is a privateutility which distributes power to consumers in the northern suburbs ofBombay. BSES currently purchases all its power requirements from the TataElectric Companies. In 1976, the Government of Maharashtra (GOM), as acondition of BSES's operating license extension, stipulated that BSES mustdevelop in-house generation capability to meet part of the projected increasein electrical demand in their service area.

BSES carried out a site selection for the proposed 500 MWcoal-fired power plant, utilizing the Government of India's (GOI)Environmental Guidelines for Thermal Power Plants. After evaluating ninealternative sites, Bassein, a coastal site north of Bombay, was the initialsite selected for the project. Lack of government approvals forced BSES toexamine a number of other coastal sites in 1986, resulting in the selection ofthe Dahanu site, 80 km north of Bombay. This site provides several advantagesincluding:

- once through condenser cooling using sea water;

- adequate land base away from densely populated areas;

- no resettlement of displaced persons;

- a secure freshwater supply;

- the opportunity to take delivery of oil or gas; and

- a railway in close proximity to facilitate coal delivery.

1.2 THE PROJECT

The proposed facility is a 500 MW thermal power station consist!.igof two 250 MW, wet cooled units, capable of burning coal, natural gas or oil.The main fuel supply will be coal from the mines in Orissa, some 1400 km away.Coal will be transported to the site by rail. The plant will be cooled by aonce through system utilizing sea water drawn from the estuary which isadjacent to the plant site. The plant will be located at least 500 m from thehigh water line as required by GOI environmental regulations. Fresh waterwill be supplied by a 31 km pipeline from the Surya Prakalp Reservoir.

Power will be transmitted to Bombay by twin double circuit 220 kVtransmission lines to three 220 kV/33 kV receiving stations at Ghodbunder,Versova and Malvani in BSES's distribution area. The route selected for boththe transmission lines and freshwater makeup pipeline will minimize disruptionof the natural habitat.

-79-Annex 3.10Page 4 of 6

with the standards of these governments and World Bank guidelines. Thistemperature rise in the creek system, which is substantially less than theseasonal fluctuations in creek water temperature, will minimize any risk ofthermal shock to organisms inhabiting the creeks. The ash handling anddisposal system will contain all this waste material for the operating life ofthe plant, while providing adequate treatment for slurry water prior todischarge to the creek system. Leaching from the ash disposal lagoons will becontrolled by lining these ponds with clay. All effluents discharged from theplant site and ash disposal area will meet World Bank guidelines and will bemonitored prior to discharge. Based on the available information, the projectis thus not expected to adverrely impact either the water or aquatic resourcesof the creek system. However, the final impact prediction must awaitcompletion of the aquatic studies (by the third quarter of 1992).

Coal for this project will be supplied by Coal India Limited fromexisting mines in the lb Valley, State of Orissa. Current Ib Valley coalproduction is about 6 million tons per annum and will be 9 million tons perannum in 1995-96, with about 2 million tons per annum slated for the Dahanuthermal power project. A World Bank mission has visited the site, hasexamined the situation against the requirements for this project, and hasconcluded that this project will result in minimal incremental environmentaland socio-economic impacts.

Construction and operation of the power plant is predicted to havelimited impacts on the socio-economic environment. The siting of the plantdoes not require relocation of residents and will not affect forestry oragricultural production. The construction wcrk force is expected to peak atabout 3000 people which is about 1Z of the region's population. Approximately2500 people will be hired lccally, with the remaining 500 construction workersbeing immigrants to the Dahanu area. The employment associated withconstruction is predicted to increase opportunities for local area merchantsand the agricultural sector, although competition for labor may increase thecosts of unskilled labor. The operation of the power plant will employapproximately 500 primarily skilled persons. This will aid in thediversification of the region's economy.

BSES is committed to employing local residents -where practical andstrengthening the local infrastructure to ensure adequate services for thearea's residents. This will in part be accomplished throur,h provision oftraining and conanunity development programs, administered 'y the GOM'sDepartment of Tribal Development. The objective of these yrograms is toupgrade the educational skills of the area's tribals, particularly the women.A broad range of opportunities are currently being assessed including:

_ upgrading and enhancing the community center at Saravali toprovide handicraft and health care training;

- upgrading and enhancing the capacity of the Indu.'trial TrainingInstitute for tribals at Wangson; and

a variety of small scale schemes predominately aimed at improvingeducational opportunities for the youth in the surrounding tribalcommunities.

Annex 3.10Page 5 of 6

1.5 MITIGATION

BSES has adopted a variety of practices and technology to minimizeenvironmental and socio-economic impacts and enhance the benefits of theproject. During construction, equipment movements will be limited to theconstruction site and designated access routes. Disturbed areas will bestabilized and reclaimed as soon as practical. Vegetation will be developedand maintained as a buffer between the construction site and surrounding wattrbodies, and to control erosion. Drainage from the construction site will becontrolled and treated to minimize the introduction of sediments to thecreeks.

Mitigation measures related to plant operation primarily involve acombination of design features and standard operating practices which BSES hasadopted to minimize environmental impacts. Electrostatic precipitators (99.8Zefficiency) will be installed and operated to ensure particulate emissionsmeet regulatory standards and guidelines. The plant will be designed toaccommodate the addition of a FGD unit should future monitoring indicate it isnecessary. All surface runoff and liquid effluent discharges will becollected and treated to ensure compliance with regulatory standards beforerelease to the environment. If the ongoing aquatic studies indicate that theproposed project will adversely impact the Dahanu Creek system, BSES will berequired to install further treatment for liquid effluents to reduce suchimpacts to acceptable levels. Ash will be contained in lagoons which will becovered and reclaimed as they become filled.

BSES will ensure that economic benefits for the region are maximized,through participation in programs aimed at upgrading the skills of the area'stribal peoples, and investigation of the opportunity for by-productdevelopments such as aquaculture and the use of ash wastes in the manufactureof construction materials. BSES has already hired a Senior EnvironmentalSpecialist and Community Relations Officer to promote the achievement of theseobjectives.

1.6 MONITORING

The proposed monitoring program is considered criXical to ensuringthe success of the mitigation of predicted impacts. The program is designedto sample a variety of environmental components to vcrify that impacts arewithin the projected ranges. Baseline data collection programs have beenreconmended for those sectors for which existing data is considered deficientand the required studies have been initiated. The aspects being monitoredinclude climate, air quality, water quality, hydrogeology, soils, vegetationand aquatic resources. Ir. addition the Maharashtra Pollution Control Boardwill audit the environmental monitoring data semi- annually and release theaudit report to all, interested parties (including interested non-governmentorganizations). Any non-compliance with GOI, GOM and World Bank requirementswill require immediate action by BSES.

1.7 CONCLUSIONS

Changes in the environment are associated with all majordevelopments which are undertaken to maintain or improve the Indian standard

-77-Annex 3.10Page 2 of 6

Pollution control systems are incorporated into the thermal plantoperations to minimize impacts oi the surrounding region. BSES will monitorall air cinJssions and liquid effluents to ensure compliance with theenvironmental requirements of the World Bank, the GOI and GOM. BSES hasappointed the Salim Ali School of Ecology, Pondicherry University, to assistin the development and implementation of the monitoring plan. The GOM'sPollution Control Board will audit the monitoring results on a semi-annualbasis, releasing the audit report to all interested parties.

BSES has also committed to maximize local staffing of theconstruction and operation phases of the project to ensure the maximumeconomic benefit accrues to the region.

1.3 EXISTING ENVIRONMENT

The Dahanu plant site experiences euu-tropical meteorologicalconditions with definite monsoon, wind and p:ecipitation patterns. The plantsite is adjacent to a tidal estuary and is approximately 3.9 km inland fromthe ocean. Evidence indicates the estuary supports a subsistence fishery.

The site is approximately 816 ha in size. The soils on the sitetend to be saturated because of the site's proximity to sea level and thenatural cover has been removed by a variety of land uses. The current useinvolves commercial salt production. The site is not considered a valuablenatural habitat because of its current condition.

There are no permanent residents on the plant site proper. Theregion's population of 300,000 people is widely dispersed in smi'll communitiesalthough approximately one third reside in or near the town of Dahanu, S kmnorth of the plant site. One half of the area's total population is estimatedto be tribals, living mainly in rural villages. The region's population isinvolved in diverse economic endeavors, including agriculture, fishing andcottage-type manufacturing industries. There appears to be considerauleopportunity for diversification in such areas as tourism, food production andprocessing, horticulture and cottage industry manufacturing. Currentinfrastructure limitations including irrigation water and transportation werecited as limiting factors to the area's overall development.

1.4 ENVIRONMENTAL IMPACTS

In 1987 BSES compleced an initial environmental assessment (EA)for the project, which was subsequently approved by both GOI and GOM. Sincethat time substantial additional information has been collected by BSES. As aresult, a consultant financed by the World Bank prepared a new EA documentwhich gatthers together all the relevant information on the project compiled byBSES and others (e.g. World Bank consultants). Preparation of this new EAreflects Bank concerns about the environmental and socio-economic consequencesof the proposed power plant project. The new EA document has been thoroughlyreviewed by Bank staff and consultants, and found to be satisfactory, althougha study of the aquatic system of Dahanu Creek is continuing. This document isthe Executive Summary of the new EA.

The overAll impact of the development and operation of the Dahanuthermal power plant will be positive for the western region of India. It will

-78-Annex 3.10Page 3 of 6

supply a benefit in the form of economical and reliable energy for Bombay, anddiversification of the local economy and improvement of the infrastructure forthe benefit of the Dahanu area residents. The impact evaluation includedexamination of the influence of construction and operation on the local andregional environment. Changes which might occur in the various componentsincluding air quality, soils, vegetation, wildlife, water quality, aquaticresources and the socio-economic environment have been analyzed.

Construction and operation of the plant will not cause significantchanges in regional air quality as stack emissions are projected to be wellbelow the World Bank guidelines. Impacts on ambient air quality are based onthe results of computer modelling studies assuming a 275 m stack, use of worstcoal quality and proper operation of electrostatic precipitators. Anextensive monitoring program will be carried out by BSES, involving both fixedand mobile stations, which will measure groundlevel cor,nentrations of S02,NO , and particulates. Continuous stack monitoring wi include measurementsof SO2, NOx, particulates and opacity.

GOI and GOM permit approvals initially required BSES to installflue gas desulphurization (FGD), with 90X efficiency, at plant start.n.Subsequent review of stack emission data and information from ambient airquality modelling indicated that the proposed power plant would easily complywith international (including World Bank) SO2 requirements without FGD. GOMpermits have therefore been revised to require BSES to leave sufficient spacefor future installation of FGD should extensive monitoring after plant startupindicate a need. GOI is reviewing its position with respect to the FGD plant.If GOI decides to amend its clearance to remove the FGD requirement, then IBRDand IFC will not have any objection to this decision which will marginallyincrease the economic internal rate of return of the Dahanu project andmarginally reduce BSES's tariffs.

The major impact on the terrestrial environment is the permanentcommitment of 816 ha of land to the proposed facilities. However, the areaaffected is not particularly valuable or unique from an environmentalstandpoint, in both a local or regional context. Information on the routeselection for the pipeline and transmission line indicate that the preferredalignment minimizes disruption of undisturbed natural lands.

Construction and operation of the power plant could pose a riskfor the aquatic environment, primarily through the introduction ofcontaminants which could alter water quality and ultimately the aquaticsystem's productivity. The available data on the Dahanu Creek system providesinsufficient information on which to predict the project's potential impactswith certainty. Studies have therefore been initiated to provide a morecomplete understanding of the local aquatic system and to provide a base forimpact prediction.

The once through cooling water system can be a source of thermalpollution which might stress the aquatic system, but modelling studiesindicate that the use of a 3 km long canal provides adequate residence timefor heat dissipation. Cooling water will be discharged to the creek system ata maximum of 5 °C above ambient. The resulting change in water temperature inthe creek will not exceed 3 °C above the ambient water temperature, asrequired by the Grant of Site Clearance issued by GOI and GOM, and in line

-81-Annex 3.10Page 6 of 6

of living. Trade-offs must be made between negative and positive rspects ofprojects. In this regard local non-government organizations who oppose thisproject have been extensively consulted uver the last 2 years. Major issuesraised (construction of permanent plant structures at least 500 meters fromthe high tide line, possible adverse impact of increase in the temperature ofcreek waters on the aquatic life, possible adverse impact on chickoo orchards,etc.) have been discussed and mitigation measures instituted. The proposedaudit by the Maharashtra Pollution Control Board, with public release of theaudit reports, in large measure reflects the concerns voiced by thenon-government organizations consulted.

This project does rot have any major negative implications for thebiophysical environment, and as regard socio-economic concerns. The overallimpact is projected to be positive. The success in achieving this result isdependent upon BSES's diligence in planning, implementation and monitoring toensure they achieve the objectives which have been established by the processto date. In this regard the most critical undertakings are related to theplanning and implementation of initiatives to ensure that regional economicbenefits are maximized and disruption to culture and infrastructure areminimized. The risks to the environment can be minimized provided BSES abidesby all the recommendations in the EA report and to their commitments in thisregard. However, central, state and local authorities in India, as well aslocal and national non-government organizations and internationalorganizations, must remain vigilant to ensure early identification of anyenvironmental and socio-economic problems associated with this project andBSES must be prepared to adopt practical solutions in a timely manner tominimize any negative impacts and to create a project which, in both the shortand the long-term, can serve the best interests of India

-82-Annex 3.11Page 1 of 5

INDIA

PRIVATE POWER UTILITIES (BSES) PROJECT

Recommended Monitoring Plan and Additional Baseline Studies

1.1 INTRODUCTION

The following program is proposed to test the validity of theimpact predictions and/or to provide baseline information to ensure existingenvironmental conditions are adequately documented.

1.2 METEOROLOGICAL DATE

A meteorological station will be located in the Vadkum Villagearea north of the proposed housing colony. The station will be operated on acontinuous basis with information available on wind speed at groundlevel and10 meters above groundlevel, solar radiation, temperature, and precipitation.The data collected will be used to verify previous plume dispersion modellingstudies.

1.3 AMBIENT AIR QUALITY

A system of five monitoring stations (3 stationery and 2 mobile)will measure groundlevel concentrations of SO2, NO, and particulates (Table3.11.1). One station will be lorated at the meteorological station, one nearDahanu Road Railway Station, and one west of the power station in BadapokharanVillage. The two mobile stations will be used to monitor ambient air qualityin adjoining communities such as Motapoda, Vadkun and Dahanu, etc. Care willbe taken to ensure site selection minimizes the influence of unrelatedactivities such as traffic and agriculture which can significantly affectparticulate readings.

The fixed stations and the meteorological station will befurnished with data links to allow on-line data collection. This program willbe started as soon as possible (mid-1992) to ensure a minimum of two years ofbaseline information prior to startup of the first 250 MW unit.

1.4 STACK MONITORING

Continuous stack monitoring will include measurement of SO2, NXX,particulates, and opacity. These measurements will provide assurance that theplant is being operated in compliance with Government of India, GovErnment ofMaharashtra, and World Bank stack emission requirements. In addition, stackmonitoring will ensure that ESP's are being properly maintained and operatedefficiently.

-83-Annex 3.11Page 2 of 5

Table 3.11.1

Air Quality Monitoring -- Dahanu Thermal Plant

Sampling Program and Schedule

No. of Stations: 5 locations (3 stationery and 2 mobile).Frequency: 3 x 8 hours samples per day.Duration: Continuous monitoring.Parameters to be Monitoreda) Suspended Particulate Matter: 8 hours (3 samples/day)b) Sulphur Dioxide: 8 hours (3 samples/day)c) Oxides of Nitrogen: 8 hours (3 samples/day)

1.5 WATER QUALITY

Water quality is critical to the operation of the plant and to thesurrounding environment, therefore water quality parameters will be monitoredin the incoming water, discharged effluents and at various points in thesurrounding environment which may be influenced by development and operationof the power plant. The recommended parameters to be monitored in theincoming fresh water supply are presented in Table 3.11.2.

Ambient w"'ter quality stations will be established at tenlocations around the plant site, with six of the locations arou:nd the ashdisposal lagoons, three locations further downstream in Dahana Creek, and onelocation in Savt.a Creek. Water samples will be taken monthly for analysis ofall parameters ahown in Table 3.11.3, except for heavy metals. Every twomonths, the samples taken from the six locations around the ash disposallagoons will be analyzee for all parameters as shown in Table 3.11.3,including heavy metals. In addition to the water samples, creek sedimentsamples will be taken ftzm three locations every three months and analyzed forheavy metals.

After five years of plant operation, certain parameters, samplesites, and the frequency of monitoring will be adjusted based upon therecorded results. This may involve dropping some parameters or stations anddecreasing the sampling frequency to quarterly or semi-annually at somelocations.

1. 6 MYDROLOGY

The sites proximity to the ocean causes the soils to be saturatedand the water table to be at or near the surface. It is anticipated thatseepage may occur from the ash lagoons or coal storage areas. The groundwaterprofile will be essentially flat except in the areas which are proposed to beraised for construction of the plant site and the ash lagoon systems. Thisflat profile ensures that there is little head to drive leachates off-site,although over long-term there will be some movement from the site toward thecreeks or possibly to the ocean.

-84-Annex 3.11Page 3 of 5

During the year prior to plant commissioning, piezometers will beinstalled around tne ash lagoons and the coal storage area to determine thecurrent water quality. The parameters monitored will be based on fuel supplycoal and ash analysis. A monthly monitoring program will be established.

Table 3.11.2

Fresh Water Supply Water Quality Parameters

pHAlkalinity (mg/L CaCO )Hardness (phenophtaleln)Calcium (mg/L Ca)Magnesium (mg/L Mg)Total Hardness (mglL CaCO8)Chlorides (Img/L Cl)Silica (mg/L S02)Sulphates (Img/L S04)Turbidity (FTU)Nitrate (ImgL N)BOD5 (mg/L)BacteriaDissolved Oxygen (mg/L 02)Total Solids (mg/L)Totel Dissolved Solids (mg/L)Total Suspended Solids (mg/L)Total Vo'iVile Solids (mg/L)Total Volatile Suspended Solids (mg/L)Dissolved Iron (mg/L Fe)

Annex 3.11Page 4 of 5

Table 3.11.3

Water Quality Parameters

TemperaturepHDissolved Oxygen (mg/L 02)Alkalinity-P (mg/L CaCO8)Alkalinity-T (mg/L CaCo3)Turbidity (FTU)Colour (APHA)BODr (mg/L)Total Suspended Solids (mglL)Total Dissolved Solids (mg/L)Total Volatile Solids (mg/L)Oil and Grease (mg/L)Phenolic Compounds (mg/L)Sulphate (mg/L SO4)Chloride (mg/L C1)Calc!.um (mg/L Ca)Magnesium (mg/L Mg)Sodium (mg/L Ns)Potassium (mg/L K)Total Hardness EDTA (mg/L CaCO3)Fluoride (mg/L F)Total Organic Carbon (mg/L C)Total Inorganic Carbon (mg/L C)Phosphate - Ortho (mg/L P)Phosphorous - Total (mg/L P)Nitrite (mg/L N)Nitrate (mg/L N)Ammonia (mg/L N)Chlorophyll (mg/m3)Total Nitrogen (mg/L N)Boron (mg/L B)Mercury (mg/ L Hg)Metals (Fe, Cu, Zn, Mn, Pb, Ni, Ca, Co, As, Ba, Cr, Se,

Mo, Al, Mg, Be, Cr, Ag, V, Bi, Zr)

1.7 AQUATIC RESOURCES

In March 1991, BSES retained the National EnvironmentalEngineering Research Institute at Nagpur to undertake a seasonal survey todetermine the estuary fisheries resource. Terms of reference for this studyare provided in the Project File. The study will involve test nettings andhabitat mapping of the estuary surrounding the plant site. The samplingfrequency will be determined by the anticipated seasonal use based on the lifecycles of the species endemic to the region. Species and abundance will bedetermined by the test nettings. The habitat map will permit an estimate ofthe total productivity of the system. Sampling will be carried out threetimes per year. While the NEERI study will be completed in 18 months(September 1992), the monitoring of the aquatic resources will continue for a

-86- Annex 3.11

Page 5 of 5

minimum of five years after commissioning of the power plant to ensureorganism response is as predicted in the assessment. However, details of thissampling program must await the results of the NEERI study.

1.8 SOILS

Air dispersion modelling suggests that the plant operation willhave little impact on the region near the plant site. However, monitoringsites will be established in areas of predicted high sulphur deposition toverify current predictions. A soil monitoring program will be established todefine background conditions and conditions during the operation of the powerplant. Particular attention will be Sivan to selection of the sites to ensuresoil chemistry is not affected by other practices such as agriculture orirrigation. Soil pH and constituents critical to local crops will bemonitored.

1.9 VEGETATION

BSES has retained the services of an expert horticulturalist toassist in the design and implementation of a number of environmental programs.The terms of reference (included in the Project File) relate to the followingareas:

-- long-term monitoring of the area's chickoo orchards;

-- preparation of ash lagoon reclamation programs;

-- preparation of a greenbelt plan, including research on thesuitability of species for inclusion in the greenbelt areas;

-_ completion of field research on the re-establishment of mangrovesaround the plant site; and

-- provision of advisory services to BSES and others, as necessary.

With regard to the work with the chickoo orchards, determinationswill be made to define the parameters which currently affect productivity,including a measure of the natural variability in productivity, seasonally andover several years. These studies will ensure that BSES are not subject toclaims of lost income due to the impact of the operation of the power plant onthe area's chickoo orchards.

"lollSECUW tOIYITE i 0MtFtlitE S togs) ESI1i

fuaaci2l bolysislocom Stateuto its 'tii40k---itter1 64itedi----- ------- --------- ---------------------------- otected ------- - -------- -------7isgoa Year "Win 5lst tl ck 1905 1906 I"7 290 I9m9 1990 I 1972 I903 994 1995 11"96 mr 20 999 2000 2MT1- . . --- .... ... _ --- --- .- --- - - - - .... . . ... . --- ...!W6veal Sinrat,tn Mob) 0 0 0 0 0 0 0 0 0 0 1,O53 2,344 2.714 2.734 2,126 2,734Pow Pswobnr from TEC 9200hl 2,240 2,i2d 2,627 2,942 S,035 3,213 3,536 3,761 1,415 4,276 6,543 2.et5 2,16? 2,t59 2,92t 3.240 3,420

Total 690902 2,2t0 2,420 2,621 '042 3,035 3,M 5.11 3,761 t,015 4,276 4,543 4,816 5,093 5,313 5,033 5,03 6.091strObOtic0 Logogo 120 22m9 226 348 36S 369 574 404 395 402 420 454 492 509 531 366 59i 622Sal" .4 Envogy 0mtat,4 0 0n 0 0 0 0 0 0 0 0 0 0 ,1'59 2,110 2,461 2.460 2,902 2.161Sal" o4 Esffq Pwtl osed 116)0i0 2,021 2,202 2,279 2,477 2,6? 2,099 3,112 3,366 3,614 35,e0 4,0B7 2,571 2,414 2,175 2,629 2,eB 3.1;7. .. ... ..... . .. . ... ----- . .... --- .. . -- - .... -_ - - -tot al tOwsrt Galn (0t2bl 2,021 2,202 2,279 2,477 2,161 2,099 3,112 3,366 3,614 3,849 4,029 4,3l4 4,354 4,016 5,090 5,344 i ,5t8Oiwra" 9rff MtAlIlN 0.06 0.03 11.3 I.l0 1.13 9.25 1.39 1.51 1.64 1177 1.90 12.6 2.05 2.09 2.17 2.21 2.Eltericily Sales tih iFillirl 1,134 2,046 2,535 2,135 3,410 3,614 4,329 5,496 5,922 6,428 7,7513 0,17 9,392 10,102 3110!8 62,93 31,2°Stwratiq Rt"fniEledfltit 7 Sitn 1,714 2,041 2,65S 2,135 3,010 3,611 4,119 5,006 5,922 6,820 1t,53 1,3t? 9,332 10,102 2t,068 12,31S 13.296El.trt,c,l Ohkg I66 222 254 204 360 396 45 536 651 n52 0m S37 9,033 I,269 2,210 1,335 1,4650Cb wtKoe is t1 20 26 2B 39 34 3t 39 41 .4 46 49 52 54 51 596.o. 1cc. Cosorotts Dinvs,, M2 963 le 294 280 226 t9l 196 213 232 25t 272 9n 316 4 312 4s 5.ICuow fro Cuouteri eirsii9 It le l9 le 20 2S 23 25 28 30 33 36 tO 41 41 52 5(l2ooe lro. Ft.,ip Pojcts 0 0 0 0 0 0 40 44 47 5t 56 6 65 10 716 82 ESTo9tal OWrsalq Fos.n 2,076 2,460 3,046 3,257 3,605 4,298 s,0o2 5,°9 6,980 7,S34 S,990 9,4" 20,013 29,696 12,001 24,032 25,650,0r8etlo Ei.pditunRtoctar of Pwr I,525 1,7156 2,29 2,433 2,652 3,21S ,622 4,290 4,604 5,359 6,201 4,203 4,395 4,452 5,229 6,4n1 1,O0lielric it Iot 966 221 254 2e04 3O S%9 41 536 651 751 il5 *37 1,033 9,221 t,2tO 1,335 1.463cost ofcol 0 ° 00 0 0 0 0 0 0 0 2,220 1,550 I2,03 2,040 2,171 2s,30OPtrStCa god 00,ot 1oa.Pf. 6E9 904 all 122 81S 1i4 22 26t 303 352 400 851 929 2,002 ,0S 1,213 9,1211Salain ad &9S. 44 51 t0 it 1 99 tt 105 226 121 12 161 212 2t4 257 25 53119Owetia6ion S2 29 31 40 39 48 63 72 so 69 9 232 569 Stt 5ni s601 0nt2 ts of , Casttrts 6ivis09 120 235 I10 982 080 216 210 a1y 203 22 230 255 20 502 327 353 82tsposn olf lower 6iwi6soo 12 12 I3 1S 24 15 s t6 19 22 23 26 29 50 33 36 rFore,gp FrojKts tp s 0 0 0 0 0 23 42 43 69 s3 57 62 61 fl 78 i5Total tWr8t0 E sdiluo 12,9e6 2,362 2,935 3,148 I,4i1 4,125 4,649 5,545 6,539 7,169 6,49? 0,916 9,039 9,fl1 00,1519 12,t09 13,679Opeotla lmo 916ti929 20 929 213 313 423 31 16 903 2,i65 I,13 ,919 I,9M9 2,922 1*1teinterest Efrpu 26 20 50 35 St 52 4t 59 12 fi ItiO I0,09 19,322,I2 2,403 t4 642fl loss,on Ia 0r1 a b 0o 0 0 0 0 0 0 6 0 0 0 0 IF too00 2l5 121 142It* off O lstl ibie asoets I I I I 0 0 I I I 0 0 is 13 i5 15 15 Isfrolt botintt 63 a 9 gO N4 e5 120 320 354 5 641 123 560 6*2 992 161 8t 991s, lot 4 7 9 14 0 0 0 0 0 I9T 913 0 0 0 6 0 0Net M 58 6l2 7t if l5 120 329 354 513 536 330 399 t02 1S2 62t6 i54 mlStattry trwm I twrWridltiombo kw"ru 1 Olov. 2w x6lo @4e w it 1 6 Is til 20 4t t 0 0 0 0 6 O 6 0 O 006l,t.re iO ,aspium f0 O s 3 I S I 1 1 4 4 4 I 0 o o 0Cttqr cf Reserv 2 e1 5 9 e 9 6 I 6 e * 42 42 43 44 45 4t6SpKial fwpiot,otins

for tb,a of j e lwme 0 0 0 0 0 0 0 0 0 0 a 014e0 ISO IO 250t.d. f,oKt CoEt 0 0 0 0 0 6 23O 210 230 250 900 0 0 0 0 0 0i0 hI,fO4 d4 2o"slu Al n e 0 6 0 0 0 0 50 31 32 32 3i 41 43 45 41 54 5frd. Sbarm ECitu ib eptmti vbrv 0 2 1 1 1 1 1 1 1 0 0 0 0 0 0 0 01e4al ruwrwn I A iarlio n. i3 32 24 23 32 62 215 25? 217 295 231 6 862 2 41 26 m 252istriOuta2e Prorrit 45 It 47 4t S3 5s 152 99 231 241 39 503 5126 s3o 55 tO6 GU6

3,i,as 12 2 11 IS 13 23 23 23 es 95 95 201 201 201 201 201 201Oetaiedw arsis 14 19 34 34 40 5 ISO 5 15i4 246 224 52 315 34t 524 405 435get ProOitlOUFao 3t St 20 2S 2n 33 it 60 a 1 13 61 6t 63 1 63 63 616,0 FrofatfEft 1tti2 lOt lOt lOt e g 01 m23 241 211 963 15S 15 101 0t 291 20 1 O 103 2O°r.9)q Itoc..lb u 41 42 43 33 n 4s 19 n n9 903 203 120 22 In 151 124 121lterwnl Cowr Itlenl 3.39 3.48 .66 3.15 3,21 3.31 9.32 1.06 . 18 6.67 5.02 1.55 2.62 2. 1 e .06 2.00 2.24

SEI 1 TE PWER UTIItTIES tBSESI ES1WECTFioejsial nalssis

Balmte Sheet Rs tI£ioo----- -£ ------- kt-al Auditeld ---------------- ---- ----- - -------- rojeiteo ---------------- ----

Rs at Slst tltnh IM 19 1986 987 1968 199 19"9 991 992 1993 1i99 1995 1996 1997 1998 1999 2000 2b4I

ASSETS

ir0oss Fixoe Assets 1,4Z6 1i144 1,269 1,410 1.627 1,867 2,100 2,344 2,596 2,061 3,165 15,937 16.280 10,642 17.924 I'.40 1 ,9g(Less ktu ulateo Deoreiatio. 266 295 332 373 411 459 522 594 674 763 961 1,194 1,763 2,344 2,937 ','AZ * lt5Change due to Foreiqn Echriaqe Variation O 0 0 0 A 0 0 57 IS 402 647 911 1,064 1,i23 1,174 1,100 1,176Capital 'ort-ie-Prslress 40 17 la 53 51 66 74Q 2,120 4,9t9 9,008 11,520 70 70 70 8o 90 0E9

_ - - -_ - - _ - -- - -- --- -- _- ----- ----- - -- _ -- ----- ----- --- -- --- -- --- -- -- - _

Not Filed Assets 810 867 955 2,898 1,266 1,474 2,318 3,927 7,072 1i,500 14,470 15,724 15,650 5.492 15,341 15,262 15,ftv-

t0 '42 65 75 66 99 162 143 808 t93 223 217 457 562 530 5e8 639 723I-ve-t7raes l6 13 16 20 19 28 32 37 37 42 342 336 390 470 4S4 525 55:Feree,ables m 436 427 409 492 616 7t: 860 1,004 1,153 1,305 1,432 1,577 1,696 1,857 2,034 2,22SLteas I Advances 57 52 72 90 64 126 43 45 47 £68 375 3Z6 227 56 57 59 61Other Corrent ssets 659 234 334 445 581 697 690 700 700 710 710 720 720 730 7S0 740 74e

Total Current kssets 574 7W 923 1,030 1,275 1,569 1,648 1 756H I,98 2,287 2,906 5,268 3,402 3,480 3,722 3,796 4,502

Crstinqgry Rese .o Inrestwnts 31 34 42 49 57 65 71 76 82 89 97 136 177 218 260 3O4 Z45tt lerestr*nts I 14 27 to t9 £8 7 8 8 7 7 4 4 3 3 2 _T

eotal noestet ts 45 48 59 67 75 63 7d 63 90 97 £04 141 191 221 263 306 330Deferred Expenws/lntagqlible Assets t I i O 0 1 0 70 70 70 £50 635 120 £05 90 75 60

Total Assets 1,430 2,715 I,938 2,195 2,616 3,127 4,044 5.839 9,213 13,954 17,652 19,200 19,432 19,299 19,426 19,559 19,7lM

LIDlIUIES 12 EUITT

Seodnr creditors 174 237 254 219 294 35 363 424 471 527 589 444 453 461 528 09£ 6W.Short Tlre Ba t Creolt 34 39 9 7 0 6 50 50 50 50 250 160 170 689 199 200 219Bridgelto 0 0 0 0 0 0 530 0 0 0 0 0OD 0 0 0Other Current tliailities 204 294 40t 516 647 868 795 629 891 I,040 1,226 1,358 1,263 1,115 1.131 1,656 1,172Current htorities of oeq-ter De6t 0 0 0 4 9 16 t6 16 12 7 0 525 W65 680 8P4 908 923

Total Crreont Liabilitms 411 570 665 746 950 1,239 1,774 1,310 1,424 1,624 6,967 2,4817 2,752 2,63 2,742 2,00 2.9T4

Sernrity Deoits 233 250 276 346 430 486 536 586 636 66 16 786 6m36 e66 936 99S 1,036Other Loq-trn Liabilitit 132 247 173 193 240 228 2U4 259 274 269 304 319 334 349 364 37 304

Total Loet-ler Liabilities 364 398 449 539 637 724 780 045 910 975 1,040 1,195 8,170 1,235 1,300 1,325 1,43O

ison-conwtible T.hntbr.es 86 0OS 106 106 186 106 106 106 106 196 106 106 86 266 166 186 IDACoavertsble DebntarnO 0 0 0 0 0 0 0 1,090 0 8,840 2,50 0 0 0 0 0 Losn froi I£6 D 0 0 0 0 0 0 600 I,SO 3,245 4,"7 9,682 4,505 4,260 4,010 3,77 3,447toa froee IFC 0 0 0 O 0 6 0 247 687 1,267 1,;04 1,544 1,422 2,274 1.121 958 780Loai Irom tndhan Finotcial Insttotlotms 0 0 0 0 0 0 0 0 1,340 2,060 3,140 3,270 2,943 2,616 2,289 1,962 1,635Other tortere toLas 1T 10 20 26 42 61 45 29 27 28 £0 10 t0 10 t 10 1t

Total Long-terw Dot 95 II5 I1S 131 147 166 150 1,981 3,710 7,707 10,482 9,611 6,985 8,205 7,53 6,772 5,902

Ordicerq Share Capital 59 5? 59 59 59 7II 117 II? 517 527 517 1,117 8,12 I,12 1,217 1,117 1,117Pre4erence Share Capital 11 1i 10 20 10 10 20 60 28 10 10 to 20 £0 :D 1 0 tShere

8re,in 0 0 0 0 0 0 0 0 600 600 600 1,0 1,500 2500 2,590 2,500 I.5 .SO

Retained Earnimjq 157 73 203 233 275 252 331 456 610 756 982 1,283 2,598 2,9t4 2,315 2,720 3.155Slta

t tory Peservn andWoroprtioues 186 222 251 266 298 360 535 792 1,070 1,365 1,596 1,682 1,768 2,005 2,246 2,495 2,746

Service Ii.e Cstribotilon 145 167 287 22t 244 270 298 329 33 400 441 486 536 590 650 712 709

total S6wre Capital aod Rewrs 550 632 709 77 681 2 ,000 1,340 2,703 3,170 3,648 4,245 6,078 6,528 7,163 7,e30 8,557 9,317

Total Liabilltits nd Eqeity 1,t30 1,765 1,938 2,195 2,616 3,127 4,044 5,839 9,213 13,954 17,633 19,281 19,433 19,29 19,416 29,559 19,7t2

let tooq-ters DdtiEqoWtt 0.17 0.18 0.16 0.17 0.17 0.67 0.11 1.16 1.17 2.11 2.53 1.58 2.38 6.25 0.96 0.79 0.64torrent Ratio 1.40 2.0 1.39 1.30 1.34 1.27 0.93 1.39 1.39 1.42 1.48 1.32 1.27 1.32 1.36 t.48 1.

SEW32 P2IVATE P1M tUTILITIES i(sESI PRWEtTFinsocial Analysis

Statewnt of Sources I 'sts of fods R8 h II2 ioAtutal -------------- Projected

Fisal year ending 31st Itfch I9W5 19o6 I997 I 1989 1990 1991 2992 1993 1994 2995 1996 1997 199 199 7000 2012

U9wratmg Ilnte 90 99? III 109 224 1n3 373 423 587 763 903 1,693 1,916 1.979 1,99 1.92. 1,097OWKWlatiDO 31 29 37 40 39 49 63 72 E 89 99 333 569 SBO 593 07 622

total loteral Get atlo 121 127 149 250 163 220 436 495 667 954 I,C0I 2,026 2,404 2,560 2,542 2,529 2.309

9o-coovertible Odentares 20 20 0 0 0 0 0 0 0 0 0 0 0 0 0 U Ocov'tiblel M tnrf 0 0 0 0 0 O 0 1.050 0 1,000 500 0 0 0 O 9toan trot I2 0 0 0 0 0 0 0 569 990 1,520 720 699 0 0 0 0Loe fro tFt 0 0 0 0 0 0 0 230 410 530 230 70 0 0 0 0 Oloan Eros Indian Finonial Institutlons 0 0 0 0 0 9 0 0 2,360 720 1,090 230 0 0 0 0 QOtor ltn.-tere Ltes 0 0 0 20 25 35 0 0 0 0 O 0 0 O 0 0 9Chae doe to forueIg Etoc2a Varlation 0 0 0 0 0 0 0 57 202 244 245 264 240 160 265 144 t2

Total tsrourinls 20 20 0 20 25 35 0 t,847 2,742 4,904 2,M 1,154 240 260 2S5 144 132

Share taital 0 0 0 0 0 0 0 0 ,I00 0 0 1,500 0 0 0 0 0OtherSo Sces 69 99 72 112 129 105 95 95 99 103 1026 20 225 120 125 252 239

Total Soerts 209 203 222 282 317 M60 529 2,427 4,507 4,962 3,92 4,790 2,159 2,039 2,92 2,9Q4 2.779

PtiCAT2I a'C

loetat to Fled Besets:Geoeratiso &, trasisoni 0 0 0 0 0 30 651 2,390 2,970 4,092 2,510 2,009 0 0 0 0 d9,stribotih 94 95 125 183 207 226 256 264 254 293 313 323 343 352 m 4*2 4$2Ehao due to Foretqo Erchm arlatiu 0 0 0 0 0 0 0 57 101 244 245 264 155 60 SO It t2

Total lemstet in Flied kots 94 95 125 193 207 255 907 1,681 3,22S 4,517 3,068 1,587 49S 422 443 64 441

Interest Etpese 26 29 30 35 39 52 45 59 n 19 2t0 1,099 2,132 1,082 2,03 92 942Printipal Ripaywit:Loo fron IWO 0 0 0 9 0 0 0 0 0 0 0 0 347 356 365 375 24ton from IFt 0 0 0 0 0 0 0 0 0 0 0 178 1823 lI 192 197taan ffoe Indn Financlal ln ltetltei 0 0 0 0 0 0 0 0 0 0 0 0 0 327 327 327 327Otar Long-term osns 0 0 a 0 4 9 16 26 t6 17 7 0 0 0 0 0 9Fl lossn a loen repymt 0 0 0 O 0 0 0 0 0 0 0 0 87 100 i25 129 143

Total Det Serevce 26 28 30 35 4S 61 62 75 go 130 127 1,089 1,744 2,47 1,999 1,947 1,t93

iarp in torting Capital 68 67 29 29 46 13 14M61 57 06 l01 272 377 m 129 169 166 201Pamet of2 ot tax 4 7 9 94 0 0 0 0 0 II 273 0 0 0 o oFaywt ef Oividend 12 12 13 3 23 23 23 25 83 95 95 201 201 201 292 292 201Coo,wos,r,n d >etcrres 0 0 0 O 0 0 0 0 0 t,49 0 0 2,500 0 0 0 0 0Otber pllctatieos 4 4 14 8 9 9 26) 77 6 6 87 37 40 41 42 43 4a

Iota! 99p2icatio 209 293 221 292 317 30 529 2,427 4,507 4,991 3,891 4,791 2,739 2,940 2,932 2,904 2,77°

Oebt S,vire coesrap 4.40 4.26 6.59 3.92 L32 5.61 7.16 6.52 7.60 5.7t 4.43 1.896 2.3 1.25 2.27 2.30 2.33

INDIA

PRIVATE POWER UTILITIES (BSES) PROJECT

ESTIMATION OF. FINANCIAL INTERNAL RATE OF RETURN(in Million Rupees)

== = == = =============_=========5=Z____INCREMENTAL COSTS INCREMENTAL REVENUES NET

~--~---- --------------------------- FINANCIALFY ENDING CAPITAL O&M -3UB-TOTAL REVENUE SAVINGS SUB-TOTAL BENEFIT

1991 817.1 817.1 -817.11992 1028.0 1028.0 -1028.01993 2223.2 2223.2 -2223.21994 3051.9 3051.9 -3051.91995 1713.3 1713.3 -1713.31996 1104.9 1179.5 2284.4 367.5 1848.9 2216.4 -68.01997 1234.9 1234.9 742.5 1973.3 2715.8 1480.91998 1410.2 1410.2 1120.5 2094.7 3215.2 1805.01999 1410.4 1410.4 1501.5 1784.2 3285.7 1875.32000 1410.5 1410.5 1882.5 1473.8 3356.3 1945.82001 1410.7 1410.7 2263.5 1163.4 3426.9 2016.22002 1410.9 1410.9 2650.5 848.0 3498.5 2087.62003 1411.0 1411.0 3040.5 530.2 3570.7 2159.72004 1411.0 1411.0 3439.5 205.1 3644.6 2233.62005 1411.0 1411.0 3691.2 3691.2 2280.22006 1411.0 1411.0 3691.2 3691.2 2280.22007 1411.0 1411.0 3691.2 3691.2 2280.22008 1411.0 1411.0 3691.2 3691.2 2280.22009 1411.0 1411.0 3691.2 3691.2 2280.22010 1411.0 1411.0 3691.2 3691.2 2280.22011 1411.0 1411.0 3691.2 3691.2 2280.2UNTIL2019 1411.0 1411.0 3691.2 3691.2 2280.22020 1291.0 1291.0 3691.2 3691.2 2400.2

…- = ===== --=== =2==== ==== ====- …=======_ _ -_=__=____

FIRR : 1.0%

NET PRESENT VALUE AT 12% Re 1,949 Million

SfN

SECOND PRIVATE PONER UTILITIES (15ESI PRJECTFinancial halysisSnsitivity Tests Rs Nillion

---------------------- Projected--- --- - AARFiscal Year ending 31st Narch 1991 1M 1993 1994 ISff 19S6 1997 198 1999 2000 2001 1991-2001

Base Case (CIAveage Tariff (Rs/kVh) 1.39 1.51 I.64 1.77 1.90 1.96 2.05 2.09 2.17 2.27 2.39 5.51Debt Servire Cover 7.16 6.51 7.60 5.71 4.43 1.86 1.38 1.25 1.27 1.30 1.33

Coal Cost Intreasing 121 p.a. I(C 621Average Tariff (RsIb/h) 1.39 1.51 1.64 1.77 1.90 2.05 2.17 2.27 2.39 2.52 2.66 6.7!kebt Service Cover 7.16 6.51 7.60 5.,. 4.43 1.86 1.38 1.25 1.27 1.30 1.33

oad Factor 604 C 70DAvrage Tariff IRs/kibm 1.39 1.51 1.64 1.77 1.90 I.9 2.05 2.22 2.31 2.41 2.52 6-Debt Service Cover 7.16 6.51 7.60 5.71 4.43 1.86 1.38 1.25 1.27 1.30 1.33

Project Cost Overrn 20MAerage Tariff (RsitEh) 1.39 1.51 1.64 1.78 1.91 2.02 2.34 2.50 2.39 2.46 2.55 6.3!Dbt Service Cover 7.16 6.51 6.91 5.22 3.61 2.51 1.44 1.18 1.26 1.29 1.31

Psis Dvalu oa 102 p.a. (C 42)Average Tariff tRs/klh) 1.39 1.51 1.64 1.77 1.90 1.99 2.11 2.17 2.27 2.38 2.50 6.12Debt Service Cover 7.16 6.51 7.61 5.71 4.44 1.9I 1.26 1.13 1.12 1.11 1.09

Project Eacludiag fGD PlantAIerge Tariff (Rs/tkhl 1.39 1.51 1.64 1.77 1.89 1.93 2.02 2.07 2.15 2.25 2.35 5.42Debt Service Covr 7.16 6.51 7.80 6.09 4.63 1.75 1.30 1.21 1.22 1.25 1.27

-92-

Page 1 of 2INDIA

SECOND PRIVATE POWER UTILITIES (BSES) PROJECT

MAIN ASSUMPTIONS FOR FINANCIAL PROJECTIONS

1. Project Completion: First unit commissioned in January 1995, second unitcommissioned in July 1995. Revenues from commercial operations assumed to beginfrom FY1996.

2. Inflation Rates: Based on IBRD projections: International inflation at 3.41p.a.; Domestic inflation: FY1991 - 8.3X, FY1992 - 6.6X, FY1993 & FY1994 - 6.5Xp.a., FY1995 & FY1996 - 6.2X p.a., FY1997 - 6.11, thereafter 6.0% p.a.

3. Contingencies: Physical contingencies: 5X on plant and equipment, 10X oncivil works. Price contingencies: based on domestic and international inflationrates.

4. Exchange Rates: Based on IBRD projections, averaging about 4% p.a.devaluation of the Rupee versus the $, with Rsl9.43/$ in FY1991. Sensitivitydone for 101 Rupee devaluation.

5. Plant Load Factor: 50% in FY1996, 601 in FY1997, and 70X assumed thereafter.Energy delivered at the sub-stations: 1,953 GWh in FY1996, 2,344 GWh in FY1997and 2,734 GWh thereafter; net of 9% auxiliary consumption end 2% transmissionlosses.

6. Electricity Sales: Net generated energy sold: 1,758 GWh in FY1996, 2,110 GWhin FY1997, and 2,461 GWh thereafter; net of 101 distribution losses. Balanceenergy required to meet the demand of BSES's license area is purchased from TEC.

7. Power Purchase Cost: Rsl.10/kWh in FY1991, escalated thereafter based onprojected domestic inflation rates.

8. Coal Cost: Rs630/ton in FY1991 (base rate of Rsl90/ton plus transport costof Rs44C/ton), escalated thereafter based on projected domestic inflation rates.

9. OReration and Maintenance Expenses: Generation: 2.51 of capital cost inFY1996, escalated thereafter based on projected domestic inflation rates.Distribution: escalated based on projected domestic inflation rates.

10. Other Divisions: Revenues of electrical contracting and computer servicesescalated based on projected domestic inflation rates. Expenses of electricalcontracting at 951 of revenues and expenses of computer services at 701 ofrevenues.

11. Depreciation: Generation project: 3.61 p.a.; Distribution facilities: 3.5%to 4% p.a.; Other Divisions: as per Companies Act.

-93-

Annoy 4. 6Page 2 of 2

12. Interest Expenses: Non-convertible debentures: 15% p.a.; Convertibl'debentures: 12.51 p.a.; IBRD: 7.73% p.a. with 2.75% GOI guarantee fee and 0.25Xcommitment fee; IFC: 10.75X p.a. with 1% commitment fee and 1X front-end fee;Indian Financial Institutions: 14X p.a. for the first two years, 151 thereafterwith 1X front-end fee; Consumer deposits: 5.5% p.a.

13. Provision for Tax: At the present rates of corporate income tax prescribedunder the Indian Income Tax Act: 401 plus 8% surcharge (effective rate of 43.21).Because of the higher depreciation rates permissable under the Income Tax Act,BSES is projectid to have no tax liabilities for 8 years.

14. Provision for Dividend: Assumed at 18% p.a.

15. SRecial Reserves:(a) Project Cost: During project construction, BSES permitted by GOM to

charge RsO.03/kWh to its consumers and a further RsO.03/kWh reduction of purchaseprice from TEC, until BSES has accumulated Rsl,O0O million towards project costfunding.

(b) Contingency Reserve: 0.25X of original capital cost.(c) Repayment of Long-term Debt: For repayment of long-term debt including

losses on foreign exchange variations.(d) In lieu of Investment Allowance: Equivalent to the amount of Investment

Allowance previously permitted under the Income Tax Act.

16. Reasonable Return: 121 on capital base plus 0.51 on opening balance ofoutstanding loans from approved institutions.

17. Working CaDital: Minimum cash of RslOO million, inventories of 60 days supplyof coal, receivables of 50 days for sales of electricity and 3 month- f,r otherDivisions, other current assets pro,ected based on past trends. Payables forcoal purchases of 15 days, payables for purchase of power from TEC of 1 month,other current liabilities based on past trend-.

-94- Annex 5.1

INDIA

PRIVATE POWSR UTILITIES (BSES) PROJECT

WESTERN REGION POWER AID ENERGY DEMALID

Average AverageActual Growth Projected Growth

.. ............... ......... ...... .......... .... ...... ........... . ............ .

FY82 a/ FY90 FY82/FY9O FY95 bl FY2000 FY90/FY2000...... ........... .. ............ ............. ...... . ... ........ .. .

(Provisfonal) (K p.a) (t p.a)

1. PEAK LOAD (NW)

Gujarat Co 1,616 3.547 10.3X 5055 7160 7.3X

Nadhya Pradesh 1,107 2,894 12.8X 4792 7578 10.1X

Nharashtre d/ 2,996 5,883 8.8X 9353 13974 9.0X

Goa 82 117 4.5X 216 329 10.9X

Total 5,801 12,441 10.0X 19416 29041 8.8%............ ......... .... ...... ... .... .. ...........

Peak Availability 5,801 12,007 9.5X 19299 29041 9.2X

DefIcit - a/ 434 117 0

2. ENERGY REQUIREMENT (GUh)

Gujarat c/ 10,176 21,000 9.5X 27,343 38,729 6.3X

Madhya Pradesh 6,502 16,247 12.1X 27,041 42,721 10.2%

Naharashtra dV 18,127 35,155 8.6% 53,731 80,275 8.6X

Goa 284 549 8.6X 950 1455 10.2X

Total 35,089 72,951 9.6K 109,065 163,180 8.4X... ... .. ... . .. . ...... ........ ..... ...

Ener&y AvailabilIty 35,089 n,951 9.6X 109,065 163,180 8.4%

Deficit e/ nil 0 0

.............................................. ................................................................................. ,O ... @*........ .....

a/ Data for FY82 reflect actual consuptfon rather than poner and energy demands.No data avalable on the extent of urmot load or mount of unserved enery.

b/ Actual data for FY89 are not yet aviflble from CEc/ Including Ddra nd Nagar HavelIdV Includinr Dman and Dlu

Source: Thirteenth Electric Power Survey of India, CEA, Wstemn Regional ElectrIcIty Board and Bank eatimates.

-95- Annex 5.2Page 1 of 3

INDIA

PRIVATE POWER UTILITIES (BSES) PROJECT

WESTERN REGION INTERCONNECTED POWER SYSTEM

A. Details of Power Cuts and Regulatory Measures in Force During FY90

Maharashtra

1. The demand cut applicable for H.T. industrial consumers is as follows:

a) General Industries: 151b) Continuous Process: 101c) Textile Industries: 10o

2. There is no demand cut for industrial consumers up to a demand of 2,500MVA in areas outside Bombay Metropolitan and Pune Metropolitan Areas.

3. No energy cut.

4. 24 hours power supply to rural areas.

Guiarat

1. Generally no energy cut during the yp c.

2. Power supply to rural areas is available generally from 1200 to 2400

hours.

3. Demand cut for H.T. industries raziged from 0-252 between the months ofNovember 1989 and January 1990.

Madhya Pradesh

1. No demand cut throughout the year and power supply to rural areas is ona 24-hour basis, subject to the following regulatory measuress

a) H.T. Consumers: Staggering of weekly off.Single and two shift industries to workbetween 1400 and 2200 hours.

b) Mini Steel Plant: To draw power for 16 hours a day from 2200hours to 1400 hours of the following day.

c) New H.T. Consumers: Not subject to any power cuts for 2 to 5years depending on the area.

d) L.T. Consumers: Not subject to any power cut/restriction.

-96- Annex 5.2Page 2 of 3

e) Rural Discipline: Rural feeders are to be divided into twogroups. Three-phase supply is to bemaintained on these feeders.

f) Essential Services: Exempted from power cuts with theunderstanding that as and when desired by theBoard, they wiil reduce their load to theextent requested by the Board.

Goa

No power cuts during the year.

B. Existing and Planned Capacities in Maharashtra

1. Existing Capacity as of March 31, 1990Total

InstalledParticulars Capacity (MW)

Number of Units x KWHydro

1. Koyna 4 x 65; 4 x 75; 4 x 80 880.02. Tillari 60.03. Koyna DPH 2 x 20 40.04. Eldari 3 x 7.5 22.55. Vir 2 x 4.5 9.06. Bhatgar 16.07. Radhanagari 4 x 1.2 4.88. Vaitarna 60.09. Vaitarna-Dam toe 1 x 1.5 1.5

10. Tata Electric Cos. Bhira - 6 x 25 ) 294.0Bhivpuri - 6 x 12 )Khopoli - 6 x 12)

11. Bhira Tailrace 2 x 40 80.012. Paithan 12.013. Pench 1/3 Share 53.014. Bhandardara 10.015. Pawna 10.0

1,552.8

Annex 5.2Page 3 of 3

TotalInstalled

Particulars Capacity (MW)Number of Units x MW

Thermal

1. Nasik 2 x 140; 3 x 210 910.02. Trombay 1, 2 & 3 3 x 62.5 187.5

3. Trombay 4, 5 & 6 1 x 150 ) 1,150.01 x 500 )1 x 500 )

4. Koradi 1,100.05. Bhusaval 482.56. Paras 92.5

7. Parli 2 x 30 ) 690.03 x 210)

8. Khaperkheda 3 x 30 ) 510.02 x 210 )

9. Uran (Gas) 672.010. Chandrapur 840.0

6,634.5

2. Planned Additions by 1994-95 in accordance with the survey

Hydro WIT Thermal MW

1. Bhatsa 15 1. Chandrapur 1,0002. Khadakwasla 16 2. Khaper Kheda Extn II-IV 6303. Ujjani 12 3. Uran Waste Heat 2404. Kanher 4 4. Dahanu 500.5. Dhom 2 -6. Terwanmedh 0.2 2,3707. Warna 16 -----8. Manikodh 69. Surya 610. Dimbhe 511. Duganga 2412. Bhandara Ph2 3413. Koyna IV 1,000 a/

1,140.2

a/ Unlikely to be commissioned fully by 1994-95 and thus peakingdeficits will further increase.

-98-

Annex5.3Page 1 of 2

INDIA

PRIYATE POERB UTILITIES IBSES) PROJECT

sconomic Analysis

Eatimation of Consumer Surplus

I. AGRICULTUR1% CONSUMRSB

The economic value of consumers' willingness-to-pay for publicelectricity for irrigation is estimated as the electricity rate which equates theeconomic costs of diesel and electric irrigation pumping.

Estimated Costs of Dieoel and Electric Pumo-ing

Blactric Diesel

Motor/Engine Size (H.P.) 5.0 a/ 7.0Pump Lifetime (years) 15.0 10.0Pump Capital Cost (Rs) 4,440 11,365Annual Charge (Rs) 652 2,0110 & M Costs (RS) 1,017 2,857Costs of Diesel Fuel (Rs/hr.) / - 8.8Annual Diesel Costs (Rs) 7,000Cost of Electricity (paise/kWh) XXX g/ -

Total Annual Cost 1,699 + 2,984(NXXX 11.868

Electricity rate at which electric and diesel pumping costs the same:

Paise XXX/kWh - (11,868 - 1,699)/2,984- Paise 341 psr kWh

A/ I M.P. - 0.746 kW.k/ Assuming an economic price of high speed diesel of Rs 3.5 per liter, and

consumption of 2.5 litres per hour and operation for 800 hours per year.c/ 2,984 a 5 x 0.746 x 800.

-99-

Annex 5.3Page 2 of 2

INDIA

PRIVATE POWER UTILITIES .IBES1 PROJECT

Economic Analysis

estimation of Consumer SurDlus

II I. 2 R SRS

Consumers' willingness-to-pay for public electricity is related tothe additional financial cost that would be incurred through private supply.Correspondingly, the economic value of this willingness-to-pay is related to theeconomic costs of private supply, which are estimated below.

Estimated Costs of Autoceneration

_ Cost oer kW of Ca2acity (Rg1SO km--Machine 200-400 kW Machine

Capital Cost a/ 6,300 4,420Annual Charge 9/ 925 649Salaries 668 449Maintenance 134 92

Total annual Fixed Costs 1,727 1,190

Cost 2er kWh Generated (Paisel2. Variable Costs

Diesel Fuel £J 140 112Lubricant 4 4

Total Variable Costs 144 116

3. Fixed Costs at 15% Load Factor 4/ 131 91

4. Average Cost of Generation am 2QZ

A/ C.1.F. price, plus handling and installation.k/ Assumlng a 15-year life and 12% discount rate.I/ Assuming an economlc cost of high speed diesel of Rs 3.5 per liter and

specific consumptLon rates of 0.4 liter per kWh and 0.32 liter per kWh,

respectively in the 50 kW and 200-400 kW machine;.4/ CRA's estimate of the average load factor of private generators.

-100-

Annex 5JPage 1 of 2

INDIA

PRIVATE POWER UTILITIES fDSES) PROJECT

Economic Ain_ysis

Western Reoin Exvansion Proaram

Summary of AssumDt-ions

FY91 to FY2000 investment time slice, including only those projectsthat would be implemented fully during the period. Constructionperiods assumed are: coal-fired - 5 years; hydro stations - 8 years;gas-fired - 3 years.

Station capital costs in January 1991 prices are estimated at: coalstations - Rs 14,260 per kW; hydro stations - Rs 11,250 per kW; andgas stations at Rs 6.500 per kW (average cost of retrofitted andnew units).

Associated transmission and distribution investments assumed to beequivalent to 60% of generation investments.

-Annual operating and maintenance costs are assumed as: coal-firedand gas-fired stations - 2.5% of station capital costs; hydrostations - 1.1% of station capital costs; and T&D - 1% of capitalcosts.

Average fuel consumptions of new stations are assumed as: coalstations - 0.6 kg/kWh of coal and 10 ml/kWh of oil; and gas stationsat 0.23 cu.m./kWh .

Economic fuel costs are assumed as: coal - Rs 360 per tonne (averageof pithead and load center stations); oil- Rs 2.7 per litre; and gas- Re 2,200 per thousand cu.m. For pumped-storage projects, fuelcosts are based on coal at Re 520 per tonne.

Annual generation by new stations is assumed as : coal - 1,000 hoursLn the first year, 3,500 hours in second year, and 6,150 hru peryear thereafter; gas - 6,000 hours per year; hydro - 2600 hoursper year; and pumped storage (excluding Bihar) 2,200 hours per year.

Consumption by station auxiliary equilpment is assumed ass coal - 10%of gross generation; gas - 2%, and hydro - 1.

Transmission and distribution losses are assumed as 20% in FY 91declining to 15% by FY2000.

INDIAPRIVATE POWER UTILIlIES (BSES) PROJCCT

Economi Analysis

Vestern Regia, Expansion ProgramNPV at 12X : Rs 187.345 sillion

(Rupees 4illion) EIRR : 25.2X

Fiscal Capital Costs Operating Costs Incresental Benefits TOTALYear --------------------------------------------- --------------------------------- TOTAL ---------------------------------- TOTAL METending Thermal Hydro Gas T&D Sub-total Fuel Gen CSM T&D OS Sub-total COSTS sales Reverue Consu4er Surplus 3ENEFITS BEFITS

a/ bI1991 2438 760 3071 6269 6269 -62691992 6473 1000 4711 12184 12184 -121841993 14970 2595 5557 23122 23122 -231221994 18349 4079 1887 24314 24314 -243141995 22954 5186 11356 39495 7681 998 8679 48174 13280 11421 13546 24MI6 -232081996 255Z0 6800 17034 49353 9013 1446 10459 59812 19619 16b72 20011 36PR4 -229281997 23552 7106 17034 47692 11172 1952 454 13579 61270 26313 22629 26839 494S8 -118021998 15041 5561 22712 43314 13306 2774 681 16761 60075 34035 29270 34716 63986 39101999 6002 2976 22712 31690 16372 3690 908 20969 52659 44790 38519 45686 84205 315462000 1426 1166 11356 13948 19746 4219 1022 24987 38934 56971 48995 58110 107105 681712001 11356 11356 21808 4219 1135 27162 38518 63363 54493 64631 119123 806052002 22461 4219 1211 27892 27892 65391 5S236 66698 122934 95042 12003 22461 4219 1211 27892 27892 65391 56236 66698 122934 95042 P-2004 22461 4219 1211 27892 2789r. 65391 56236 66698 122934 95042 02005 22461 4219 1211 27892 27892 65391 56236 66696 122934 95042unti I2021 22461 4219 1211 27892 27892 65391 56236 66696 122934 95042

a/ Based on average economic tariff level of Rs 0.86 per kWhbJ Coansw surplus estimated at Rs 1.02 per kWl.

Source: Bank and CEA estimates

0.> *pJ 4

-102-

Annex 5.5

INDIA

PRIVATE POWER UTILITIES I3BSES PROJECT

EconomLc Analysis

Rgulte of Sensitivitv Analysis of Wegtern Realonal Proaram

XIRR NPV at 12%I 1 1 (In Re BDllionsl

Dame Case 25.2 187

Without ConsumerSurplus Value 7.0 (55)

Higher program costes10% 22.6 16125% 19.3 1225C% 15.0 57

Lower program benefits:10% 22.3 14325% 17.8 7550% 8.8 (36)

Program delays:One year 21.4 151Two years _8.7 118Three years 16.7 87

INDIAPRIVATE POWER UTILITIES (BSES) PROJECT

ECONOMIC ANALYSIS

ENERGY DISPATCH FROM DAHANU THERMAL POWER PLANT TO THE WESTERN GRID

PROJECT'S IMPACT ON GRID DAHANU OPERATIONREGIONAL --------------- ________________ ---------------------------FY SYSTEM ADDITIONAL ENERGY NET GROSS PLANTENDING REQUIREMENT a/ INPUT b/ DISPLACEMENT b/ GEN c/ GEN L.F.… ---------------------- …----------------------- --- ------- _______GWh GWh GWh GWh GWh GWh

1995 1090651996 118177 201 1792 1993 2190 0.5001997 128094 1832 559 2391 2628 0.6001998 138151 2140 650 2790 3066 0.7001999 150518 2333 457 2790 3066 0.700 o2000 163180 2480 310 2790 3066 0.7002001 176887 2653 137 2790 3066 0.7002002 191746 2790 2790 3066 0.7002003 207852 2790 2790 3066 0.7002004 225312 2790 2790 3066 0.7002005 244238 2790 2790 3066 0.7002006 264754 2790 2790 3066 0.700

___________________________

a/ Assumes 64% system load factor from FY2002 and thereafterb/ Based on CEA's simulation of system generation dispatch and resulting LOLP and levels ofunserved energy with and without the project.c/ 9% station use for Dahanu Thermal Plant

-104-

Annex- 57Page 1 of 2

INDIA

PRIVATE POWER UTILITIES 1lSESl_ ROJECT

Economic Analvais

.; ,. n_of the Project's Economic Internal Rate of Return

Summary of Assumptions

Among the cost elements (expressed in January 1991 prices) considered inestimating the economic costs of the project are:

a) Direct capital costs, inclusive of physical contingencies, for thethermal station, FGD plant, and associated transmission anddistribution facilities; subject to exclusion of taxes and dutiesand to a standard conversion factor (SCF) of 0.8 on the localcurrency components. Residential and commercial wiring costs of Rs1,300 per kW additional load connection.

b) operating and maintenance expenses for generation equivalent to 2.5%of capital costs of the thermal station; for transmission - 1.0% ofline investment; and for distribution - Rs 200 per additional kVAconnection based on prevailing levels.

C) Coal expense based on an ex-mine cost of Rs 167 per ton plustransport cost of Rs 443 per ton and coal consumption of 0.60kg/kWh. Fuel oil expense is based on an economic price of Rs 2,700per liter and consumption of 10 ml/kWh.

d) Plant load build-up is assumed at 50% plant factor during the firstyear of commissioning, 60% during the second year and 70%thereafter.

In evaluating the benefits derived from the project, the followingparameters were assumed:

e) Energy losses reflecting Dahanu thermal station use of 9% of grossgeneration; transmission loss of 2% from the station to the loadcenter; 10% distribution losses within BSES service area.

f) An average tariff of Re 1.50 per kWh, subject to 0.8 SCF, forincremental energy sales attributable to the operation of the DahanuThermal Station; consumer surplus value among BSES consumersestimated at Rs 0.64 per kWh.

g) Cost savings due to displacement of less efficient thermalgeneration estimated at Rs 0.50 per kWh.

INDIA

PRIVATE POWER UTILITIES (BSES) PROJECT

ESTIMATION OF ECONOMIC INTERNAL RATE OF RETURN FOR THE PROJECT(in Million Rupees)

INCREMENTAL COSTS W/ FGD INCREMENTAL BENEFITS NET------ ~~~~~~~~~~~~~~~~~~~~ ------------------------------------ ECONOMICFY ENDING CAPITAL O&M SUB-TOTAL TARIFF C.SURPLUS SAVINGS SUB-TOTAL BENEFIT-----------------------------------------------------------__----------------__-----------------

1991 672.9 672.9 -672.91992 806.2 806.2 -806.21993 1742.7 1742.7 -1742.71994 2361.1 2361.1 -2361.11995 1302.8 1302.8 -1302.81996 932.0 1001.5 1933.5 217.1 115.8 896.0 1228.9 -704.61997 69.0 1172.4 1241.4 1978.6 1055.2 279.7 3313.5 2072.11998 71.4 1343.3 1414.7 2311.2 1232.6 325.0 2868.8 2454.11999 76.1 1343.5 1419.6 2519.6 1343.8 228.5 4091.9 2672.3 o2000 78.4 1343.6 1422.0 2678.4 1428.5 155.0 4261.9 2839.9 VI2001 81.9 1343.7 1425.6 2865.2 1528.1 68.5 4461.8 3036.22002 62.6 1343.8 1406.4 3016.4 1608.8 4625.2 3218.82003 67.0 1344.0 1411.0 3016.4 1608.8 4625.2 3214.22004 68.5 1344.0 1412.5 3016.4 1608.8 4625.2 3212.72005 1344.0 1344.0 3016.4 1608.8 4625.2 3281.2until2020 1344.0 1344.0 3016.4 1608.8 4625.2 3281.2

EIRR : 21.99%

NET PRESENT VALUE AT 12% : Rs 6,501 Million

0 0vK tD

0ao .J

-106-

Annex 5.8

INDIA

PRIVATE POWER UTILITIES (BSES) PROJECT

Economic AnalVsis

Results of Sensitivity AnalvEis for the Pronosed Proiect

EIRR NPV at 12%( % I (In Rs Millionsl

Base Case 22.0 6,501

Without ConsumerSurplus Value 13.3 677

Without FGD plant 22.9 6,853

Higher project costs:10% 20.6 5,96425% 18.8 5,15750% 16.5 3,812

Lower benefits:10% 19.6 4,74025% 15.7 2,09950% 6.9 (2,303)

Project delays:One year 19.4 5,131Two years 17.4 3,907Three years 15.8 2,814

Project cost overrunsand lower benefit combined:

10% 18.4 4,20325% 13.1 755

-107-

Annex 5.9Page 1 of 2

INDIA

PRIVATE POWER UTILITIES (BSESI PROJECT

Economic Analysis

Evaluation of a Combined-Cycle Alternative

The comparative economics of a combined-cycle alternative vis-a-visthe project was examined notwithstanding the fact that the gas supply situationin the Bombay area is presently not conducive for setting up a gas-based plantfor BSES. The results indicate that while the combined-cycle alternative wouldhave been able to serve more load in the system because of its operationalflexibility for intermediate loading, the proposed Dahanu thermal stdtion remainscompetitive due to the relatively attractive bid offer received for thegeneration equipment and the relatively higher fuel expense attached to gas usegiven the limited supply and large potential demand.

For purposes of the economic analysis, two estimates of the capitalcost of a combined-cycle facility were taken, i.e., at at the conservative priceof US$600 per kW and at US$730 per kW installed including site development costs.The latter estimate is based on the latest price offers received for the mainplant turnkey contract for one of NTPC's gas projects and follows recent upwardtrend in costs of combined-cycle plants in the world market. Gas pipeline costsserving the power plant installation, in this case from the Hazira terminal, wastaken at $25 million (at USS 250,000 per km of pipeline). The economic value ofnew gas supply in the area is estimated to be about Rs 2,200 per thousand cu.m.and approximates the equivalent fuel oil price parity (at US$20 per barrel ofcrude) for gas use among industries in the Bombay area. The heat value of gasis estimated at 8,500 kcal per cu.m., and the power plant's heat rate at 2,000kcal per kWh. The plant's auxiliary consumption is assumed to be equivalent to3% of gross generation.

The following table presents the derived economic rate of returnfor a combined-cycle alternative relative to that of the proposed project:

Table 1. Com3arative Economics of the Combined-Cycle Alternativevs. the Proposed Project

EIRR NPV at 12 %M8) (In Rs. Millions)

Combined-Cycleat US$600 per kW 22.9 6,545at US$730 per kW 20.7 5,742

Proposed Projectwith FGD 22.0 6,501without FGD 22.9 6,853

-108-

Annex 5.9Page 2 of 2

The differences in economic yields between the proposed project and acombined-cycle plant are hardly significant, such that modest variations in costparameters, particularly with respect to capital cost and fuel price movements,can shift the economic advantage of one scheme over the other. For example: evenagainst a low combined-cycle plant cost of about US$600 pe;: kW installed, the NPVat a 12% discount rate of the proposed project is sufficiently attractive, andmore so if the FOD unit is excluded. The cur- nt tight international market forgas-based plants also enhances the project'B attractiveness.

In any case, the non-availability of assured long-term gas supply has beena critical factor for not pursuing a combined-cycle plant option. Nevertheless,to cover the possibility of increased gas reserves becoming available in theBombay area and assuming that future gas market conditions result in a lowereconomic value attached to gas, the proposed plant's boilers has been designedfor dual-firing (coal or gas). The operational efficiency associated with thecombined-cycle operation would not, however, be attained.

-109-Annex 6.1

INDIA

PRIVATE POWER UTILITIES (BSES) PROJECT

Documents in Prolect File

1. 2x250 MW Thermal Power Station in Western Maharashtra -- FeasibilityReport; BSES; August 1988.

2. Basic Information for Environmental Appraisal; BSES; June 1987.

3. Environmental Impact Assessment -- Supplementary Report; BSES; 1988.

4. Flue Gas Desulphurization Relevance in Indian Context; BSES; 1988.

5. Environmental Appraisal for the Dahanu Thermal Electric Project; JamesH. Trall (IBRD/IFC Consultant); Harza Engineering Company; October 1989.

6. The Dahanu Thermal Power Project - A Social Impact ReconnaissanceReport; Jasper Ingersoll (IBRD/IFC Consultant); October 1989.

7. Dahanu Thermal Power Station; BSES: October 1989 (Booklets 1 and 3).

8. Discussion Material Provided by BSES to October 1989, July 1990, October1990, and February 1991 Joint IBRD/IFC Missions.

9. Due Diligence Plan (Environment) -- Status Report; BSES; January 15,1991 (two volumes).

10. Organization Structure; BSES; January and April 1990.

11. Action Plan for Human Resource Development; BSES; 1990.

12. Environmental Assessment; IBRD/IFC Consultant and Project Team;May 1991.

.. ____________________ _ .l_ _IBRD 229 f

I N D I A

SECOND PRIVATE POWER UTILITIES PROJECT (BSES)DHLYA46 VAHM DAHANU THERMAL POWER STATION AND

o ASSOCIATED TRANSMISSION AND DISTRIBUlION DEVELOPMENT

. PROPOSED POWER STATIONDAHANJ) COAL FIRED 0 PROPOSED SUB STATIONS

rAHANUO EPOWESTATION - PROPOSED 220 kV TRANSMISSION LINES

BSES SUPPLY AREA

liSf o i ^ BEST SUPPLY AREATAkWROPA AM KHURD

BOISAR USAKHURD ^ EXISTING TARAPUR POWER STATION* EXISTING SUB STATION

EXISTING 220 kV TARAPUR-BORIVLI ANDTARAPUR-GUJARAT TRANSMISSION LINES OF MSEB

RIVERS

O SELECTED TOWNS

MO,HiMAO 0'F \Ao r

GHODBlKD / g ,4_ H R

TUPADE 0

IL ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~~~-

U -|- 6 *j ZO0M FA 1- 7 KL ,

V\>j (/Y 9MM

BOMBAY 4:/,, -(

, ( TUR^DEO o - r*ns*Beaivoflo-Slot,

APRIL 1991