world bank document of the world bank for ofmicial use only report no- 5410-in staff appraisal...

Document of

The World Bank

FOR OFmICIAL USE ONLY

Report No- 5410-IN

STAFF APPRAISAL REPORT

RIHAND POWER TRANSMISSION PROJECT

May 3, 1985

Power and-Transportation Division

South Asia Projects Department

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

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CURRENCY EQUIVALENTTS

Currency Unit = Rupees (Rs)Rs 1.00 = Paise 100US$1.00 = Rs 12.00 1/Rs 1.CO = US$0.0833 1/Rs 1,000.000 = US$83,333.3

MEASURES AND EQUIVALENT

1 Kilometer (kin) = 1,000 meters (m) = 0.62L4 miles (mi)1 Meter (m) = 39.37 inches (in)I Cubic Meter (m3) - 1.31 cubic yard (cu yd) = 35.35 cubic feet (cu ft)1 Ton (t) = 1 metric ton = 2.200 pounds (lbs)1 Kilovolt (kV) - 1,000 volts (V)1 Kilovolt ampere (kVA) = 1.000 volt-amperes (VA)L Megawatt (MW) = 1,000 kilowatts (kW) = 1 milLion wattsi Kilowatt-hour (kWh) = 1.000 watt-hours1 Megawatt-hour (Mwh) = 1,000 kilowatt-hours1 Gigawatt-hour (GWh) 1,o0o,000 kilowatt-hoursI Mega volt ampere (MVA) = 1,000 kilovolt ampere

ABBREVIATIONS AND ACRON!YMS

AC - Alternating CurrentCEA - Central Electricity AuthorityDAE - Department of Atomic EnergyDC - Direct CurrentDESU - Delhi Electricity Supply UndertakingE.hV - Extra High VoltageHPSEB - Himachal Pradesh State Electricity BoardHSEB - Haryana State Electricity BoardHVDC - High Voltage Direct CurrentGEB - Coa Electricity BoardGot - Government of IndiaICB - International Competitive BiddingJKSEB - Jammu and Kashmir State Electricity BoardLCB - Local Competitive BiddingLRMC - Long Run MarginaL CostMPSEB - Madhya Pradesh State Electricity BoardMOU - Memorandum of UnderstandingNHPC - National Hydro Electric Power Corporation Ltd.NPP - - National Power PlanNREB - Northern Region Electricity BoardNTPC - National Thermal Power Corporation Ltd.PLCC - Power Line Carrier CommunicationPSEB - Punjab Stace Electricity BoardREB - Regional Electricity BoardREC - Rural Electrification CorporationRSEB - Rajasthan State Electricity BoardSEB - State Electricity BoardTOE - Ton of Oil EquivalentUPSEB - Uttar Pradesh State Electricity Board

NTPC's FISCAL YEAR (FY')

April 1 - Karch 31

1I The US$/Rs exchange rate is subject to change. Conversions in thisreport have been made at US$1 to Rs 12.0, which represents the projectedexchange rate over the disbursement period.

FOR ORmCIL USE ONLY

INDIA


OAN AND PROJECT SUMMARY

Borrower: India, acting by its President

Beneficiary: National Thermal Power Corporation Ltd. (NTPC)

Amount: US$250 million.

Terms: Repayment over 20 years, including five yearsgrace, at the applicable rate of interest.

Onlending Terms: From the Government of India (GOI) to NTPC,with repayment over 20 years, including five years'grace, at an interest rate of not less than 12.52per annum. GOI would bear the foreign exchangeand interest risks.

Project Description: The Project's main objective is to help meet thedemand for electricity in the Northern Region ofIndia by providing transmission linkage betweenthe thermal power plants at Singrauli-Riband inthe State of Uttar Pradesh and the main loadcenters in the Northern Region, and to ensure theevacuation of pover from these plants at leastcost to the economy. The Project comprises theinstallation of about 910 km of 500-kV directcurrent (DC) power transmission line betweenRihand and Delhi, and the associated convertingstations, together with about 1,450 km of 400-kValternating current (AC) lines connectingSingrauli-Rihand with the main load centers atKanpur, Delhi, Panipat and Jaipur and relatedsubstations in the Northern Region. The Projectwill introduce long-distance high-voltage directcurrent (HVDC) power transmission technology inIndia. There are no risks other than those nor-mally associaLed with this type of Project. NTPCwill be assisted by consultants for implementationof the DC component. NTPC has gained experiencewith transmission and installation so risk ofslippage wiLl be minimal. Most of the majorequipment components with the exceptionof the converting stations, are manufactured inIndia, and there is zdequate understanding of, andexperience with their installation.

This docment ha a resticied disibutwn and may be used by recipients only in the perfornumce ofthei offidl dues Its contents may not otherwie be dicosed without World Bank authorition.

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Estimated Cost:l/Local Foreign Total Local Foreign Total-- Rs million--- ----- US$ million

400-kV AC lines 1,091.2 407.8 1,499.0 90.9 34.0 124.9400-kV AC substations 981.8 140.0 1,121.8 81.8 11.7 93.5HVDC line 661.9 302.1 964.0 55.2 25.1 80.3BVDC terminals 785.2 1,464.8 2,250.0 65.4 122.1 187.5Consultancy and - 55.0 55.0 - 4.6 4.6Technical Assistance

Engineering andAdministration 390.1 - 390.1 32.5 - 32.5Total Base Cost 3,910.2 2,369.7 6,279.9 325.3 197.5 523.3

Physical Contingencies 202.6 115.8 318.4 16.9 9.6 26.5Price Contingencies 721.6 670.4 1,392.0 60.2 55.9 116.1Total Project Cost 4,834.4 3,155.9 7,990.3 402.9 263.0 665.9

Interest during Construction

Bank - 224.9 224.9 - 18.8 18.8Other 99.8 - 99.8 8.3 - 8.3

Front-End Fee - 0.0 0.0 - 0.0 0.0Total Financing Required 4,934.2 3,380.8 8,315.0 411.2 281.8 693.0

Financing Plan: Local Foreign Total(US$Million) ------

IBRD Loan 122.0 128.0 250.0Cofinancing 135.0 135.0GOI and NTPC 289.2 18.8 308.0

Total 411.2 281.8 693.0

Estimated Disbursements:

Bank FY FY86 FY87 FY88 FY89 FY90-------------- (US$Million) -----

Annual 23.0 64.5 81.0 45.0 36.5Cumulative 23.0 87.5 168.5 213.5 250.0

Rate of Return: 13%

I/ Includes taxes and duties of about US$86.7 million.

INDIA



Table of Contents

Page No.

Loan and Project Summary ................................... i

r. SECTORAL CONTEXT ........................................... 1

Commercial Energy Resources ............................. _.1Supply and Demand of Electricity - India ................... 2Organization of the Power Subsector .................. 2Pricing and Resource i-lobilization ..... .............. 3Power Subsector Planning ................................... 4Management and Operations - ... 4Bank Group Participation in the Past ..... ............ SBank Group Strategy in the Power Subsector ................ . 6Power Supply and Demand in the Northern Region ............ . 7

II. THE BENEFICIARY - NATIONAL THERMAL POWER CORPORATION LIMITED 9

Existing Facilities and Development Program . . 9Organization and Management ............................... 9Recruitment and Training ................................... 10

III. THE PROJECT ........................ _ . . ... 12

Project Setting ....................... 12Project Objectives ...................... ................... 12Project Description ...................... .................. 13Project Cost ............................................... 13Project Financing ................ 15Engineering and Studies ....... ............................. 15Construction and Procurement ............... .. .............. 16Project Implementation and Completion ...................... 20Disbursement ............................................... 20Ecology ............. ...... 21Project Risks ............. ............... 21Project Monitoring .......................................... 21

This report has been prepared by Messrs. E. Linard de Guertechin(Power Engineer), John B. Creasor (Financial Analyst) and Wynne P. Jones(Economist).

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Page No.

IV* FINANCE ................................................. o ............. 22

Accounting Organization and Systems ........................ 22Past Performance and Present Financial Position ........... . 22Future Investment ........... ........ e ... 25Future Performance and Financial Position .................. 25NTPC's RegionaL Tariffs .................................... 29Commercial Arrangements for Sale of NTPC Power ............ . 30Taxation ................................... ................ 31Bank Loan for the Proposed Project ......................... 31Audit ...................................................... 32

V. PROJECT JUSTIFICATION AND ECONOMIC ANALYSIS ................ 33

Least Cost Alternative ..................................... 33Internal Economic Rate of Return ........................... 33Justification for Bank Involvement ......................... 35

VI. AGREEMENTS AND RECOMMENDATIONS ............................. 36

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ANNEXESPage No.

1.1 Electricity Generation, Sale and Pattern of EnergyConsumption - All India * ................................ 38

1.2 Forecast of Regional Power Demand in India FY86 - FY92 ..... 391.3 Electricity Generation and Consumption of Northern Region... 401.4 Power Supply Position of Northern Region .................... 412.1 NTPC - Generation Facilities - Operational Performances .. 422.2 Schedule of Cohmissioning of Power Plants .................. 432.3 NTPC - Organizational Structure ........................... 453.1 Project Description ......................... 463.2 Project Cost Sumary ................... .......*...... 543.3 Project Implementation Schedule ............................ 552.4 Estimated Schedule of Disbursement ......................... 564.1 Investment Program . ............................. *... .. 574.2 Financing Plan Covering Fiscal Years FY'77 througb FY'96 ... 594.3 Consolidated Income Statements Covering Operations FY'83

through FY'96 ............................................ 604.4 Balance Sheets Covering FY'83 through FY'96 ................ 614.5 Statement of Source and Application of Funds Covering

Operations FY'83 through FY'96 ........................... 624.6 Rate of Return on Net Revalued Assets Covering FY'83

through FY'96 ............... .O.*...**.**.*.*.*****.... * 634.7 Projected Regional Tariffs versus Long-Run Marginal Costs ... 644.8 Assumptions for NTPC Financial Projection................... 654.9 Comercial Arrangements for Sale of NTPC Power.............. 725.1 Internal Economic Rate of Return ........................... 746.1 Related Documents in Project File ........................... 78

MAP IBRD 18595R

INDIA

RIHAND POUER TRANSMISSION PROJECT


I. SECTORAL CONTEXT

Comercial Energy Resources

1.01 India's commerciaLly exploitable energy resources consist of coal,oil, gas, hydro, uranium, and thorium. Of the nonrenewable resources, coalis the most abundant. Reserves of thermal coal have been estimated atslightly more than 100 billion tons, of which 25 billion tons are proven.Although reserves are ample, the quality of coal produced is generally lowand is deteriorating. Proven and probable petroleum reserves compriseapproximately 530 million tons of oil and 390 million toe of natural gas.Despite recent increases in domestic production, India still imports 35% ofits oil requirements, which in 1983/84 cost the equivalent of 40Z of itsmerchandise exports. Consequently, the Government of India (GOI) hasattempted to stimulate exploration while restricting petroleum and naturalgas consumption by emphasizing premium uses such as transportation,petrochemicals and fertilizer. However, in the case of natural gas, the slowdevelopment of premium uses has led to substantial volumes of associated gasbeing flared. India's hydroelectric potential is about 100,000 MW. Atpresent, only 13,000 KW have been developed, 4,700 "s4 are under construction,and a further 23,000 KW are being studied for future development. Theprominent role of hydro in regional least-cost development plans prepared in1982 has led COI to emphasize the need to accelerate its development;however, progress has been slow owing to the limited resources available forthe simultaneous preparation of a large number of schemes and the timerequired to resolve water rights and environmental issues. The country'suranium reserves could support a modest nuclear program (8,000-10,000 MW),and its thorium reserves are enough for a large fast breeder program.

1.02 Planning the best use of India's indigenous energy resources forpower generation raises a number of issues. First, the high ash content ofcoal, which can reach 50%, increases transport costs, s well as power sta-tion capital and operating costs. The development of minemouth stations,which is constrained by pollution limitations and the availability of coolingwater, helps to solve only the transport problem, and thus priority needs tobe given to more selective mining and improved coal preparation. Even thougha lower ash content might help to alleviate transport problems, they wouldstill persist. Two studies included in the Dudhichua Coal Project (Loan2393-IN) are designed to help formulate a strategy to deal with theseproblems: one study will examine ways of improving the linkages between thesources of supply and demand, and the other will concentrate on improvmentsin handling and transportation facilities. Second, with the recent increasesin the supplies of both associated and free gas, there is a need for a

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coherent policy on the utilization of gas. A Bank study planned for 1985will focus on, among other things, the potential for the economic use of gasin power generation. Third, if hydro development is to accelerate, furtherresources, including consultants if necessary, need to be deployed to preparehydro schemes. Furthermore, if water rights and environmental issues cannotbe resolved quickLy, appropriate procedures need to be initiated to ensurethat an adequate number of schemes are available for development.

Supply and Demand of Electricity - India

1.03 Approximately 5OZ of India's electricity is generated from coal, 40%from hydro, and the rest from oil, nuclear power, and natural gas. Althougha number of large thermal projects are planned for the short term, the shareof hydro is expected to increase in the long run. Electricity losses haverisen slowly but steadily over the last few years and now exceed 26% of grossgeneration. The deteriorating quality of coal has been at least partlyresponsible for this trend, with coal stations' own consumption now approach-ing 10% of gross generation against a desirable 5% or 6%. Distributionnetworks have been overloaded because inadequate attention has been given tosystematic analysis and planning of this part of the system. As a result,distribution losses are high by generally accepted standards and, althoughthey are lower than in several countries in the region, they need to bereduced. Under its lending program, the Bank has supported pilot studies toreduce system losses, and it will continue to follow this approach in itsfuture lending. However the Bank can only pursue this on a State-by-Statebasis, with loss reduction targets reflecting the particular circumstances ofeach State.

1.04 Over the past two decades, the consumption of electricity has grownapproximately twice as fast as total comercial energy consumption and nowaccounts for more than 30% of the latter. As a result, shortages haveprevailed throughout the country and, during the last five years, averaged anestimated 13% of electricity requirements. The principal sectoral shares oftotal electricity consumption are: industrial, 56%; agricultural, 19X; anddomestic, 12% (Annex 1.1). Agriculture's share has grown steadily owing toincreased electrical irrigation pumping made possible by rural electrifica-tion and encouraged by heavy subsidies. Total consumption has grown at anaverage rate of 10X per annum during the past two decades, and the CentralElectricity Authority (CEA) has forecast growth of 9% per annum between1984/85 and 1989/90 (Annex 1.2). Whether such growth can take place willdepend on the utilities' success in installing new capacity.

Organization of the Power Subsector

1.05 Responsibility for the suppLy of electricity is shared between theCentral and State Governments. The State Electricity Boards (SEBs) and theRegional Electricity Boards (REBs) are controlled by States; the CentralElectricity Authority, the NationaL Thermal Power Corporation, the National

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Hydro-Electric Power Corporation (NHPC), and the Rural Electrification Cor-poration fEEC) are controlled by the Central Government. SEBs wereinstituted under the Electricity Supply Act of 1948 (the Act) to promote thedevelopment of the power subsector and to regulate private licensees.Although, in principle, SEBs are supposed to be autonomous in managing theirday-to-day operations, in practice they are under the control of StateGovernments in such matters as capital investment, tariffs, borrowings, pay,and personnel policies. As a first step toward national integration, theSEBs have been grouped into five regional systems, each coordinated by anREB. Coordination responsibilities include overhaul and maintenance programsand determination of generation schedules, inter-State power transfers, andconcomitant tariffs. CEA was created in 1950 to develop national powerpolicy and to coordinate the various agencies involved in supplying elec-tricity. It is responsible for the formulation of countrywide investmentplans for approval by the Central Government, the development of integratedsystem operation, the training of personnel, and research and development.It maintains operational, economic, and financial data at both the Centraland State levels, and provides consulting support to SEBs. NTPC and NHPCwere incorporated in 1975 by GOI to construct and operate large power sta-tions and associated transmission facilities. They sell bulk power to theSEBs for distribution. NTPC has had marked success and has grown rapidly.In contrast, NHPC is still struggling to establish a role for itself. TheStates own most hydro sites and are reluctant to relinquish these sources ofcomparatively inexpensive energy to the Central Government. REC was estab-lished in 1969 to coordinate rural electrification and provide financial andtechnical expertise for SEB schemes. At present, REC finances more than halfof total rural electrification investment.

Pricing and Resource Mobilization

1.06 Through the 1983 amendments to the Act, GOI has set a financialobjective for the SEBs to produce an annual return of at least 3% on theirhistorically valued net fixed assets, after meeting operating expenses,taxes, depreciation and interest. The 3% return would represent in terms ofthe Bank's conventional method of calculation, a rate of return on histori-cally valued assets in the range of 102 to 13%. The Bank considers thisobjective to be a reasonable minimum but believes that because of theirinvestment requirements a number of SEBs, needs to achieve internal cashgeneration which implies returns higher than this minimum. Higher returnsmay be possible in some cases through reclassification of consumers.However, substantial improvements are only achievable through tariffincreases. Present tariffs are in most cases inadequate not only in economicbut also in financial terms, and most SEBs are unable to finance a reasonableshare of their investment programs. On average, SEB tariffs are equivalentto only about 50% of long run marginaL cost (LRMC), in contrast NTPC's tariffapproximates LRMC. Industrial tariffs are almost 90% of LRMC but agricul-tural and domestic tariffs, which are considered politically sensitive andhave been consistently subsidized, are only 27% and 36X, respectively.

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State-specific financial programs are needed to provide both an increasedreturn on investment and simpler, efficient and affordable tariff structure.These programs will be addressed through Bank's lending to individual SES's.

Power Subsector Planning

1.07 Because the demand for electricity has increased rapidly, COI atpresent allocates about 20Z of public investment to power development. Toensure that the subsector would be developed in the most economic manner, theBank encouraged GOI to prepare a comprehensive least-cost National Power Plan(NPP), which was completed in September 1982. Although this plan representssubstantial progress, further refinement is needed. To assist GOI in thistask, the Bank has planned a study for FY85 that will review the assumptionsand methodology employed in formulating the least-cost plan. There appearsto be a need for further national integration and greater coordinationbetween power and other sectors, especially coal and gas. Since it will notbe possible to achieve full national integration immediately, the Bank willcontinue to ensure that each Bank-financed project forms a part of anup-to-date regional least-cost development plan. In due course, the sourcesof supply considered in the formulation of each regional least-cost planshould be widened to include the option of importing from neighboringregions. This approach would eventually lead to integrated planning at anational level. A further problem has arisen in the coordination of thelong-term NPP with the national five-year plan and shorter-term budgets.Because of inadequate resources, fewer projects have been included in thefive-year plan than in the NPP and, as a resuLt of underestimation of projectcosts and delays in project implementation, still fewer have been executed.Consequently, the shortage of power has become more and more acute, and overthe next decade, India expects its power deficit to increase severalfold.This deficit will tend to undermine rational planning because emphasis islikely to be placed on rapid expansion of supply rather than on least-costdevelopment. Furthermore, it may prompt overinvestment in captive plant andexcessive use of high-value energy products in the generation of power. Inaddition to supporting GOI's efforts to increase the supply, the Bank willcontinue to stress to GOI the role of pricing in eliminating the deficit andthe importance of integrating planning and pricing.

Management and Operations

1.08 SEBs' organization and management practices have become outmoded assupply has expanded. The quality of service, reLiability, and financialperformance are the principaL areas of concern. In general, SEBs havehigh-quality engineering staff, but lack experienced personnel in the areasof financial planning and control. The relatively poor status and pay ofthese personnel compared with those in the private sector makes it difficultto recruit competent staff. At present, accounts are maintained principallyto track cash receipts and expenditure , and accounting information is seldomused for managerial purposes. GOI has decided that a new and uniform

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accounting system should be installed in all SEBs. After initial delays,preparations are now proceeding and implementation was expected to begin inApril 1985.

1.09 In the area of operations, one of the main concerns has been the poorperformance of thermal plant. Factors that have contributed to this areinadequate maintenance (due to capacity shortages), deficiencies in plantmanufacture, lack of spares, and the poor quality of coal; in general, theseproblems have been recognized by the relevant authorities and correctivesteps are being taken. GOI is currently preparing a rehabilitation programfor thermal plant which may be financed by the Bank. Until this program iscompiled, the Bank will, whenever appropriate, include a thermal rehabilita-tion component under each of the loans made to the SEBs. NTPC, thebeneficiary of the proposed Project, only operates new and well maintainedplants not requiring rehabiLitation.

Bank Group Participation in the Past

1.10 The Bank has made 18 loans for Indian power projects amounting toUS$1,983 million, and 17 IDA credits totaling US$2,409 million. Seventeenprojects financed under the following loans and credits have been completed:ten generating projects, the Beas Project (Credit 98-IN), the first fourtransmission projects (Loan 416-IN, Credits 242-IN, 377-IN and 604-IN), andthe First and Second Rural Electrification Projects (Credits 572-IN and911-IN). The Fourth Transmission Project (Credit 604-IN) was completed in1983, and the Second Rural Electrification Project in 1984. The Singrauli(Credit 685-IN), Korba (Credit 793-IN), and Ramagundam (Credit 874-IN andLoan 1648-IN) Thermal Power Projects are in advanced stages of implementa-tion. The credit for the Second Singrauli Thermal Power Project (Credit1027-IN) and the creditiloan for the first stage of the Farakka Thermal PowerProject (Credit 1053-IN and Loan 1887-IN) were approved in May and June 1980.Korba II (Credit 1172-IN) was approved in July 1981, Ramagundam II (Loan2076-IN) in December 1981, and the Third Rural Electrification Project (Loan2165-IN) in June 1982. The Upper Indravati Hydro Project (Credit 1356-IN andLoan 2278-IN) and the Central Power Transmission Project (Loan 2283-IN) wereapproved in May 1983, and the Bodhghat Hydroelectric Power Project in Kay1984. The Second Farakka Thermal Power Project (Loan 2442-IN) was approvedin June 1984, and the Trombay IV Thermal Power Project (Loan 2452-IN) in Juneof the same year. The Third Rural Electrification Project is about a yearbehind schedule. The first five unizs of the Singrauli Project and the firsttwo units of the Korba project :-?re commissioned on schedule. The Farakkaand Ramagundam projects are proceeding satisfactorily, the first unit atRamagundam having been commissioned four months ahead of schedule. The ThirdTrombay Project (Unit 5) (Loan 1549-IN) was first synchronized in January1984, about a year behind schedule; time was lost mainly because parts forthe boiler were not delivered on time, and because of delays in its construc-tion.

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1.11 A performance audit conducted in 1980 for the Second Power Transmis-sion Project (Credit 242-IN) concluded that the project has succeeded inhelping the nine beneficiary SEBs extend their transmission systems and meettheir growing power requirements. Utilization of generating capacity inthese SEBs has exceeded the appraisal forecast. The upgrading of the SEBs'financial management practices that began under this project will continueunder subsequent projects. The audit highlighted the difficulties of ade-quately supervising this project (because it consisted of many widely scat-tered subprojects), and of effecting institutional improvements in theabsence of a close working relationship between the Bank Group and thebeneficiary SEBs. The Bank has therefore scught more direct involvement withthe SEBs through State-specific projects.

Bank Group Strategy in the Power Subsector

1_12 Over the last ten years the Bank Group has assisted GOI in substan-tially expanding its centrally-owned generation capacity, which is currentlybeing run relatively efficiently. In the past two years, however, theemphasis of Bank Group lending has begun to shift from supporting projectsowned and operated by the Central Government to projects owned and operatedby the SEBs. This gradual shift has come about in support of OOI's desire toaccelerate the deveLopment of India's hydroelectric power resources (most ofwhich are o_ned by the State Governments), and because of the considerableneed to improve the operational and project implementation efficiency and thefinan-ial viability of the State-owned power sector institutions. In paral-leL w--th this shift in Bank Group lending, sector-wide objectives for powersystem operation at both Center and State levels-such as improvingefficiency in the use of existing power generation, transmission and dis-tribution systems, strengthening Central and State level sector institutions,improving country-wide power system planning, and increasing resource mobi-lization within the sector--will continue to be pursued by the Bank Group.Hore specifically, the principal objectives of the Bank Group's assistance inthe subsector are:

(a) the better use of existing facilities-through transmissionprojects improving regional interconnections and throughrehabilitation of plant, particularly of thermal power stationsand distribution networks: these measures will improve theefficiency of energy use and reduce system losses, therebyhelping to minimize system capital and operating costs;

(b) institution building--although the Bank will continue to maintainan interest in Central institutions, its efforts will bebroadened to encompass individual SEBs, where substantialefforts are needed to strengthen management, operations, andfinances;

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(c) improved pLanning--particularly by extending the scope ofplanning from the State through the regional to the nationallevel and through greater integration of planning with othersectors in the economy, both those that consume electricity andthose that supply other forms of energy; and

(d) improved resource mobilization from electricity consumers - theprincipal vehicle for this has been and will continue to befinancial covenants in relation to beneficiaries; however, theBank will also continue to stress the importance of relatingtariffs to the economic costs of supply.

Power Supply and Demand in the Northern Region

1.13 -The proposed Project will benefit the Northern Region where publicsupplw if electricity is entrusted to the Uttar Pradesh State ElectricityBoard (UPSEB), the Punjab State Electricity Board (PSEB), the Haryana StateElectricity Board (HSEn), The Delhi Electricity Supply Undertaking (DESU),the Rajasthan State Electricity Board (RSEB), the Jammu and Kashmir StateElectricity Board (JKSEB), and the Himachal Pradesh State Electricity Board(UPSEB). As of March 31, 1984, the comt,ined installed capacity of these SEBswas about 8,800 NW- Of this about 45% is operated by UPSEB, which is thelargest utility in the Eegion. PSEB, HEvR and RSEB follow with each uperat-ing between 12-15% of the Region's installed capacity. The remaining 6Z isoperated by the other SEBs. The utilities controlled by COI, namely, NTPC,NHPC and the Department of Atomic Energy (DAE), provide the region with anadditional capacity of abouc 2,400 MW. Therefore the total installedcapacity available to the Northern Region is about 11,200 MW, (about 26% ofthe country's total) consisting of 4,771 MW (43Z) of hydro, 5,958 MW (53Z) ofthermal and 44' MW (4Z) of nuclear power. The Region's installed capacity isexpected to rea.ch almost 20,000 MW by 1990, representing an average annualincrease of about 10.4%, significantly higher than the 7.1Z experienced overthe last five years. Most of the increase will be in thermal capacity, whichis expected to reach around 12,700 MV by 1990 and represent 69% of theregion's total installed capacity. NTPC's installed capacity allocated tothe Region is forecast to increase from 1,770 MW, representing 29% of thecapacity available to the Region ir 1984, to about 4,600 MW, accounting for35% of the Region's capacity in 1990. NTPC's new facilities would consist ofthe Capital Region station (800 NW) to be constructed at Muradnagar, nearDelhi, the ongoing extension at Singrauli (1,000 MW), and the new Rihandpower station (1,000 MW).

1.14 The electricity generation and consumption for the States of theregion during the period FY'79-FY'84 is shown in Annex 1.3. Elect.icityconsumption grew at an average of 7.1% per year during the period, reaching28,200 GWh in FY'84 and peak demat.d was about 8,700 MW. Industry is thelargest consum-r of electricity in the region, but its share of total con-sumption, which is about 52%, is below the national average of 56X. On the

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other hand, agriculture's share, which is the second largest, is sig-nificantly higher than in the country as a whole, 30X compared to 19X. TheRegion, therefore, is subject to the disadvantages of high agriculturaldemand, characterized by sustained consumption during the daily peak period,low load factor, and high system losses in distribution. According to thedemand forecast prepared by CEA for the period FY'85-FY'93 (Annex 1.4), theunconstrained peak demand in the region will reach 20,024 MW in FY'93 at anaverage annual growth rate of about 10.8Z. Energy requirements are expectedto increase to 102,432 GWh by FY'93 at an average annual growth rate of about10.2% during the same period. However, these forecast demands are unlikelyto be met owing to shortage of capacity and operational problems. Deficitswith respect to both peak demand and energy will therefore continue.

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II. THE BENEFICIARY - NATIONAL THERKMAL POWER CORPORATION LIMITED

2.01 NTPC, the beneficiary of the proposed loan, was established in 1975as a pubLicly owned utility, under the general supervision of the Ministry ofEnergy, 1/ with the responsibility for designing, constructing, and operat-ing large thermal power stations and transmission systems, and for the saleof power generated to the SEBs. NTPC's initially authorized share capital ofRs 1,250 million (US$104.2 million) has increased steadily and has reachedRs 25,000 million (US$2,083 million) by FY'1983. On March 31, 1984, thepaid-up capital of the Corporation was Rs 15,668 million (US$1,306 million)_NTPC has broad powers to carry out its daily operations. Decisions oninvestment plans and financing require Government approval before implementa-tion. NTPC is also subject to periodic examination by the Committee onPublic Undertakings, a body established by GOI to monitor the performance ofpublic sector enterprises.

Existing Facilities and Development Program

2.02 NTPC commenced generating electricity in 1982 and, by the end ofFY'84, had in operation nine units of 200 MW each: five at Singrauli, threeat Korba and one at Ramagundam. In addition it operates the 720 MW Badarpurstation near Delhi on a management-fee basis. Transition from the construc-tion to the operational phase is being carried out successfully. Efficiencyhas also been high and unit availability and load factor maintained above theaverage regional and national levels (Annex 2.1). The Corporation's powerplants commnissioning program for the 24-year period FY'77-FY'2000 is shown inAnnex 2.2. The program includes 31 generation and transmission projects, ofwhich 16 have been approved and the remaining 15 projects are currently beingprocessed for final approval by GOI. NTPC's generating capacity is projectedto increase from 1,800 MW in FY'84 to 10,400 MW by FY'91, 21,580 MW by FY'96and 27,080 MW by FY'2000. Concurrently, the transmission system would beexpanded to include more than 9,000 km of EHV lines and 37 EHV substationsthroughout the country, thus initiating what would eventually evolve into anational grid for the transmission and exchange of power between NTPC and theSEBs. NTPC's investment program and implementa0on schedule are realistic interms of NTPC's technical capability.

Organization and Management

2.03 Considering the rapid increase in NTPC's operational and constructionactivities, a study to develop a decentralized organizational structure wastaken up in 1981, with the assistance of experts from reputed power utilities

1/ Under the latest reorganization of Government responsibilities, NTPC hasbeen assumed by the newLy-formed Ministry of Irrigation and Power.

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in the UK and the USA. Based on the result of the study, NTPC has adopted aregional organizational structure with each Region under the charge of anex2cutive director responsible for the design, construction and operation ofgeneration and transmission facilities within the Region. The decentraliza-tion of NTPC's operations on a regional basis, was approved by NTPC's Boardon August 16, 1982, and impLementation is almost completed. Regional head-quarters staff, headed by Executive Regional Directors, have been establishedfor:

(a) the Northern Region, comprising the power stations at Singrauli,Rihand, Badarpur and Muradnagar;

(b) the Western Region, comprising the power stations at Korba andVindhyachal;

(c) the Southern Region consisting of the Ramagundam power station and agrid which will have over 3,000 km of 400-kV lines; and

(d) the Eastern Region consisting of Farakka and Kahalgaon power stationand associated transmission system.

In addition to these regional headquarters, and with the commencement ofconstruction activity for the transmission system associated with theproposed Project in the Northern Region and the transmission systemassociated with the V.ndhyachal Project in the Western Region, it was decidedto create a division responsibLe for the transmission system in these tworegions. It will ensure adequate attention to the implementation by 1990 ofmore than 7,500 kms of transmission lines, 17 substations and the introduc-tion ir. the country of HVDC facilities. The division was created in May 1984and is headed by an Executive Director based in Delhi.

2.04 This restructuring has led to decentralization of the implementationresponsibility. The role of the Corporate organization is progressivelybecoming one of policy-making and that of providing functional guidance tothe Regions' project and other operating divisions. The principal corporatefunctions are finance, personnel and administration, planning and monitoring,technical, procurement and commercial. The finance, personnel and technicalgroups are headed by Directors who are members of NTPC's Board of Directors.The commercial group, including procurement, is responsible to the ExecutiveDirector (Commercial). The planning and monitoring group reports to theChairman and Managing Director. The present corporate organizational struc-ture is shown in Annex 2.3.

Recruitment and Training

2.05 Recruitment is progressing satisfactorily and is expected to meetNTPC's expanding operational needs. By the end of FY'84, NTPC had about13,000 employees. This number is expected to reach about 31,555 by the end

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of FY'90. In the first few years of activity, NTPC has given emphasis torecruiting and training executives, engineers and supervisors who account atpresent for nearly 40Z of its staff. However, with the development of itsoperations, this emphasis has been gradually shifting toward the recruitmentof more skilled laborers, who will account for about 70% of its staff byFY'90. Moreover, NTPC has given high priority to the training of its stafffor which detailed programs have been developed. The approach adopted byNTPC to effectively meet its large manpower requirement involvespre-employment and post-employment training. Pre-employment training isprovided to personnel who enter the organization as trainees at varying entryleveLs and undergo an extensive training program before assuming their per-manent assignment. The pre-employment training for professional engineersand executive trainees is tailor-made to meet the requirements in engineer-ing, personnel and finance. The one-to-two year program provides a com-prehensive exposure to the conceptual and practical aspects of future assign-ments. For graduate engineers this includes visits to manufacturer's worksand training on simulators; a 200 MW simulator has been installed at Korbapower station and a 500 MW is being procured. There are also trainingschemes for non-graduate engineers (i.e. diploma holders). These one-yearschemes have a strong practical bias as these trainees are earmarked toassume responsibilities in the operations and maintenance functions. Forskilled Laborers, training is highly job-oriented and aims to develop thenecessary skills required for working as operators and artisans for powerplants, load dispatch and transmission facilities. The post-employmenttraining schemes, provides training to personnel who are already employed bythe Corporation or who have joined the Corporation with previous experience,but need some exposure to the expertise required in their new assignments.Training centers have been established at NTPC's plant locations. Thesecenters with workshops, training materials, and hostel facilities aredesigned to train young graduates, diploma holders and operating staff. NTPCalso provides adequate training in management and other areas in the powersector in two specialized centers, the Centre for Education in Power Manage-ment in Delhi and the Central Institute of Training at Badarpur. In addi-tion, specific programs are organized in collaboration with power organiza-tions of international repute, (e.g. the Central Electricity Generating Boardof the U.K.).

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III. THE PROJECT

Project Setting

3.01 GOI's strategy for meeting the future demand for power has involvedan accelerated orogram for the development of coal-fired thermal pLants,particularly those which can be installed near or at open pit mines. One ofthe largest coalfields is located in the Singrauli region, about 500 km westof Calcutta at the border between Madhya Pradesh and Uttar Pradesh (Hap IBRD18595). The development of this field, with estimated coal resources ofaround 10 billion tons, has recently been financed by the Bank under theDudhichua Coal Project (Loan 2393-IN). The field is expected to produceabout 40 million tons of thermal coal per year in the mia-1990s. in order toutilize this resource, NTPC's development program calls for the installationin the region of three super thermal power stations with an ultimate totalinstalled capacity of about 7,300 MW, divided among Singrauli (2,000 MW),Rihand (3,000 MW) and Vindhyachal (2,300 MW).l/ Presently, five units of 200MW each are already in operation at Singrauli and the construction of thefirst 500 MW units at Singrauli and Rihand has been initiated. In associa-tion with the development of this generating capacity, CEA has outlined, withthe assistance of Hydro Quebec International (HQI), Canada, a least-costprogram for the development of the transmission system necessary to ensurethe efficient and economic evacuation of power from the Singrauli-Rihandstations to the northern grid system. The transmission program calls for theimplementation of a combined AC/DC system, comprising a + 500-kV HVDC line tobe constructed in combination with extensions to the existing 400-kV ACsystem to transmit the power to the SEBs in the Northern Region. The com-bined AC/DC system was selected to allow for the transmission of large blocksof energy over long distance through the HVDC link, and its distribution tothe SEBs through the 400/220-kV AC system. This combination would reducelosses and ensure the efficient transmission of power from the power plantsto the main load centers in the northern region.

Project Objectives

3.02 The objectives of the proposed Project are to continue the institu-tion building efforts initiated under the Bank Group's earlier lending opera-tions by strengthening the capabilities of CEA and NTPC in formulating andimplementing an investment program aimed at meeting the future demand forelectricity at least cost. The main objective is to assist NTPC in meeting

1/ The Bank is financing the development of Singrauli station (Cr. 685-INand Cr. 1027-IN) in conjunction with the Federal Republic of Germany,while UK and USSR are financing, respectively, the first stage of Rihandand Vindhyachal stations.

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the electricity demand in the Northern Region by providing transmissionlinkage between the coal-based thermal power plants at Singrauli and Rihand,and the main load centers in the Northern Region and ensuring the evacuationof power from the plants at least cost to the economy. It would also serveas a vehicle for the introduction of new technology, HVDC links, needed toensure the continued implementation of NTPC ongoing program for the expansionand reinforcement of the EHV transmission grid. Moreover, the introductionof the HVDC system would allow for the distribution of specified blocks ofelectricity from the central stations to individual States and betweenregions which are often operating at different frequency margins. In addi-tion the proposed Project would, through the associated transmission study(para 3.07), contribute significantly to the rationalization and integrationof an EHV grid and to the long-term objective of ensuring economic intercon-nections within and among the different regions of the country. .herefore,the proposed Project would complement the progress made under the Pankfinanced the Central Power Transmission Project (Loan 2283-IN) and furtherGOI's and the Bank's joint strategy for the development of a national, tech-nically reliable and economically justified generation and transmissionsystem.

Project Description

3.03 The proposed Project, the physical aspects of which are described indetail in Annex 3.1, would comprise:

(a) a + 500-kV HVDC bi-polar transmission line of about 910 km,connectirg Rihand and Delhi, and the associated AC/DC convertingstations for an initial capacity of 1,000 MW and related auxiliaryequipment at Rihand and Delhi;

(b) about 1,450 km of 400-kV single and double-circuit AC lines,connecting the Rihand and Singrauli stations with Kanpur, Delhi,Panipat and Jaipur, and the construction or expansion of relatedsubstations with associated auxiliaries; and

kc) technical assistance for the engineering, testing andcommissioning of the Project.

Project Cost

3.04 The estimated cost of the proposed Project, including contingenciesbut excluding duties and taxes, is Rs 6,950.3 million (US$579.2 million).Taxes and duties would amount to about Rs 1,040.0 million (US$86.7 million).Interest during construction adds Rs. 324.7 million (US$27.1 million) to thefinancing required. The direct and indirect foreign currency costs areestimated at about Rs 3,380.8 million (US$281.8 million), which representabout 412 of the total financing required. The estimated costs of theProject are set out in Annex 3.2 and summarized in Table 3.1 below.

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Table 3.1

Project Estimated Cost

Local Foreign Total Local Foreign Total------ Rs million-- ----- US$ million----

400-kV AC lines 1,091.2 407.8 1,499.0 90.9 34.0 124.9400-kV AC substations 981.8 140.0 1,121.8 81.8 11.7 93.5HVDC line 661.9 302.1 964.0 55.2 25.1 80.3HVDC terminals 785.2 1,464.8 2,250.0 65.4 122.1 187.5Consultancy andTechnical Assistance - 55.0 55.0 - 4.6 4.6

Engineering and 390.1 - 390.1 32.5 - 32.5Administration ------ ------- -------

Total Base Cost 3,910.2 2,369.7 6,279.9 325.8 197.5 523.3

Physical Contingencies 202.6 115.8 318.4 16.9 9.6 26.5Price Contingencies 72i.6 670.4 1,392.0 60.2 55.9 116.1Total Project Cost 4,834.4 3,155.9 7,990.3 402.9 263.0 665.9

Interest during ConstructionBank - 224.9 224.9 - 18.8 18.8Other 99.8 - 99.8 8.3 - 8.3

.Front-End Fee - 0.0 0.0 - 0.0 0.0Total Financing Required 4,934.2 3,380.8 8,315.0 411.2 281.8 693.0

The cost estimates for the main items of equipment and materials related tothe 400-kV AC facilities are based on the most recent quotations receivedfor similar projects with prices updated to December 1984 levels. As for theHVDC facilities, estimates are based on indicative proposals made by some ofthe firms with extensive experience in HVDC installation which comparedfavorably with recently submitted prices for similar works in othercountries. The estimated cost of consulting services covering (i) man-monthrate, (ii) reimbursable items, and (iii) subsistence and other allowances inIndia are based on experience with other projects under preparation andexecution in India. The cost of the technical assistance for overseas train-ing of Indian engineers was determined on the basis of standard pricesprovided by internationally reputable firms. Physical contingencies of about10% on civil works and 5% on equipment were assumed on the basis ofexperience with similar projects which are considered adequate. Price con-tingencies for local costs for equipment and erection were assumed at 8.5%for FY'86 to FY'91, and 6% thereafter. Price contingencies for foreign costswere assumed at 9% annually from FY'86 to FY'88, 7.5% for FY'89 and 6Z there-after. Interest during construction takes into account the progressivecomnissioning of the 400-kV AC lines.

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Project Financing

3.05 The proposed financing plan assumes a Bank loan of US$250 million,representing about 43Z of the totaL project cost net of taxes and duties.The terms and condition of Bank loan and onlending arrangements between GOIand NTPC are detailed in paragraph 4.16. GOI and kTPC are also consideringadditional sources of financing in the form of co-mercial/supplier's creditsor bilateral assistance, particularly for the foreign cost of the AC-DCterminals. The balance of the financing required would be provided by GOI,in the form of loan and share capital, and NTPC's own resources. The follow-ing table summarizes the proposed financing plan:

Table 3.2

Project Financing Plan

Local Foreign Total=-- (US$ million) --

IBRD Loan 122.0 128.0 250.0Cofinancing - 135.0 135.0

GOI and NTPC 289.2 18.8 308.0

411.2 281.8 693.0

The plan assumes that cofinancing of about US$135 million would be securedfor equipment for the HVDC terminals. If cofinancing in excess of $135million is forthcoming, the proposed Bank loan would accordingly be reallo-cated to cover an increased share of the local cost.

Engineering and Studies

3.06 Following the project feasibility study prepared by CEA (para 3.01),detailed system and engineering studies were undertaken by NTPC, in closeassociation with their consultant, HQI, financed by CIDA of Canada. Thesestudies, which were completed in September 1984, covered the simulation ofenergy flow and network design. Moreover, the consulting services by HQIfocussed on maximizing the transfer of these new techniques to CEA and NTPCstaff by de-?eloping their expertise in power systems analysis and settingspecifications for the performance of equipment. NTPC is now preparing thedetailed specifications of the HVDC components of the project and will retainconsultants to assist in supervising the engineering activities during thesupply of equipment, construction, testing, and commissioning of that part ofthe project. At the request of NTPC, the foreign cost of these technical

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services, covering about 165 man-months of service, would be financed underthe proposed Project. As for the engineering of the 400-kV AC transmissiondesign and construction details of this system have already been standardizedfor all India as a result of the experience gained by the SEBs and NTPC inimpLementing similar projects in the past. This has provided the basis fordetailed design of the 400-kV lines and substations included in the Project.

3.07 The increase in the size of the generating units and plants, theexpansion of the 400-kV grid and the introduction of HVDC facilities neededto keep up with the growth of the power subsector, have made it necessary toextend the country's EHV power transmission system. Therefore in conjunctionwith the proposed Project, CEA, will carry out a series of power transmissionstudies, to be financed by GOI from its own resources. These studies will beundertaken for each of the Regions and will form the basis for the formula-tion of a least-cost, long-term (15-to 20-year) national power transmissionplan for the development of the high-voltage power transmission system; theplan will include the configuration of a primary grid, interregionallinkages, and system control requirements. Further s:udies will beinstituted by GOI as necessary to address the responsibilities, policies,and procedures pertaining to the institutional, commercial, operational andtraining aspects of the system at the State, regional, and national levels.C0I agreed during negotiations that the scope and terms of reference for thestudies will be prepared by CEA in collaboration with the Bank by December31, 1985, and consultants will be appointed or retained as necessary toassist and train CEA staff in their execution. The studies and the nationalpower transmission plan will be completed, and the results reviewed with theBank, by June 30, 1987.

Construction and Procurement

3.08 NTPC is currently successfully implementing, through contractors, the400-kV lines and substations in conjunction with the construction of itsthermal power projects. The same approach would be followed for the con-struction of the 400-kV AC facilities included under the proposed Project.The equipment (conductors, insulators, hardware, metering, telecommunicationand substation equipment), and civil works estimated to cost about US$150million, would be procured through international competitive bidding. Thesupply of towers and lines erection estimated at US$60 million, would becarried out through separate contracts under local competitive bidding. TheHVDC line material, as well as the construction of the line, estimated atabout US$91 million, would be procured through international competitivebidd ng. The main equipment of the HVDC terminals would be purchased throughnegotiated contract or international competitive bidding depending on theresults of cofinancing arrangements (para 3.05). This contract, which alsoincludes erection works, is estimated to amount to around US$176 million. Inaddition, the contract would include adequate provision for training NTPC'sstaff since the HVDC facilities would be introduced in the Indian powersector. Accessories and miscellaneous equipment related to HVDC terminals,

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estimated at about US$17 million, would be procured through internationalcompetitive bidding. Table 3.3 below summarizes the proposed status ofprocurement arrangements.

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Table 3.3

PROCUREMENT ARRANGEMENTS(US$ million) l/

Project Element Procurement Method 2/

ICB LCB Other NA Total Cost

I. 400-kV AC Lines

Preliminary Works - - - 8.7 8.7Towers and Lines Erection - 58.9 - - 58.9Conductors and Earthwire 49.2 - - - 49.2

(47.8) - - - (47.8)Insulators and Hardware 9.4 - - - 9.4

(8.7) - - - (8.7)Accessories and 2.2 - - - 2.2Miscellaneous (2.0) - - _ (2.0)

Sub-total 60.8 58.9 - 8.7 128.4(58.5) (58.5)

II. 400-kY AC Sub-Stations

Land and Colony - - - 7.2 7.2Structures and C .vil Worss 5.5 - - - 5.5

(4.5) - - - (4.5)Equipment 84.2 - - - 84.2

(82.0) - - - (82.0)

Sub-total 89.7 - - 7.2 96.9(86.5) - - - (86.5)

11 All figures are net of duties and taxes, figures in parentheses indicatethe amount to be financed by the Bank.

2/ ICB: International Competetive BiddingLCB: Local Competitive BiddingOther: Direct negotiationNA: Not subjeet to commercial procurement (e.g., land acquisition, owner

expense..F

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III. Rihand-Delhi HVDC Line

Preliminary Works - - - 6.1 6.1Towers and Line Erection 36.1 - - - 36.1

(34.4) - - - (34.4)Conductors and Earthwire 38.5 - - - 38.5

(36.2) - - - (36.2)Insulators and Hardware 11.9 11.9

(9.8) - - - (9.8)Accessories 4.3 - - - 4.3

(3.8) - - - (3.8)Sub-total 90.8 - - 6.1 96.9

(84.2) (84.8)

IV. HVDC Terminal

Buildings and Civil Works - 25.6 - - 25.6Equipment 3/ - - 176.3 - 176.3Accessories and 17.1 - - - 17.1Miscellaneous (15.8) - - - (15.8)

Sub-total 17.1 25.6 176.3 - 219.0(15.8) - - - (15.8)

V. Consulting Services and - - 5.0 - 5.0Technical Assistance - - (5.0) - (5.0)

VI. Engineering and - - - 32.5 32.5Administration

Total 258.4 84.5 181.3 54.5 578.7(245.0) (5.0) (250.0)

3.09 Procurement of equipment, materials, civil and erection works amount-ing to about US$260 million, would be on the basis of international competi-tive bidding in accordance with the Bank's guidelines. Documents forindividual contracts above US$ 3,500,000 equivalent would be subject to priorreview by the Bank. Local contractors and manufacturers would be expected tobid for almost all categories of equipment and materials of the AC facilities

3/ Mode of procurement is yet to be finaLized (see para. 3.08) and thecontract includes around US$135 million in foreign cost.

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and HVDC lines. Local manufacturers competing under international competi-tive bidding will have a 15Z preference or the applicable duty, whichever isless, for supply of goods. Consultants for project supervision would beselected in accordance with Bank guidelines and employed under terms andconditions satisfactory to the Bank. The planned schedule for procurement cfthe equipment and material to be financed by the proposed Bank loan is:(i) start of bid invitation: October 30, 1984; (ii) first bid opening:January 21, 1985; (iii) first award decision: Hay 15, 1985; and (iv) firstcontract signature: June 15, 1985. Accordingly, NTPC has requested the Bankto authorize advance procurement and retroactive financing of up to US$20million to cover expenditures under contracts awarded after April 15, 1985and prior to Loan signing, and in accordance with Bank guidelines forprocurement, in respect to the supply of equipment for the AC facilities andHVDC line, and associated consultancy services.

Project Implementation and Completion

3.10 Taking into account the advanced stage of project preparation andexpected timing of procurement, the project completion is expected by the endof 1988. This completion date is in accordance with the time scheduleforeseen for the completion of the Rihand power station currently underconstruction. The implementation schedule for the proposed Project is shownin Annex 3.3.

Disbursement

3.11 Disbursement from the proposed loan would be against 100% of theex-factory cost of equipment and materials procured in India, 100% of theforeign cost of equipment and materials procured abroad and 90Z of the civiland erection works, these being subject to international competitive bidding.Disbursement from the proposed loan would also be made against 100% of thecost of consultancy for project supervision. The estimated schedule ofdisbursements as provided in Annex 3.4, was determined by NTPC and relate tothe Project implementation schedule (Annex 3.3). The disbursement pe-ofilefor the Project is much faster than the Bank's standard profile for a powerproject in India, 4.5 years as opposed to 10, but this is reasonable giventhe weight of generation projects in the latter. The profile is also fasterthan the Bank-wide standard profile for transmission and distributionprojects, which is 7 years. However, the Bank is satisfied that the proposedprofile is reasonable and reflects NTPC's experience in transmission lineconstruction and the advanced stage of project preparation. Negotiationsfor equipment for the HVDC terminals are already well advanced and supplyof this equipment is unlikely to cause delays affecting Bank financed ele-ments of the Project.

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Ecology

3.12 No ecological problems are expected. Conductor sizes and spacingAill be designed to keep energy losses and radio interference within accept-able limits. Furthermore, with the introduction of DC line and higher volt-age (500-kV), the area of the transmission corridor, and therefore the areaof right of way, is significantly reduced as compared with a system ofsimilar capacity using AC or lower voltage.

Project Risks

3.13 No risks, other than those normally associated with this type ofpro,auz qre foreseen. In view of NTPC's previous experience with transmis-sion construction, it is expected that the risk of slippage would be minimal.in particular, for the DC facilities, discussions with equipment suppliershave indicated that HVDC terminals can be comissioned in 36 months after theorders are placed on a turnkey basis. The DC line require comparativelysimple towers and need only two-phase conductors to be strung. Any possibleslippage wouLd have a negative impact only if the construction of Rihandpower station is progressing faster than the Project implementation. NTPC,being responsible for both projects, will ensure appropriate coordination ofthe different activities during implementation of the projects in order toachieve the target dates for compLetion. Risk of damage due to fire, explo-sion, etc. would be covered by the respective contractors during the con-struction phase and by GOI, through its self-insurance policy, after commis-sioning.

Project Monitoring

3.14 NTPC wilL submit quarterly reports covering physical progress, con-sultants' work, costs, disbursements and administrative aspects of theProject. In addition, there will be annual reports on the financial positionand management situation of the Corporatioc. Progress on the long-termtransmission study will be reported regularly by CEA and reviewed againstthe agreed program.

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IV. FINANCE

Accounting Organization and Systems

4.01 NTPC, assisted by A.F. Ferguson Co. (India), designed in 1979 andhas since implemented well conceived accounting and internal control systems.These cover financial and cost accounting, contract accounting and manage-ment, inventory control, billing, fixed assets accounting, and payroll.Moreover the corporation has established decentralized autonomous accountingorganizations at the site of each plant in operation. A.F. Ferguson Co.,since 1979, has been engaged in the monitoring of the implementation of thesystems at plant sites and assisting in the training of the accounting staffon an on-going basis. Management information and budgetary control systemswere intzoduced in 1979. These are well designed and review of their resultsprove them to be effective in providing the inputs needed for planning andmonitoring NTPC's project construction activities and commercial operations.An internal audit unit has been established with adequate systems andqualified staff. Accounting practices, procedures and staffing are satisfac-tory. Training of accounting staff is well planned and organized, andrecruitment of qualified staff is progressing at a rate sufficient to meetthe forecast manpower requirements of the financial complex of the organiza-tion.

Past Performance and Present Financial Position

4.02 NTPC is currently in the ninth year of an investment programinitiated in 1977 (Annex 4.1) which originally envisaged the construction offour large thermal stations at Singrauli, Korba, Ramagundum and Farakka, toprovide a total installed capacity of 7,300 MW and about 6,000 km ofassociated transmission lines. At the time, the cost of this program wasestimated at about Rs 41,000 million (US$3,417 million). Since then, theinvestment program has been increased to about Rs 423,000 million (US$35,243million) to accomodate the increased demand for power. By the end of FY'84,NTPC had an installed generating capacity of 1,800 KW (Annex 2.2). NTPCstarted its comercial operations in FY'83, consequently there is no historyof financial operating performance prior to that year. Operations duringFY'83 were minimal due to start-up and testing procedures required for thestabilization of the newly comissioned generating units. Despite theseconstraints, net earnings of Rs 46 million for FY'83 compared favorably withRs 45 million previously forecast for the year. The financial performancefor FY'84 is provided in Annex 4.3. Sales revenue for that year was Rs 1,398million, representing an increase of Rs 96 million (7%) over the projectionsprepared in 1983. The higher revenue was due to the increased energy sales,actual of 3,845 CWh compared to 3,675 GWh originally forecast, and highertariffs, 36.45 compared to 35.45 paise per kWh initially projected in 1983.Total operating expenses of Rs 723 million were the sAme as previously

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projected due to Lower operations and maintenance costs and lower deprecia-tion costs which offset completely the increase in fuel costs of Rs 164miLlion over the 1983 forecast. The higher fuel bill was attributable tothree factors: (a) the generation of more power than was forecast whichrequired more primary energy than was planned; (b) the unanticipated increasein the price of domestic coal; and, (c) the increased reliance on oil tocompensate for shortages of coal attributable to supply constraints duringthe monsoon period. NTPC is taking measures to build up a sufficientstock-pile reserve of coal at each station, to ensure a constant supply foroperations and thereby reduce the consumption of oil. Operations and main-tenance costs and depreciation were lower than projected as a consequence ofslippage in the initiation of commercial operations of the newly commissionedpower stations. NTPC capitalizes costs, other thani fuel, during the periodbetween commissioning and the start of comnercial operations rather thancharging these costs to operations. Depreciation is charged to operationsonly for assets that are under commercial operations. As a result of theabove variances in sales revenue and operating expenses, operating income ofRs 675 million for FY'84 exceeded the previous forecast by Rs 96 million(17Z), yielding a financial rate of return on unrevalued assets of 11.3%compared to 7.1% previously forecast. The rate of return compares favorablywith the 7% minimum rate of return on unrevalued assets required for FY'85-90under Loan 2442-IN. The equivalent financial rate of return on revaluedassets, calculated on a pro-forma basis, is approximately 8.8Z for FY'84which is satisfactory. Net profits of Rs 449 million exceeded the previousprojections by Rs 253 million attributable to a decrease in interest expenseon GOI loans, deferred expenses written-off (not previously planned), and theabove favorable variance in operating income. With exception of the increasein fuel costs NTPC's performance in FYs'83 and '84 was satisfactory.

4.03 Cash generation measured as a percentage of average annual capitalinvestment requirements, was 5Z for FY'83 and 3Z for FY'84. Details arepresented in Annex 4.2. For FY'84, the low contribution to investment wasattributable to the fact that generation during the year amounted to only 43%of potential output mainly due to the time required to stabilize, and to thefact that 1,000 MW of the total 1,800 MW at year-end were commissioned and inoperation progressively from the sixth to twelfth month of the year, only.Assets in operation and producing income at FY'84 year-end represented only40% of total capital expenditure to date. The lower ratio of cash generationin the earlier years of NTPC's commercial operations is further commentedupon in para 4.06.

4.04 NTPC's collection of accounts receivable has been slower than isconsidered accepcable. As of July 31, 1984, outstanding receivables on theaverage represented about 3.9 months of NTPC's total sales. According to theterms of the bulk supply contracts NTPC's customers are required to remitpayment for power purchases within 30 days of receiving bills from NTPC. Thecontracts also require that the NTPC customers open revolving bank letters of

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credit in favor of NTPC for an amount equivalent to one month's power pur-chases. At present, five of the nine customers concerned in the Northern andWestern Regions have complied with this requirement; none of NTPC's customersin the Southern and Eastern Regions has yet done so as bulk supply contractsfor these were concluded only recently, only a limited amount of power isavailable from NTPC's Ramagundam plant, and NTPC's Farakka plant is yet to becommissioned. NTPC has encountered resistance from some of its customersconcerning the opening of letters of credit, because at this stage ofdevelopment of the transmission network, power frequently has to be routedthrough one or more States before it reaches its ultimate destination, and asa result NTPC is not able to ensure that they receive their allocated sharesof power. In view of this situation, it was agreed during negotiations thatthe required letters of credit would be opened for each NTPC customer within30 days of their receiving their allocated shares of power. In the meantime,NTPC will continue to make every effort to obtain letters of credit fromthose customers which have not yet opened them (para 6.02(a)). With regardto the arrears in NTPC's accounts receivable, these have arisen primarily inconnection with NTPC's sales of electricity prior to the signing of the bulksupply agreements with its customers, during which time electricity was beingsoLd at interim rates which were subject to subsequent adjustment. NTPCagreed during negotiations to provide the Bank with repayment timetables, byDecember 31, 1985, drawn up in conjunction with each of the customers inarrears in its payments, with the objective of liquidating the outstandingarrears within two years (para 6.02(c)). It was also agreed during nego-tiations that NTPC will ensure that with respect to its sales of electricitysince the signing of the bulk supply agreements, its total monthly accountsreceivable will be maintained, from March 31, 1986, at a level equivalent tonot more than two months' sales (para 6.02(b)).

4.05 NTPC's fixed assets as of March 31, 1984 amounted to Rs 22,794 mil-lion which was comprised of work-in-progress of Rs 13,767 million and plantin operation of Rs 9,197 million (Annex 4.4). The plant in operation iscomprised of commissioned generating units (1,800 MW) and associated trans-mission facilities. Current liabilities of Rs 2,142 million are high due toreceipt of GOI project financing subsequent to the FY'84 year-end, for itemspurchased prior to the year-end. Receipt of such financing prior to year-endwould have been applied to payables outstanding for construction materials,resulting in a reduction of current liabilities at March 31, 1984. The debtto equity ratio of 26/174 is satisfactory. With the exception of the improve-ment required in accounts receivable collections, NTPC's financial operationsfor FY'84 and its financial position at year-end were satisfactory.

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Future Investment I/

4.06 NTPC's capital expenditure for the development of its system for theperiod FY'77-'96 amounts to Rs 422,911 million (US$35,243 million) (Annex4.1). NTPC's total external financing requirements would be met by GOIequity contribution through the issue of share capital of Rs 173,026 million,and by long-term loans of Rs 179,829 million. Foreign financing through Bankloans, bilateral loans and aid, and co-financing is expected to contribute,as in the past, at approximately 30Z of financing requirements. NTPC'sinternal cash generation is projected to contribute about 30X to the totalcapital investment requirements, increasing from about 3% in FY'84 (para4.03) to about 36Z in FY'93. The lower ratio of cash generation to capitalinvestment during this earlier period of the FY'77-'96 investment program isdue to the high level of capital expenditure relative to the assets whichwere in operation and generating cash income. This was foreseen for theearlier years of NTPC's commercial operations, and for this reason the finan-cial rate of return on net assets in operation was selected, in preference tocash generation as contribution to investment, to monitor NTPC's financialperformance. In FYs'94, '95 and '96 internal cash generation is projected tobe about 52Z, 66Z and 95Z for each year respectively. Future upward revi-sions of the investment program, which are expected with the passage of time,would bring the level of cash generation for this period down to about the40% level usually associated with an 8% or 9X rate of return cn revaluedassets, with the rate of return also remaiaing at a satisfactory level (para4.08). The Bank intends to monitor the adequacy of NTPC's cash generation,as a check to determine the adequacy of the rate of return on net unrevaluedassets. The benchmark ratios the Bank would use for this purpose, would bea minimum cash generation contribution to investment of 10% in FY'88, 13Zin FY'90, 25% in FY'92 and 40Z in FY'94 and each year thereafter. Dividendson equity share capital are not anticipated in the forecasts on the assump-tion that surplus funds would be applied to the investment program. NTPC'sinvestment program and financing plan for FYs'77-96 are satisfactory.Details of the forecast financing plan are set out in Annex 4.2.

Future Performance and Financial Position 1/

4.07 NTPC's consolidated income statement covers projected financialperformance for FY'85 to FY'96 (Annex 4.3). This period was selected forthe financial projections as FY'96 would be the first year in which all GOIapproved generation projects would be fully stabilized and operating at fullcapacity. The assumptions used for the forecasts are presented in Annex 4.8.Power generation is projected to increase from 1,109 GWh in FY'83, to 47,606GWh in FY'91, and to 106,161 GWh in FY'96. The average tariff is forecast to

1/ All figures are expressed in current prices. Refer to Annex 4.8 para2(c), for the escalation factors used.

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increase from 32.30 paise/kWh to 67.95 paise/kWh and to 93.22 paise/kWh forthe same years respectively, on the basis of applying the formwla factors ofthe regional bulk supply contracts. The increase in NTPC's average tariffwould represent an annual average rate of growth of about 8.5% between FY'83and FY'96, which would slightly exceed the expected rate of inflation andthus result in a small increase in the tariff in reaL terms. This wouldmaintain the average tariff at about parity with the LRMC (para 4.11).Revenue from sales of electricity is projected to increase from Rs 1,398million in FY'84, to Rs 29,602 million in FY'91, and to Rs 91,038 million inFY'96.

4.08 Operating expenses, comprised of fuel costs, operations and main-tenance expenses and depreciation, remain relatively constant as reflected byoperating costs as a percentage of sales revenue which varies, for the periodFY'84-FY'96, from about 50% for FY'84, 56% for FY'90, and 54Z for FY'96.Operating income is projected to increase from Rs 675 million in FY'84, to Rs13,448 million in FY'91, and to Rs 42,236 million in FY'96. This would yielda financial rate of return on unrevalued net assets in operation of about11.3% in FY'84 and FY'91, and 14.7Z in FY'96. Between FY'84 and FY'91, thefinancial rates of return vary between 9.4% and 1'.5X. The variation duringthis period is attributable to the fact that common facilities, serving andsupporting the total complement of generating units at each station, arecompleted and transferred to assets in operation prior to the completion andcommissioning of most of the power units which produce saLes and consequentlyincome. The value of these assets cannot be separated and therefore tends todepress the rate of return by overstating the value of net assets in opera-tion. Both the financial rate of return and internal cash generation (Annex4.2) would increase together to reach acceptable levels of about 12% and 52%,respectively, by FY'94. Under Loan 2442-IN, GOI and NTPC agreed to achieveannual rates of return on unrevalued net assets in operation of not less than7% in FY'85 through FY'90, 9.5% in FY'91 through FY'95, and thereafter,annual rates of return at levels satisfactory to ensure the financialviability of NTPC. It was agreed that the 14.7% rate of return, reflected inthe financial projections for FY'96, would satisfactorily ensure such finan-cial viability. NTPC's current projections comply with these covenantedrates of return. The covenant has been repeated for the proposed Project,and GOI and NTPC agreed during negotiations that NTPC would achieve annualrates of return on unrevalued net assets in operation as described above forLoan 2442-IN (para 6.02(d)). Current projections reflect a 14.7% rate ofreturn in FY'96 which is still considered satisfactory to ensure the finan-cial viability of NTPC. A rate of return of 7% on net unrevalued assetswould reflect positive net income after interest expense, and cash generationafter debt service, in each of the years FY'85 to FY'90. It should be noted,however, should NTPC achieve only the minimum 7% rate of return during thisperiod, it would not imply an adverse effect on implementation of the invest-ment program as GOI would cover any resulting deficiency in the plannedfinancing. It should also be noted that NTPC's projected rates of return arerealistic and achievable. The equivalent financial rates of return on net

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revalued assets, based on a pro-forna revaluation (Annex 4.6), are 8.8Z inFY'84, 7.2% in FY'91 and 7.5% in FY'96 which are satisfactory. GOI continuesto oppose the principle of revaluation of assets, operated by public sectorundertakings, and the calculation of depreciation on the basis of revaluedassets. The Bank, however, prepared under Loan 2442-IN, and for the proposedProject, a pro-forma revaluation of NTPC's net assets in operation for pur-poses of checking the adequacy of the rates of return on unrevalued assets.The Bank has consequently, as an alternative to a rate of return on revaluedassets, raised the minimum rate of return on unrevalued assets from 9.5Z inFY'96 and thereafter, to a level considered satisfactory to ensure the con-tinuing financial viability of NTPC. The level of 14.7% reflected in theprojections (Annex 4.3) is satisfactory to achieve this objective. Thiscompensates for the failure to revalue by providing a higher return onunrevalued assets, than normally required, to ensure sufficient cash gener-ation to provide a satisfactory level of contribution to investment and toprovide for renewal and replacement of -assets as they reach the end of theiruseful life. We would expect that NTPC would continue, as in the past, toprovide the necessary data to enable the Bank to calculate rates of return onrevalued assets, on a pro-forma basis, to be used as a check on the adequacyof rates of return on unrevalued assets.

4.09 Net earnings, after interest expense, were Rs 449 million in FY'84,representing about 32% of sales revenue. These are projected to increase toRs 6,824 million in FY'91 and to Rs 25,622 million in FY'96 representing 23%and 28% of sales revenue respectively. The ratio of net earnings-to sales ishigher in the early years of the projections, due to proportionately lowerinterest expense, owing to GOI's practice of advancing to NTPC the equitypart of project financing before the start of GOI loan disbursements. Thenet earnings ratio to sales, however, improves in the later years of theprojections owing to loan repayments and the resulting interest saving.NTPC's forecast of future financial performance and cash generation aresatisfactory.

4.10 Forecast Balance Sheets, for each year FY'85 through FY'96, are setout in Annex 4.4. A statement of source and application of funds for thesame period is provided in Annex 4.5. These reflect the commencement ofcommercial operations in FY'83, and the financing of NTPC's capital require-ments through generation of internal resources, and through a combination oflong-term borrowing and equity capital. Initially the equity portion offinancing would be released by GOI, followed by loan capital, except in thecase of the Bank loan for the proposed Project, which the Bank intends tolend directly to NTPC (para 4.16). Table 4.1 sunmarizes NTPC's financialposition at three significant points in its development, namely: at March 31,1983, the year in which NTPC commenced commercial operations and becamerevenue earning, at March 31, 1990, the year following the year in which theproposed project would be completed, and at March 31, 1995, the first fullyear in which all generating units, of the projects presently officiallyapproved by GOI, would be operatfng at full capacity. These forecasts show

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that in FY'83 when NTPC started generation and commercial sale of elec-tricity, total capitalization was Rs 15,050 million (US$1,254 million),divided between GOI Loans (including the onlending of Bank Group credits andloans) and equity in a ratio of 21/79. Seven year later (March 31, 1990),after the proposed Project is completed, total capitalization would rise toRs 183,585 million (US$15,299 million), reflecting a debt/equity ratio of34/64. The debt/equity ratio would increase slightly to 35/65 by March 31,1995 at which point capitalization would have increased to Rs 397,597 mil-lion. The lower debt/equity ratio in FY'83 compared to FYs'90 and '95 isattributable to the drawdown of project equity financing prior to loanfinancing. For this reason, also, the debt service coverage (Annex 4.5) isprojected to decrease from 3.5:1 in FY'84 to 2.0:1 in FY'90, and due to loanrepayments, increase from FY'91 to FY'95 to 2.2:1 and 2.7:1 respectiveLy.NTPC's debt/equity ratios, debt service coverage and financial position, asreflected in the projections, are satisfactory.

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Table 4.1 Financial Position of NTPC

At March 31st FY'83 FY'90 FY'95(Rs Million)

Fixed Assets at Cost 3,036 115,318 318,090Less: Depreciation (68) (7,833) (39,323)

Net Fixed Assecs in Service 2,968 107,485 278,787Work-in-Progress 12,758 71,731 75,073

Total Net Fixed Assets 15,726 179,216 353,840

Short-Term Deposits - - 29,506Working Capital (702) 4,369 14,251Deferred Preliminary Expenses 26 - -

Total Net Assets 15,050 183,585 397,597

Financed By:

Equity Share Capital 11,810 104,925 173,026Retained Earnings 46 16,110 86,018Total Equity 11,856 121,035 259,044

Long-Term Debt (including IDACredits/IBRD Loans) 3,194 62,550 138,553

Total Capitalization 15,050 183,585 397,597

Debt/Equity Ratio 21/79 34/66 35165

NTPC's Regional Tariffs

4.11 A comparison of NTPC's projected regional tariffs to LRMC for theperiod FY'85 - FY'96, is provided in Annex 4.7. The LRMC, in FY'85 prices,have been escalated annually by inflation factors of 8.5% in FYs'85-'91, and6.0% in FY'92 and thereafter, to provide a comparison with the regionaltariffs, which are expressed in current prices. The Northern Region tariffsincrease from 32.3 paise/kWh in FY'83 to 56.9 in FY'88, to 70.5 in FY'91, andto 97.7 in FY'96, representing a compound annual increase from FYs'85-96, ofabout 9%. As a percentage of LRMC the Northern Region tariffs representabout 90% in FY'85, 100% in FY'88, and about 992 in FY'96. The projected

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tariffs for the Western Region increase from 36.0 paise/kWh in FY'84 to 52.5in FY'88, to 66.3 in FY'91, and to 89.4 in FY'96 representing a compoundannual increase of about 8% from FY'84-'96. As a percentage of 1.RMC theWestern Region tariffs represent, for FYs'85, '88, '91, and '96, about 102%,105%, 104% and 102% respectively. Southern Region tariffs are projected toincrease from 50.0 paise/kWh in FY'84 to 59.5 in FY'88, to 67.3 in FY'91 andto 93.9 in FY'96, representing a compound annual increase of about 5X fromFYs'84-'96. The Southern Region tariffs, as a percentage of LRMC, would beabout 127%, 109%, 97% and 99Z for FYs'85, '88, '91 and '96 respectively. Thetariffs of the Eastern Region are projected to increase from 52.5 paise/kWhin FY'86, to 55.5 in FY'88, to 65.6 in FY'91 and 92.6 in FY'96, representingan annual compound increase of about 6% from FYs'86-'96. As a percentage ofLRMC, the Eastern Region tariffs represent 115Z, 103%, 96Z and 99% forFYs'86, '88, '91 and '96 respectively. NTPC's average tariff increases from32.30 paise/kWh in FY'83 to 56.02 in FY'88, to 67.95 in FY'91, and to 93.22in FY'96, representing a compound annual increase of 8.5%. Although therelationship of Regional tariffs to LRMC fluctuates to some extent, due tothe lumpiness of investments, and at points in time the tariffs exceed LRMCbetween FY'85 and FY'91, it smoothes out and remains relatively constant andclose to LRMC from FYs'91 to '96. NTPC's projected regional tarifks arelower than the projected cost of generation for each of the SEB's of theNorthern Region, with the exception of PSEB. In the case of PSEB, NTPC'stariffs would be higher in the range of about 8Z to 11% over the periodFY'86-FY'95. SEB purchases of power from NTPC consequently would not distortleast-cost system operation in the Northern Region.

4.12 NTPC's projected financial performance and financial position, asreflected by its financial rates of return on both unrevalued and revaluednet assets (para 4.08). incernal cash generation as a contribution to invest-ment (para 4.06), debL, quity ratio, financial position and debt servicecoverage (para 4.10), and the favorable relationship between regional tariffslevels and LRMC (para 4.11), wouild indicate that NTPC will progressivelydevelop towards being a financially sound and viable organization, able tomaintain a satisfactory level of self-financing of its investmeat program andreplacement and renewal of assets.

Commercial Arrangements for Sale of NTPC Power

4.13 Under previous loans and credits, GOI and NTPC agreed to sell thepower from NTPC's power plants to its customers under contracts satisfactoryto the Bank Group. Contracts have now been concluded between NTPC and theDelhi Electricity Supply Undertaking, the Damodar Valley Corporation, theElectricity Department of the Union Territory of Goa, and all but two of theSEBs, with respect to sales of electricity from the four major Regionalplants--Singrauli (Northern Region), Korba (Western Region), Ramagundam(Southern Region), and Farakka (Eastern Region). The Bihar and West BengalSEBs are not expected to receive power from the Farakka plant for some time,as the first 200 MW unit there is yet to be commissioned. GOI and NTPC

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agreed, during negotiations for the proposed project, that contracts inrespect of these SEBs would be concluded and provided to the Bank by August31, 1985 (para 6.03(e)). The Electricity Department of the Union Territoryof Pondicherry is not expected to receive power from the Ramagundam plantumtil the commissioning of the second stage, which begins in early 1988. Acontract in respect of this entity is therefore not yet required but will beconcluded at the appropriate time.

4.14 The contracts concluded to date are interim contracts only, sincecertain additional provisions--contract renewal, tariff revision, capacitycharge, and NTPC's return on equity--need to be included. GOI and NTPCpropose in due course to replace these interim contracts with eitherindividual or regional supply contracts (one for each Region) that willprovide uniform terms and conditions for the sale of electricity by NTPC toall SEBs and other customers within each region. Accordingly, GOt and NTPCagreed during negotiations to provide to the Bank, by March 31, 1986, revisedbulk suppLy contracts incorporating the necessary additional provisions withrespect to the SEBs and other NTPC customers of the Northern, Western,Southern and Eastern Regions. In the interim, the terms of the existingcontracts will continue to apply (para 6.02(f)).

Taxation

4.15 NTPC is liable for income tax under the Income Tax Act, however, inview of NTPC's large capital expenditure program, tax relief is providedbeyond the period of the present investment program and financial projec-tions. A tax equalization reserve, therefore, is not necessary.

Bank Loan for the Proposed Project

4.16 GOI's policy in financing projects of NTPC, and other central publicsector undertakings, has been to provide 50% of project financing require-ments as loans, including the onlending of Bank loans, and the remaining 50Zas equity share capital. The loan financing has been disbursed to the entitysubsequent to drawdown of the total equity portion. The consequence of thispractice has been that Bank loan disbursements has been, in effect, onlent asequity with NTPC incurring no loan liability or interest cost until GOI loandrawdowns commence. This would be in about the fourth year of implementa-tion, in the case of the proposed Project. This practice is not goodresource mobilization in respect to the interest foregone by GOI. Moreover,it introduces unwarranted financial practices on the part of NTPC, insofar asthey do not absorb the interest due, nor the liability incurred, on therelevant loan financing. The tariffs, consequently, understate full costs asthe true interest cost is not reflected in the cost of supply. If Bank loanswere onlent to NTPC at the time of the Bank's loan disbursements, interestcosts would be incurred by the entity, during project implementation, andcorrectly apportioned between capital costs and revenue expenses, a practicepresently followed by NTPC. It was consequently agreed during negotiations

P

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that the Bank Loan for the proposed Project would be onlent to NTPC by GOI inaccordance with an acceptable Subsidiary Loan Agreement as a condition ofeffectiveness of the Bank Loan. It was further agreed that the terms of theSubsidiary Loan Agreement would specify that Bank Loan disbursements beonlent on a quarterly basis to NTPC, being paid in the first montt of thequarter following the quarter in which GOI receives such disbursemt.. :s. Theterms would also provide for maturity in 20 years, including a grace periodof five years, and repayment of principal in equal semi-annual installments,with interest payable on outstanding balances at not Less than 12.5% perannum. This minimum onlending rate provides sufficient margin over thecurrent Bank rate of 9.29% to cover the foreign exchange risk which is borneby the Government, and represents about 6% in real terms.

Audit

4.17 As required by the Manufacturing and other Companies (Auditor'sReport) Order, 1975 issued by the Company Law Board in terms of Section 227(4A) of the Companies Act, 1956, the audit of NTPC's accounts is performed byprofessional auditors appointed by the Company Law Board, on the recommenda-tion of the Comptroller and Auditor General of India. The auditors arenormally members of the Indian Institute of Chartered Accountants. Theauditors' report is subject to review and comment by the Auditor General ofIndia. For FYs'83 and '84 the appointed auditors were P.K. Maheshwari & Co.and Goel, Garg & Co., both firms of Chartered Accountants. The auditedfinancial statements and auditors report for FY'83 and FY'84 were satisfac-tory to the Bank. The auditor' s reports contained no substantive recommenda-tions or adverse comments. As has been agreed in connection with previouscredits and loans, NTPC agreed during negotiations to submit to the Bankaudited financial statements within seven months of the end of the fiscalyear to which they relate, together with a certified reporr by the auditors,and comments of the Comptroller and Auditor General of India (para 6.03).NTPC has complied with this undertaking for FY'84 and prior years.

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V. PROJECT JUSTIFICATION AND ECONOMIC ANALYSIS

Least Cost Alternative

5.01 Principal energy resources in the Northern Region, where the proposedProject will be located, are concentrated in its two extremities. A vasthydro potential exists in the Himalayas, in the northwest, and there arelarge coal reserves in the southeast, of which about 10 billion tons arebeing developed to generate po.er in the Singrauli-Rihand complex (para3.01). In contrast, the States of Punjab, Haryana and Rajasthan in themiddle of the Northern Region do not have significant energy resources and itis in these states that the major load centers are located, particularly inand around the Union Territory of Delhi. Consequently, supply to these loadcenters requires either high voltage transmission or transport of coal toload center stations. Although reasons of system security and stabilitydictate that there should be a proportion of power supplied by load centerstations, the core of the least cost development plan comprises mine mouthstations and high voltage transmission. In 1982 CEA, assisted by HQI, car-ried out long-term planning studies for the development o' the EHV transmis-sion system for the region. Three options for system development were inves-tigated: (i) expansion of the existing 400-kV network, (ii) introduction of ahigher AC grid at 735-kV, with initial operation at 400-kY, and (iii) acombination of an AC-DC system. The analysis concluded that the AC-DC system,the proposed Project, was the least-cost option. While in principle a com-p-ehensive national transmission study, such as has been included with theproposed Project, is desirable to confirm the optimality, this is not prac-ticable given the timescale required for the study. The Bank is confidentthat the geography of electricity supply and demand is such that a transmis-sion line between Rihand and the Delhi region would still be a vital part ofany comprehensive plan and therefore, that the results of the previousstudies are robust. Present information also indicates that the potentialfor gas-fired power generation in Delhi which has recently emerged as apossibility, is limited by the availability of gas and is insufficient toaffect the desirability of the proposed Project.

Internal Economic Rate of Return

5.02 Although the Project is crucial to the development of the powersystem in the Northern Region its benefit to consumers cannot be separatedfrom those of investments in generation, other transmission lires and dis-tribution. Therefore, having established that the proposed Project formspart of the least-cost expansion plan it is appropriate to carry out acost-benefit analysis on the entire plan in order to ensure that the expan-sion envisaged is desirable. For this purpose a 'time-slice' of the NorthernRegion's investment program, covering the period FY'85-FY'95, has beenanalyzed. Capital costs of the investment program (covering generation,transmission and distribution) together with incremental operating and fuelcosts are given in Annex 5.1. The benefits of the investment program relate

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mainly to the incremental consumption which it makes possible 1/. A minimummeasure of benefit, which ignores consumer surpLus, can be derlived from therevenue generated by the incr-mental sales. In the absence of adequate classspecific consumption conversion factors, the standard conversion factor(estimated to be 0.8) has been applied to convert financial revenue into ameasure of economic benefit. On this basis the minimum internal economicrate of return achieved by the program is 4%.

5.03 However, this estimate is more useful as a measure of the adequacy oftariffs than of the economic merit of the investment program which includesthe proposed Project. The estimated minimum economic rate of return, 4Z, issubstantially less than the established opportunity cost of capital, and thisis indicative of the fact that tariffs to consumers are presently less thanLENC (para 1.05)21. In reality the program will confer benefits in excess ofthose de?cribed above. There will be consumer surplus associated with theincremental consumption and typically there will be other external benefits.The severe shortages of power experienced at present, and expected for theforeseeable future (para 1.10) suggest that consumers' willingness to paysubstantially exceeds present tariff levels.

5.04 In order to derive a more realistic estimate for the internaleconomic rate of return of the program it is useful to impute a measure ofconsumer surplus, at least for industrial and agricultural consumers. Theirwillingness to pay will be related to the costs of autogeneration and dieselpumping, which many consumers are observed to find economic when publicsupply is not available. Annex 5.1 presents an estimate of dieselautogeneration costs at Rs. 1.12/kWh. It would, however, be unreasonable toassume that all consumers would be willing to pay this price for the whole oftheir consumption from the public supply system. Therefore, as a conserva-tive measure, it has been assumed that the consumer surplus attributable toincremental sales can be derived from an average of the cost of autogenera-tion and the prevailing tariff. Similarly for agricultural consumers the

1/ The program may also lead to benefits in terms of a reduction in the costof meeting existing demand, particularLy through fueL savings. However,the energy deficit is such that by far the greater part of the outputavailable from plants in the program will lead to increased sales. Fur-thermore, the existing plants do not .ave particularly high fuel costs(being predominantly coal or hydro-electric). Therefore, fuel savingsresulting from the program are likely to be small and this element of thebenefits has therefore been ignored.

2/ It should be noted that although final consumers' tariffs are much lessthan LRMC, analysis of NTPC's, and bulk tariffs suggest that they are inline with LRMC.

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equivalent cost of diesel pumping has been estimated at Rs. 2.21/kWh andaverage willingness to pay has been estimated at halfway between the averageagricultural tariff and this alternative cost. This more realistic measureof the benefit of consumption results in an internal economic rate of returnfor the program of 13Z. However, it must again be stressed that this stillrepresents a lower bound estimate as domestic consumer surplus and otherexternal benefits, have still not been included.

Justification for Bank Involvement

5.05 The Bank would be supporting GOI's efforts to alleviate powershortages and reduce transmission losses as the Project would add efficienttransmission capacity to evacuate power from the new thermal capacity beingconstructed in the Singrauli-Rihand area to load centers in the middle ofthe Northern Region. In addition the Bank's involvement would promote:

(a) the introduction into India of a new technology in power trans-mission (HVDC) capable of evacuating large quantities of powereconomically over long distances;

(b) the rational development of a national interconnected grid, byensuring sound planning of the grid through the transmissionstudy which is included with the Project;

:c) the mobilization of foreign exchange financing through bilateralagencies and/or commercial/supplier's credits.

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VI. AGREEMENTS AND RECOMMENDATION

6.01 During negotiations GOI agreed that CEA will undertake studies forthe formulation of a least-cost long-term (15-to 20-year) national powertransmission plan and to address issues pertaining to the institutional,coomercial, operational and training aspects of the system at the State,regional and national levels. The scope and terms of reference of thestudies will be prepared by CEA in collaboration with the Bank by B)ecember31, 1985. The studies and the national power transmission plan will becompleted and the results reserved with the Bank by June 30, 1987 (para3.07).

6.02 During negotiations the following issues were raised with COI andNTPC, and satisfactory clarification, agreement or assurances were obtainedwith regard to:

(a) revolving letters of credit which should be opened, by allrelevant NTPC customers, for an amount equivalent to one month'spurchases of power (para 4.04).

(b) reduction of NTPC's accounts receivable to a level not exceedingthe equivalent of two months' sales of power (para 4.04).

Cc) timetables to liquidate arrears in accounts receivable (para4.04).

(d) annual rates of return on unrevalued net assets in operationwhich should be not less than 7Z in FY'85 through FY'90, notless than 9.5Z in FY'91 through FrjO5, and thereafter annualrates of return at levels satisfactory to ensure the financialviability of NTPC (para 4.08).

(e) interim bulk supply contracts which are outstanding for two SEBswould be concluded and submitted to the Bank by August 31, 1985(para 4.13).

(f) satisfactory final bulk supply contracts -which would be sub-mitted to the Bank by March 31, 1986, and subsequent revisionswhich wouLd similarly be submitted to the Bank for review (para4.14).

6.03 During negotiations NTPC agreed to sbmit to the Bank, audited finan-cial statements within seven months of the end of the fiscal year to whichthey relate, together with a certified report by the auditors, and commentsof the Comptroller and Auditor Ceneral of India (para 4.17).

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6.04 Subject to the foregoing, the proposed Project is suitable for a Bankloan of US$250 million_

aluAm EOWA TANSMBISSION PROJECT

Electricitl Gcneration. Salg end Pattern of Enalav Conuomotioa - All India

Description nm =5 n- 'a Wm6 *'6 6 PY:7 gm '79 z'Q Y' 1 Ptr8 Wm8 "

Installed Capacity (NW) 1,835 2,886 4,653 9,027 12,957 16,664 26,680 28,448 30,214 32,344 35,361 39,360

Electricity Generated(CWh) 5,858 9,662 16,937 32,990 47,433 66,689 102,523 104,627 110,821 122,010 130,211 139,877

Electricity Consumption(CGh) (Utilities only) 4,793 7,959 13,953 26,735 37,352 50,246 77,293 78,124 82,473 90,237 9S,917 K

Per Capita Generation(kWh) 20.80 30.90 43.90 73,81 97.82 126.26 159.60 160.00 166.20 182 183 NA

Per Capita Consumption(kWh) (Utilities only) 12,30 20,70 31.90 53.70 70.80 87.15 120.48 119.40 123.70 132 135 NA

Consumation Pattern (S)

Domestic Light &small Power 12.40 11.70 10.70 8.80 8.50 9.20 9.80 10.76 11.28 11.50 12.48 NA

Comm_ercial Light 68m11 Pover 6.90 6.80 6.10 6.20 5.70 6,00 5.60 5.96 5.95 5.98 6.28 NA

Industrial Power 63.70 66.90 69,40 70.60 69.30 64,60 61,35 58.86 58.60 58.75 55.80 NA

Railway/Traction 6.90 5.10 3.30 4.00 3.30 3.00 2.83 2.95 2.82 2.78 2.79 NA

Agriculture Pumps 4.30 4.00 6.00 7,10 9,30 12.60 15.56 17.23 17.48 16.71 18.55 NA

Public Water Vorks,Sewage Pumping, PublicLighting & Others 5.60 S.50 --4.50 3.30 - .2I0 4.60 4.86 4.24 3.87 -4.28 4Q.1 NA

Total 100.0Q 100.00 QQO 100.00 100.00 100.00 10O 100.00 100.Q0 100.00 lOO.00 100.00

NA - Not Available

source: COA

IINDIJA

lIRAUD -POlER TU5N1II0ON PROJECT

Poreeaa of Eagional Power Dnaud in India. FY'86 - FYg92

__Jt 86 n ~FY87 n 88 n V-89 FY ._ 1 0:9Energy Peak Enersy Peak Eoergy Peak Energy Peak Eoergy Peak Energy Peak Snergy took(GWb) Load (CGh) Load (GlM) Load (GMO) Load (GWb) Load (GMi) Load (CWl) Load

(V) (HU) (wN) (NW) (MW) CM) (w)

Wortbern 54,549 10,643 60,000 11.704 65,824 12,841 71,996 14,045 78,583 15,331 85,562 16,692 93,023 18,147

Western 53,097 9,184 58,002 10,035 63,338 10,962 69,046 11,953 75,153 13,010 81,730 .14,153 88,737 15,369

soutbern 47,188 8,558 51,676 9,359 56,521 10,221 61,778 11,158 67,509 12,175 73,704 13,276 80,227 14,431

Eastern 25,669 4,505 26,274 4,924 30,827 5,368 33,517 5,837 36,323 6,327 39,279 6,641 42,380 7,382

Nortb-Eastern 1,991 432 2,261 491 2,536 548 2,825 610 3,135 674 3,486 747 3,869 825

Andaman &NicobarIslands 23 7 26 8 30 8 33 9 37 10 41 11 45 12 %

Lakqbadveep 3 1 2 4 2 4 4 __ 4 2 2 2

All India 182,720 33,330 200,242 36,523 219,060 39,950 239,199 43,614 260,744 47,529 283,807 51,722 308,286 56,168(Total) *umano -- - m - - -- .* ..... u.uMa . mumum u..... .mu... -_mu."...... uu _u u...

Bouroet COA

aIlNuD POYER TRANSMISSION PROJECT

ELECTIICITY CGEflTION AND CONSUKPTIOX O NORTHERN 3101ON

(Clib)

Average AnnualGrowth Rate

n ^79 nIS 80IS n n'82 n '83 tYY&4Y71-F'83

ELECTRICIT! GEnITID

Baryaons 3,855 3,968 4,289 4,818 4,911 NA 6,2Liuachal Pradesh 398 355 245 432 540 NA 7.9Jamu and Kashmir 533 690 768 785 936 NA 15.1Punjab 6,073 6,235 6,483 7,010 7,777 NA 6.3Rajasthan 3,597 3,725 3,393 3,561 3,604 KA 0.0Uttar Pradesb 10,139 10,124 10,190 11,348 12,585 NA 5.6Chmndigarh - -Deou 1.413 1.467 1.313 1.113 NA7 M

Sub-total 26,008 26,562 26,681 29,072 31,430 NU 4.8

Central Sector 1.,541 2,665 3.317 3552 5.648 NA 38

TOTAL REGIOtI 27 S49 29.227 29.998 32.624 37078 39.672 7.6

BLECTRICITI CONoUxPTION

Haryana 2,415 2,355 2,556 2,999 3,326 NA 8.3limacbal Pradesh 207 233 260 287 330 KA 12.2Jasu and Kashmir 400 421 440 493 651 NA 12.9Punjab 4,656 4,915 4,997 5,046 5,843 NA S.8Rajasthan 2,604 2,974 2,935 3,130 3,265 NA 5.8Uttar Pradesh 7,688 7,611 7,846 8,494 9,843 NA 6.8Chandigarh 154 152 170 181 196 MA 6.2Deau 13 JAM 2.3J 25 26

Total Region 20.01f 12 t 1721.531 23.132 261a3Z 2Z.200 i.

NA: Not AvailableSource: COA

RIBAND ?MWl TIANSHISSION PROSJEC

FPOWER SUPPLY PQBITION OF NORTUREN REGION (ON-GOING UCEZIU ONLY)

Installed Capacity (NW)

Total 8,782 9,451 10,278 11,169 11,929 12,871 14,631 16.641 17,985 19,148 .20,7 56 21,803 .22,193

Hydro 4,033 4,144 4,441 4.771 5,001 5,094 5,604 5,849 6,038 6,491 7,601 6,646 9,636

Thermal 4,309 4,867 5,397 5,958 6,488 7,337 8, 567 10,117 11,037 11,747 12,247 12,247 12g247

Nuclear 440 440 440 440 440 440 440 675 910 910 910 910 910

Peak Availability (MW) - 5,791 6,470 6,779 7,190 8,98 9,123 10,034 11,013 11,906 13,732 14,702 15,632

Peak Demand (MV) - 5,741 6,470 6,779 8,790 10,703 11,793 12,961 14,200 15,326 16,932 18,431 42,024

supply/(Deficit) (K(W) - - - - (1,600) p2,40 5) 42,670) (2,933) (3,187) (3,620) (3,20) (3,729) (4,392)

Energy Availability (Glib) .28,663 31,223 35,819 36,463 41,880 5D,376 55,807 62,970 70,563 77,367 89,128 96,729 101,310

Energy Reaquirement (GUh) 33,111 36,312 39,082 40,243 46,905 56,779 60,356 66,325 72,658 79,433 86,622 94,285 102,432

surplus/(Deficit) (Glib) (4,448) ( 5,098) (3,264) (3,780) ( 5,02 5) (4,403) (4,549) (3,3 55) (2,09 5) G2,066) .2,50D6 .2,444 (1,122)

source: CIA

KnATIOLL MA= U COVOhIAYION

EnutAYis PACILITI3I - O?3ATIOIL PfhIAmCE

8totlon Ca tep ellbllleit1 Cerle oedmtr;/Rt*s

(NI ( *ro per (2) CWbK1 L 2ad1ic tr

Unit 1 200 01.06.J2 6,121 70.26 1,078.3 61.55 2,752 30.52it zoo 01.02.83 910 30.00 160.4 23.04 3,223 26.58

01.07.13 - - -

Aveirta WEBS 4,36 4 5,634 66.W 17,806.0 65.10(Tbenral)Average India 18,490 - 6,132 70.00 77,135.5 49.80(TboenaI)

Enl'

Unit 1 200 7,000.6 79.72 1,340.4 76.30 2,510 34.2611 200 3,680.0 61.89 700.1 39.65 2,590 33.20

III 200 4,336.0 49.36 797.5 45.39 2,535 33.93IV 200 2,079.3 57.73 405.9 56.24 2,491 34.52

VW 20037.7 - 2.4 - - -1.00 3,245.6 52.6

KOR1

unit 1 200 01.06.83 6,527.8 74.32 947.3 55.46 2,838 30.3011 200 31.10.83 2,161.6 5J.90 340.2 46.32 2,759 31.17

III 200 17.03.84 1,145.1 40.30 9.. 1MANl 3,676 23.38600 1,324.3 51.66

Unit 1 200 01.03.86 1,570.6 41.70 205.0 27.2 2,725 31.55

Average IllS 6,258 - - - 19,311.0 42.3 - -(Thenal)

Averge India 23,825.5 - - - 86,516.0 47.9 - -

(The mal)

1/ Durins the first motbs of operoation, the avalabilty Is nornally haspered by problems of rtoblilction of erquipmotthereafter an avarage of around t02 would be expected for coal-fired uoits enabling sufficient tim for oloteonace,overhauling and forced outagse.

21 The load factor is the ratio of average load over the year to the peak capacity of the uiLt; the load factor depeadaon the coyst requiremeuta but TPC coal-fired malte being ormlly used to supply the base load wuld be expected tohave a bigher load factor thao the cytet load factor; hoever, i prerlawity in ceol supply sad Its qu4llty often reduce.the load factor.

sources CIA sad WTC

INDIA

IMiIDlIMll 111ERMLPIEIRliE CUPOPTI01 tLIMItED

. .. _.....................NIMIIO P0313 TEMUMINM!al PROECT

-°C----...l.! C.°IISSIOW OP POR PLANTS

UI IV FISCL iWii

*alllsomessit Ts Bea I stag* =X*s X *Xt I-*AI Nl"S* ll stswlt*X|StelW |X *tl *st Ito twllZ es *ls asZ *l248 *sXl*wttlgll volatl|SXUlp-4 We'l|sl sl9s wls lll Sul...2|

cuImiSiOWi, INCNRONW.UICML ORDER DAIE IN 1992 183 3914 193 In936 1"? 7 19K If" 399o l99 1992 193 1991 It" 19`& 3991 IM 199! 2000wss p sesalaT Isw "O'l' no, wssu 'I'll",ssssss s Isa all"1211111181w, "ssssssawswsw Ron sss 11838"'l "'ese sa *w"litges"n ol" I" Iota 10 Is 58,1112 a, I"'sss s w s l"|$ w w nsw "s aasI l I I FEI.12 200 2 20

RiM I OV.032 200 200SoUR I NAR.33 200 200............................ ....................................... _

RIA 1 OCT.33 200 20SIINAUtl it NOV.33 200 200RMAN I NOV.33 200 200IDIE AI I II FEllt. 200 200kORIA I MA.31 20 200

i............ ii i -i... . ............. _ _IIAIIIW I JUN1.94 200 200MARKA I J.15 200 200

RAMUUDAN I P9.03 200 200......................... Ju...............O....................................... "

FARAUA I JAN.16 200 200..... ... .......... Rvlw...... ...... ............... ........................................... _

SIIAWIIUt II Ff3.31 500 540~~~~~......................................................... ............................................................ ............... IIIAD A 2 o0 5.00VINNHIf KI JUNA? 21 210KORDA II AUG.$? 500 SooVINIYAL DEC.17 230 210SIA$AII If FILM0 500 300. ........----------------------....... ................................................... . .................... * 0 RITNANll JIl. N 500 500VlIN"OACHAL JUN. 210 I00VMAS3UAMOIU 116 61 500 500KOIA I I JUIN 500 S00VIKHIIACtHAI DECE1A 210 230

.... ................... ................................................................. ............................................................... _

YINSIYACNL JU.,9 210 210RP A N II JUL."9 500 500KeImA if ALIS,I19 500 socV3N114ACUII DEC.39 210 210

IIU401- 0. . . ..IN.I. ...1. . .AR.90 210 020FUASkKA II MAY 90 500 500KAN6RMU JULI.9 210 210ORANATDAM II JLL.90 S00 soUANIAL INAT.CAP G.REB OCt.90 210 210

kANALSAO I DEC.90 230 210

MUANIARll IIEIIC .ROJt APR.9l12 2300t°t 6 W,._ 'CA. _R' 6. ---- 2D......................................................... _ t0

INIIFIED NEW PMOJ'l 11 APR.91 500 500FA KIA 111 mAl 91 500 500

KAMUMN ~~~JUN.91 230 210NLMIOMAIAA (NAT.CA.RfS.) OCt.91 230 230loIDE FIED NEl PROJT 32 OCT.91 500SoRAIALAO DEC.91 210 210IDENTIFIED NEI PROJ't 13 JAN.92 500 500

33E11111E3 U PIOJ'1 R APR.92 50 500FARAKA IIT NAY 92 500 500IDETIFlt III NE MOJ' 12 OCT.92 500 500lINllFIEl EUV PIO'T 33 JAN. 93 500 500.IE.TIFIED NEU PRDJ'T 14 MR.93 500 500

INDIA

NATIONAL TRERIML POWER COAPOPATION LUNITED

RIAOPWR TNA SISIIN PROJECT

SCHEDULE OF CONNISSIONINS OF PODlR PLANTS

Oh f FSCAL YEARS

CNRONMOLOICAL ORDER DATE II 19912 599 191 M9S 1914 1997 199013999 1990 3991 3992 3993 299 3995 2994 5997 199. 2959 2000

IDENTFIEDNEW ROJ' SO APR.93 500 500IDNTIIFIED NEW PROJ.? 06 JUN.93 230 230IDENTIFIED PNE PROJ'T Ii OCT.93 500 500IDNOTIFIED NEW PROJ'S 54 DEC.93 230 210IDENTIFIED NEN PROJ'T N4 WM.94 500 500

IDENTIFIED NEW POJ'S .. HAPR.9-4 .... 50'0 .......................................---- 500IDENTIFIED MNE PROJ'S 14 JUN.91 230 210IDENSIFIEC NEW PROJ'S 17 OCT.94 500 500IDENTIFIED NEU PROJ'S lb DEC.91 230 230IDENTIFIED MNW PROJ'T SI JAN.95 500 500

IDENTIFIED--- EN P9ROJ--'S00 -----------------------------------------------APR.95----- 5----------------00IDENTIFIED NEV PROJ' 1190 JUR..95 500 500IDENTiIFIE NEW PROJ'T Nil OCT.95 500 500IDENTIFIED NEN PROJ'S NI JAN.94 500 500

IDENIFIED NEW PRJ'S 69 APR.94 500 soo IDETIFIEDMENE PROJ'S 530 JUL.94 500 500IDENTIFIED NEW PR0J'IIoil OCT.941 500 500 aIDENTIFIED NEW PRQJ'T 622 DEC.94 500 500

IDENTIFIED MENMPOJ'S 113 APR.97 500 500IDENTIFIED NEW PROJ'T 622 DEC.97 500 500

IDENTIFIED NEW PROJ'T 633 APR. 99 500 0IKIITIFIED MEN PROJ'T 324 JIL.9B 500 500IDENTIFIED NEW PROJ'T 325 OCT.91 500 500

IDENIFIED EM PROJ'T 534 JUL.99 500IDENTIFIED EU PRW'T 335 OCT.99 500 N00

TOTAL IMETIFIED I APPROVES 22,210 200 400 1,000 400 400 500 2,920 1,920 1,420 2,640 1,310 500 0 0 0 0 0 0 01I1EN.1EW MPRJS-NOT YET NI1 APP'S 34,340 0 0 0 0 0 0 0 0 0 0 3,500 2,000 3,92 1,920 2,000 2,000 1,000 1500 3,00

ITOIL CAPAITY ADDED IN) 27,010 20 00 3,000 boo 400 500 1,920 2,920 1,420 1,110 2,140 2,500 3,920 1,920 2,000 2,000 1,000 3,500 1,000

TOTAL CIMILAT IV! CAPACITY It 200o 500 3300 2400 2100 3300 5220 1140 9540 10400 13240 55140 11440 59590 2159 2356 24560 2400 21090333323333333332333332133333.333322333333333333333103 33333333331213uSiSmana: aw:: 5333 3U33 333 .. 3..323133533

INDIARIHAND POWR TRANSMISSION PROJCT

Nationa *wmI P CofPotlgoAnzobnol Shiwture

iwoc ~ ~ CiwG

L*KtO~ ~~~~~~~~~~~~~~~~~gb

. LZ - I c'.- II~~~~~~~~~~Ib

}3 wi j lew^~~~~~~~~~~~~~~~~~~~~~~~marnlIfnlgtw>1GFC*Ma

(f hblwEa

T~_-L

I IiI@1 f W1 i11k

ANNEX 3.1-46- Page 1 of 6

INDIA


PROJECT DESCRIPTION

The project consists of the following major physical components whichare also indicated on the single Line diagram in Attachment 1.

I. 400-kV Transmission Lines

The expansion of the 400-kY network would be comprised of:

(a) Rihand-Singrauli, single circuit: 40 km;(b) Rihand-Kanpur, single circuit: 450 km;(c) Kanpur-Ballabgarh, single circuit: 450 km;(d) Ballabgarh-Jaipur, single circuit: 310 km;(e) Ballabgarh-Muradnagar, double circuit: 20 km;(f) Muradnagar-Karwalnagar, double circuit: 17 km;(g) Muradnagar-Panipat, single circuit: 100 km;(h) Muradnagar (NTPC)-Muradnagar (UPSEB): 10 km;(i) Jaipur (NTPC)-Jaipur (RSEB), double circuit: 20 km;(j) Kanpur (NTPC)-Kanpur (UPSEB), double circuit: 20 km

These lines will be constructed in accordance with NTPC scandards andpractices.1/

II. 400-kV AC Substation

Rihand: Modifications to the already ordered sub-station of NTPC tomake it compatible with requirements of the HVDC terminal.

Singrauli: Extension of the existing sub-station located at the siteof Singrauli power plant to allow for connection of theRihand-Singrauli line at the substation.

Kanpur: New substation to connect the Rihand-Kanpur-Ballabgarhlines as well as the Singrauli-Kanpur-Agra-Jaipur lines ofNTPC. This substation would also be connected to the

1/ The salient features of the NTPC 400-kV transmission lines have beendescribed in the Central Power Transmission Project SAR (Report No. 4293-IN)in Annex 13, Attachment 1.

-47-

ANNEX 3.1Page 2 of 6

existing 400-kV Kanpur substation of UPSEB. Provision fora reactance would also be made at this substation.

Muradnager: Extension to the proposed 400/220-kV substation toconnect the Ballabgarh, Muradnagar (UPSEB) and Panipat linesand accommodate off take from Delhi HVDC terminal as weLl asa new substation being created to feed power from HVDCbipole to the Delhi grid. Provision has been made Eor 2 x315 MVA 4001220-kY transformers.

Ballabgarh: Extension to the proposed 400/220-kV substation atBallabgarh to connect the Muradnagar, Jaipur and Kanpurlines.

Karwalnagar: Extension to the proposed 400/220-kV substation atKarwalnagar to connect the Muradnagar line.

Jaipur: New substation to connect NTPC's Ballabgarh andKanpur-Agra lines. This substation would be connected tothe RSEB's 400-kV substation at Jaipur.

Panipat: Extension to the existing Panipat 400-kV substation ofBBMB to terminate the Muradnagar line.

These substations will be constructed in accordance with NTPC standards andpractices.l/

III. HVDC Transmission Line 2/

Voltage Selection

Tne voltage in HVDC links ranges between + 450-kV and + 600-kV. Volt-ages above or below these figures would require multi-condictor bundles eitherbecause of excessive losses (below + 450-kV) or excessive corona (above +600-kV).

1/ The salient features of the NTPC 400/220-AV substation have been describedin the Central Power Transmission Project SAR (Report No. 4293-IN) in Annex13, Attachment 2.

21. About 20,000 MW HVDC links are now in operation around the world; 45,000MW are expected for 1990. (Information provided at the "Conference Inter-nationale des Grands Reseaux Electriques" - CIGRE, Paris, September 1984.

-48-


The selected voltage for the Project (+ 500-kV) is based on theexperience in previous projects in operation or under construction in the worldas illustrated here below with some examples:

- Intermountain (USA) 830 km 1600 MW, 1600 A, + 500-kV- Itaipu (Brazil) 800 km 3150 MW, 2600 A, + 600-kV- NR 2 (Canada) 800 km 2000 MW, 2000 A, + 500-kV- NR 1 (Canada) 800 km 1690 MW, 1800 A, + 500-kV- Inga-Shaba (Zaire) 1800 km 1120 MW, 1120 A, * 500-kY

Line Coafiguration

Bipriar lines with a horizontal configuration.

Towers

Self-supporting latticed steel towers, fabricated from structural steelangle sections will be used. All the components of the towers would be h.--dipgalvarised. Normally, the foilowing four types of towers would be used: (0) 'A'type suspension straight run tangent towers for up to 2 degrees angle of devia-tiov; (Hi) 'B' type tension towers for angles of deviation in the line up to 15degrees, also to be used as anticascading tower; (iii) 'C' type tension towersfor angles of deviation in the line up to 30 degrees; and (iv) 'D' type tensiontowers for angles of deviation in the line up to 60 degrees and also as dead-end(terminal) towers.

In addition, special towers and foundations are envisaged for majorriver and power line crossings and places where the right of way is restrictedor the terrain is particularLy difficult. The design of these towers and foun-dations would be finalized after undertaking detailed soiL investigation androute survey.

Conductor

Quadruple bundle of ACSR (Aluminum 4214.57mm + Steel 712.54mm) would beused per pole to provide a power transfer capability of up to 1500 MW.

Earthwire and Lightning Protection

Two galvanized steel earthwire of size 713.66mm would be used forshielding.

-49-ANNEX 3.1Page 4 of 6

Grounding

The tower footing resistance would be kept below 10 ohms so that themaximu= number of flash overs do not exceed 2 per year. Standard and radialcounterpoises would be used whenver applicable to provide a tower footing resis-tance of 10 ohms.

InsuLator dnd Hardware

Suspension string would nave a 'V' configuration. The whole assemblywould be designed for the load corresponding to an ultimate tension of 160-kV ineach subconductor i.e., a total of 640-kV. Anchor shackles would be designed toaccommodate tower strain plates. High strength antifog DC disc insulators of160-kV electricaL and mechanical strength would be used. The number of discs ina 'V' string assembly would be 2 x 38 (320 x 170 mm). A zinc sleeve would bepovided at the cement pin interface of the disc. To protect the pin of theinsulator from corrosion. Other regulations, procedures and practices will be asper the prevailing Indian practices and standards for EHV lines as given atSection I above.

HVDC Terminals

The basic one line diagram of the HVDC convertor stations is enclosedas Attachment 2. The terminal at Rihand would be connected by cwo 400-kV ACfeeders to the 400-kV AC substation at Rihand power station and the terminalat Delhi by two 400-kV AC feeders to ti 400-kV AC substation at Muradnagar.The salient details of the HVDC terminal equipment are given below:

Converter Transformers

The converter transformers would be th'ree phases or single phase unitsappropriately connected. They would be designed to withstand the combined DCand AC stresses that would be subjected to while in operation. They would haveappropriate number of taps as well as an ade-uate tap range so as to ensuredesired flexibility in the operation of the bipole.

Thyristor Valves

The EVDC converter stations would comprise one 12 pulse valve group perpole which would be initially equipped for a nominal continuous rating of 1000MW in bipolar operation but which would be upgradable at a later date to 1500MW. The multiple valve units would be water-cooled and will be the indoor airinsulated type. They would be of modular design comprising different thyristorlevels of identical construction. They will be triggered by opticallyinstigated electrical firing, separately light triggered thyristor firing ordirect optical firing. Each valve would be protected against overLoad, overvoltage, and other variations in current and voltage.

-50-


Smoothing Reactor

The DC smoothing reactors would be designed for limiting the over cur-rent phenomena during the invertor voltage collapse and for smoothing the DCvoltage/current during normal operations.

Surge Arrestors

The AC and DC surge arrestors would be of the metal oxide type becauseit has generally been established that metaL oxide surge arrestors with theirdefinitive characteristics are more appropriate for DC applications. Hence,parts of the AC system contiguous to the HVDC systems (e.g. 400-kV AC coimnutat-ing bus) would also be equipped with this type of arrestor. Each arrestor wouldhave discharge characteristics and ratings as is required for that particuLarapplication. The arrestors would be designed to give consistent protection totheir associated equipment against over voltages produced by lighting, switch-ing, internal or external faults and other system disturbances. Each arrestorwould be provided with a surge counter and Leakage current meter for monitoringpurposes.

AC Harmonic Filters

AC harmonic filters would be used to filter out undesirable characteris-tics and non-characteristic harmonics generated as a result of the conversionprocess and minimize their entry into the AC network thereby minimizing overvoltages, resonance effects and electromagnetic noise generation and inter-ference. The AC harmonic filter would also supply most of the reactive energyrequired by the convertor equipment. The filters would comprise of linear shuntcapacitors and reactors arranged in suitable groups and banks.

DC Filters

DC filters would be used to reduce the noise on the DC line generatedas a result of the harmonics generated during the conversion process. Theywould be composed of capacitor, resistor and reactor elements.

DC Measuring Devices

DC voltage measuring devices would be of the resistor divider type withan accuracy of not less than 1%. The resistors would be of the metal film type,deposited on a suitable ceramic base. DC current measuring devices would be ofthe transductor type and wouLd have an accuracy of not less than + 2% for up tonormal full load current.

-51-


400-kV AC Switchgear

All AC side equipment would be the 400-kV AC equipment as described atSection rIi above.

Auxiliary Power

Adequate power supplies from the 11-kV boards at Rihand power stationand 11/6.6-kV boards at Muradnagar station, would be provided. In addition allprotective interlocks, relays, controls and critical illumination would operateon 220-V/48-V DC fed by battery banks and charges. A standby diesel generatorfor running fire pumps, illumination lamps etc., in an emergency would beinstalled.

Buildings

All buildings would be as per the relevant Indian Building codes.However, the main convertor building housing the EVDC valves would have a spe-cial electro-magnetic screen to reduce Radio Interference as well as electros-tatic shielding to limit the exposure of personnel to specified electric fieldstrengths.

Service Facilities

Service facilities such as water treatment, sewerage, sanitation,purification, fire fighting, oil filtration and fire fighting and repairworkshops would generally as per the service facilities described at SectionII above.

INDIARIHAND POWER TRANSMISSION PROJECT

Nouhem Region EWV Grid(Single Line Diagrom)

APAAAti AlAt 1 V (AA/ M - t \ jtWjjja / ttAt5APAt~~~~~~~~(5 MA

I~~~~~~~~~~~~~~~~~~~~~~I.

tWPAI /IA

/~~~~~~~~~~~~~~~~~~~~t hY Pkvr

I.tm& .

IOU~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~-

(l e/4', ; riaSI

Wtl/ > t92 Stb~~~~~~~~~~~~4DWtlc

(1a111~~~~~~~~~~~~~~~~~~~( tt,w = 4 kbv*dtN

WMXX,tcttu

INDIARIHAND POWER TRANSMISSION PROJECT

HVDC System - Deslgn Dagram

DELHI TERMINAL RIHAND TERMINAL

NlistoI Smoothiji Snoowihng ltrIiysl rot"VnIvos ru?aclIs lJectoskV Vv 40VAC R

400kVaAmCS SAlche tC Inias DC Itie SnnNchei hanVuimee

W~t Bw - 26i0

bgr ln

I..'

-54- AMNNE 3.2

RIlUD PWU K RANSSIOWPROJECT COST SWUZT

(Rupee Million) (USS Nillion) Z TotalZ Foreign Base

Local Foreisn Total Local Foreign Total Cxebause Costa

A. 400 KV Lines

Rihand-Kanpur 317.9 119.9 437.8 26.5 10.0 36.5 27 7Riband-Singrauli 60.6 24.2 81.8 5.0 2.0 7.1 29 IRiband-Riband 6.9 2.9 9.8 0.6 0.2 0.8 29 0Kanpur-Delhi 323.9 123.1 47.0 27.0 10.3 37.3 28 7Kanupr-Kanpur 22.7 9.4 32.1 1.9 0.8 2.7 29 1Delbi-Jaipur 245.0 90.3 335.3 20.4 7.5 27.9 27 5Delhi-Panipat 91.5 28.6 120.1 7.6 2.4 10.0 24 2Jaipur-Jaipur 22.7 9.4 32.1 1.9 0.8 2.7 29 1

Sub-total 400 KV Lines 1.091.2 407.8 1,499.0 90.9 34.0 124.9 27 24

B. 400 KV Substations

Singrauli 11.6 1.5 13.1 1.0 0.1 1.1 12 0Rihand 12.3 1.6 13.9 1.0 0.1 1.2 12 0Delhi 213.9 21.6 235.5 17.8 1.8 19.6 9 4Kanpur 316.7 35.8 352.5 26.4 3.0 29.4 10 6Jaipur (WIMC) 148.3 14.1 162.4 12.4 1.2 13.5 9 3Panipat 32.3 4.0 36.3 2.7 0.3 3.0 11 1Jaipur (USEB) 33.8 4.1 37.9 2.8 0.3 3.2 11 1

Sub-total 400 XK Substations 768.8 82.8 851.6 64.1 6.9 71.0 10 14

C. PVDC Facilities

DC Line (Riband-Delbi) 661.9 302.1 964.0 55.2 25.2 80.3 31 15AC Substations (Riband & Delhi) 212.9 57.3 270.2 17.7 4.8 22.5 21 4KlDC Terminals (Rihand & Delhi) 785.2 1,464.8 2.250.0 65.4 122.1 187.5 65 36

Sub-total IVDC Facilities 1,660.0 1,824.2 3.484.2 138.3 152.0 290.4 52 55

D. Consultancy

Project Consultaucy - 33.0 33.0 - 2.8 2.8 100 1Study - 22.0 22.0 - 1.8 1.8 100 0

Sub-total Consultancy - 55.0 55.0 - 4.6 4.6 100 1

E. Knaineerina and Administration 390.1 - 390.1 32.5 - 32.6 - 6

Total Baseline Comts 3,910.2 2,369.7 6,279.9 325.8 197.5 523.3 38 100

Physical Contingencies 202.6 115.7 318.4 16.9 9.6 26.5 36 5Price Contingencies 721.6 67.4 1.392.0 60.1 55.9 116.1 48 22

Total Project Costs 4,834.4 3.155.9 7,990.3 402.9 263.0 665.9 39 127_a m . _ ___-

INDIARIHAND POWER TRANSMISSION PROJECTNallonal Thermnal Power Co,poIatlon Ltd.

Implemenation Schedule

AC [M rI 13 U191 MI9S 1 9|_~~~~~~~uf 2 1tg I 1 12 1 13 4 II ii I 011 I 1 III I 041 ,t III 1 141 III1 14l stl tI 1 141 r t 0 1 121 1 13l1 4

ftwo~ rAh~~~~~~;~ ,c,majwtd arI Xrq AC t4MCCInes/c 1owvrEmctbn& flio /. R1? hlaC fg|i

5c, s lands a Qdw _S & _Slb Stvt F e, dOfo k* rcn I &h / )e CO'

I?'Wd~~~~~*IGflPJAI t~~~~~~~~~& lc~~~~vErocIa,JS,r ~~ ~ ACtw4WCCMhAmi Doc_ 8 _ F. _ _ -

WPM 5MfLA7ONt Spocl c a a F_ur_____w_Fcl__ .1 IJY 7 0CCIVSI4C 1 sa |

LIUuWG * taEdsI I O**e& 7 R0_1 II74TIhfj;A*VGQ,AN1PA SW$ to Kw a . bwg Skt rm k"=hon 100a [ vtn na s Cmbrgo m ;ln w mCwAi

131CIIOIAS S*Omwv v 1 4(

xtlOCCIKM~~~~~~~~~$S 10(wo aft ^. io & I wYbCd fra1eand Ax R&V& ;(C IEr cln&Sb) rfi =_ I WMLAMMIEDs.S c I^ eD&V." Stu KGa db _ rv0xAB

_ 0C SYSTEM SCCtur htg I

I~IWdDNtA~d~NAG$J ToKid EI:bUa Cbr tIf xh-ad. _ b_It rDAIMIDH - -S, -- --ww a&o oftwF -0k (c hiksIv-&hq{l rA*M Cotto _. 1A-i r I J

__ I RIt I___I t1 C>del D&OJ * CMIzfi& I Comm

Wald l*o- 6R0

I|wWCA

~1 . ftoao m C-1-oftif

-56-

ANNEX 3.4

INDIA

RIHAND POWER TRANSMISSION

Estimated Schedule of Disbursement

IBRD FiscaL Year ---------------Disbursements----------------…and Half-Year Cumulative US$ Million Equivalent X Undisbursed

1986

December 1985 12.0 95.2june 1986 23.0 91.0

1987

December 1986 53.5 78.6June 1987 87.5 65.0

1988

December 1987 125.5 49.8June 1988 168.5 32.6

1989

December 1988 187.5 25.0June 1989 213.5 14.6

1990

December 1989 250.0 -

00101W. 30630A0.940 CWPAT IS LINOIEI

Rime05 muR 13mi031K0 POOJCI

103Ml0 01.0*0A015 200 3144.2 t0.s 097.5 M9.4 003.3 030.0 059.5 440.0i 272.9 100 00 00 0000.0.0 0.0 0.0 0.0 0,0 0.0 .00m4U21025 OILS0 0.2 02.5 1410.0 114.1 149.5 31.7 50.0 0.0 0.0 0.00 0.:0 0.0 0.0 0. 0.0 0.0 0.0 0.0 0.0 0.0

I K 01.9 0.0 0.0 0.0 0.0 00. 44.3 25.2 0.0 0.0 0.0 0.0 0.0 0.4 0.00. 0.0 0.0 0.0 0.0 0.0TOTAL. 3741.1 00.0 M0.& 114.0 131.0 047.3 741.5 495. 2?1.9 10.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 '.0 0.0

10VA0 00 .S0 A011*1 2t0 0500.0 0.0 0.0 0.0 527.3 1510. 1012.5 In..0 250.0 207.4 054.4 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 I'D310100M 500 0023.7 0.0 0.0 0.0 0.0 0.0 454.2 504.0 525.3 2157.4 I0,10. 1002.4 0204.0 756.0 0.0 0.0 o.o 0.0 0.0 0.0 0.0

13006eso0020 2034.0I 0.0 0.0 0.0 0.0 0.0 30.2 203.0 410.? 504. 1 949.1 303.3 11.6 0.0 0.0 0.0 0.01 0.0 0.0 0.0 0.0IK 304.0 0.0 0.0 0.0 ID l 0.0 0.0 0.0 0.0 4.l.0 b.1 0152.6 71.0 0,0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

T0OTAL 12271.1 0.0 0.0 0.0 121.1 014. 441.9 949.2 0234.4 2030.2 1051.3 2249.0 1450.0 251.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0A01U011101001 .500 03119.1 0.4 0.0 0.0 0.0 0.0 0.0 494.2 500.0 2024.9 2594.0 3305.? 250. 4 10992.4 0.0 00 .0 0.0 0.0 0.0 0.0

IC 0044.3 ~~~~ ~~0.0 0.0 0.0 0.0 0.0 0.0 3.3 04.4 5. 5 INA1. 354.5 500.9 011.7 0.0 0. 0.0 0,0 00 0, .100000 04020.0 0.0 0.0 0.0 0.0 0.0 0.0 104.1 594.1 2M0. 2232.9 3140.2 2001,3 2020.0 0.0 0.0 0.0 0.0 0.00 0.0 S0.0

~~W0M:100f0W 200~~~n 024441.31 0.0 0.0 0.0 0.0 0.0 0.0 9.0 2.2 A0. 0 711.1 944.7 2002.9 1455. 0 2410.0 2221.2 02110.4 .6. . .000059010053 ~~~~2440.0 0.0 0,0 0.0 0.0 0.0 0.0 0,0 0,0 19.3 M4.3 934.5 349.9 340.0 143.0 0.0 0.0 0.0 0.0 0,0 0.0

I K 612.5 00 0.0 0.0 I 0.0 0.0 0.0 0,0 0.0 0.0 0.0 0.0 0.0 5.1I 214. 344. 1 135.5 0.0 0. . .000100. 0~~~~~~~~~~~ ~~~~ ~~~~ ~~~~ ~~~~ ~~~~ ~~53100.3 0.0 0.0 0.0 0.0 0.0 0.0 0.0 1.2 19.3 901.4 07E.2 2310.01 1590.7 3001. 2543.1 1314.21 . . . .

ChuIL RM 13 M03 N A01:11 0132.0 0.0 0.3 0.0 0.0 0.0 0.0 0.0 0.0 02.0 040.0 343.0 320.0 001.0 204.0 0.0 0.0 0.0 0.0 0.0 0.0OK 33.3 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 00.0 .0 0. 01 00 0.0 0.0 0.0 0.0 0.0 0.0

olOtAL 0104.61 0.0 0.0 0.0 0.0 0.0 0.0 0.0 00 020 000 34,0 3351. 1051 20. 0.0 0.0 0.0 0.0 0.0 0.03RIM" 73ANS10110111Wfun 99. 3 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 200.4 09,09.3 0750.2 2302.2 900. 4 049.4 0.0 0.0 0.0 0.0 4.0 0.0

I K 324.4 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0. 104,7 53. 143.7 203.3 0.0 0,0 0.0 0.0 0.0 0.0 0.0101TA. 10304.9 0.4 0.0 0.0 0.0 0.0 0.0 0.0 0.0 20 7.0 09I24.0 1000.4 22I".9 1004.1 409.0 0.0 0.0 0,0 0,0 0.0 0.0

IDENIFIED NEI M2I11 100K 540 4199. 4 0.0 0.0 0.0 0.0 0.0 0.0 0.0 4,0 0.0 0.0 490. 5 500.4 203.11 4213.9 4599.4 0224. 353 70. 505 29.13000100510P 00099~it.0I 0.0 0.0 el0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 20.3 200.3 000b1. 0203.3 0J04.3 23.2 21444.5 2570.5 1504.1 370.3

1 K 4733.9 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0,0 0.0 0.0 0.0 435.0 0293. 0W3. 0224.3I010AL 0133.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 121.3 1662.1 4491.4 5441.2 NW4. 1 30249.5 02495.4 00113. 39014.0 339. 5

7501.1114010611 1A110W100103 200 11023.0 20.3 091.0 29.4 144.10 33.0 322.0 620.) 503.5 401.4 044,1 944.1 2000.9 2055.0 2070.0 20171. 0231.4 0.0 0.0 0.0 0.331A1IM 540 419M15. 0.0 0.0 0.0 0.0 0.0 454.2 12202.3 0005.4 3044.5 0545.21 51194.4 4310.1 5029.9 4011.9 455.4 3 1224. 3 9395.13 7303.7 5100.51 24941.9

IRMPNIOUO 23109.3 0.2 02.5 if.4 0214.1 049.3 40.9 1333.0 411,1 534.0 32101. 3 3230.3 3420.4 3140.5 2244.9 0904.3 2023.2 2444. 5 2514.5 1504.0 014.131 K 7455.0 0.0 0.0 0.0 0.0 064. 44.1 33.5 04.4 54. 279.9 505.1 544.2y 305.1 294.0 34.7 21 5.5 035.4 0293.5 000.5 0224.3

000. 022940.4 00.0 209.4 344.0 3M0.0I 0001. 10390.4 2049.5 21001.2 4490.5, 1905.0 100410.3 2050.6 11504.1 9400.4 0110l.5 11411.0 HI4S. 4 00033.7 1 3014, 3491.5

095147001N M 0977-94 0917 0976 0979 093 09301 0192 933 09314 0915 090 211 011 JIM 09" 1990 1, 1990 092 09l3 09941 099 1990

ROAM150:301ATI0 200 4024. 0 0.0 05.5 200.5 302.1 432.4 1122.0 912.4 403.0 340.0 A 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0tRAM "I 0 0.0 0.0 0.0 31 15? 3 116.1 110.3 131.1 274.7 0.4 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.00100 K100 900.0 0.0 0.0 0.0 30.4O 051. 010.0 25.5 03. I 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0. 0.

10100. 5031.0 0.0 05.5 200.5 334.3 19. 9 2302.6 100111.41 530.3 W0.3 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

KENA 001,81ATI 500 01224.5 0.0 0.0 0.0 0.0 0.0 3,5 405.4 905.4 0447.0 3409.7 29100.3 0350.9 0025.0 45. 7 0.. 9.0 0.0 0.0 0.4 0,07310002030 0543.3 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 42.0 501.0 455.3 414,0 01.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

OK 0~~~~~~270.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 00 03 00 226 433 491 053 00 '. . . . .00100 253. . . 0.0 .0 .0 .5 4.4 905.4 05 090 3914,1 3423.4 2000.2 0543.3 60.".0 00 0.I. 0. 0.0

VIM20904.01411AN 200 00337.3 0. 0.0 0.0 0.0 0.0 0.0 152.1 341.9 903.1 0433.2 202. 0 0090.9 0900.3 0039.5 112.4 0.0 0.0 0.0 0.0 0.0101i 3303.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 02.0 40.0 03.0 0015.3 500.7 141.3 0.0 .1. 0.0 0.0 0.0 0.0 .[K00OO 294.4I 0.0 0.0 0.0 0.0 0.0 0. 0 0.3 32.3 400. 03.3 9.2 234.3 00. 3 32.y I. 0 0.0 0.0 0.0 0.0 .

ODIN. 04020.3 0. 0 0.0 0.0 0.0 0,0 0.0 0 53.01 420.? 0449.0 2070.5 30 971. 2a86.9 2239.9 047.2 732.4 0.0 0.0 0. 0.0 0.0

cow. unuou1 1473,1 A.. 0.0 0.0 0.0 0.0 0.0 0.0 0.0 04.0 093.9 460,9 392.1 042.0 2401.5 0.0 I. . 0 0 .IKI 020.4 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 4.0 19.41 41.4 40.2 15.1 .13 A-I A-,.3 37. I3.3 0

00371. 2000.0 0.0 0.0 0.0 0.0 0.0, 0,0 0.0 0.0 04.0 093.9 444. 402.0 035.1 323.1 75.1I 79.3 33.0 0.6, 01.3 31. 3 io0

I0EIFI1 03 m 11023030 200 04472.13 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 1.4 70.7 033.5 0000.2 2347.3 3024.1 3142,1 ZIU4. 3 0457.00I0 50 49449.2 0.0 0.0 0.0 0.0 #0., 0.0 0.0 0.0 00 1 0.0 100. 4 590.2 235. 0 3300.1 4434. 4 4237.7 3445.1 1090.6 7430.4 473.TJIOIO 10329.1 0.0 0.0 0.0 0.0 0. 0.0 0.0 0.0 0.0 0.0 0.0 056.0 0107.4 1502.9 H400.? 4445.2 3053.5 0033.5 0340.4 077.

____ JK~~~~T 0911.11 0.0 9.0 0.0 0.0 O.: 0.0 0.0 0.0 0.0 0.0 00 0.0 0.0 0.0 0.0 0.0 34.5 420.1 7100,0 7114 013700 54432.3 0. 0.0 0.0' 0.0 0.0 0.0 0.0 0.0 0.0 0.0 in1.4 149.0A 4094.0 5037.0 0020.1.0 030001.1 0124.4 12432,3 12044.7 44125.1

tool.11111 mikA 1 1 01 30o 431.0 0021. 1 3 is'O ,' j17 01: $1~ jj3j0 0044.0 267 3124.7 5042.4 292.3 041.204I~~~~~ 05.5 230.1 302.1 4 0014.~~~~~~~~~~~~~~7 JJ44 44i.I 5.1 7,1 404& .10. 0.0 0.0 3.0 05. I 0 0. 0. 000 05 00i7Y.3401 4371 11J i?. 0?:" It ""4, 1 1 0.0 0. . 0 01 A¶ IA .1 11 i. 9. 6 0. 230.7 15.1 19.2 1 I ,I. I 3.A

TOTAL 020723.4 0.0 01.5 230. 5 334.3 7399 032.3 0004.9 0934.9 3109.9 0000.1 ?1995, 0650.31 0003.0 6439.5 02005.9 03043.0 0510. 402031.4 02032.0 7071.9

3011W1. Tank rPr moaoim uoiou

SOUTIUN Kill00

if 114110K 0 2077.0 2911 20l3 1920 201 1002 2902 2033 2944 2935 MI34 I"31 lie3 2it" i9t0 2092 I9 1993 1994 291 20014

041WuWb 1:151412020 200 2120.3 0.0 0.0 50.0 3463.2 344.4 2000.3 144.11 1.4 220. 121.4 0. 00 0.0 0. .0 0.0 0.0 0.0 0.0 0.0imosoissim t 0s. .o . 0.0 #0 3.4 33.5 2 I.4 0.0 232.0 430.1 242.2 2.2 0.0 0.0 00 .0 00 0.0 0.0 0.0 0.0I C 222.0 0. 0 0.0 0.0 0.0 0.0 0.0 12.0 201., 40.3 32.1 . . . .0.0 0.0 0. 0.0 0.0 0.0

lOIN. 4320.4 0.0 0.0 10.0 340.4 382.0 2243.1 3004.4 2110.2 122.2 322.2 :1.2 0.0 0.0 0.0 0.:0 10.0 10.0 0.0 0.0: 0.0AAIW5022 21S1141210S 54O 11012.3 0,0 0.0 0.0 0.0 0.0 0.0 0.0 700.46 0P0.0 2240.7 3012.2 MU. 123344 159. 0 340.2I 0.0 0.0 0.0 0.0 0.0

100052125110 2100.2 0.0 0.4 0.0 0.0 0.0 0.0 0.0 0.0 11.5 S14.5 2163.3 303.4 253.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0I K 12262.2 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 37.4 325.3 253.4 202.9 02.9 0.0 0.0 0.0 0.0 0.0

lOIN. 21323.5 0.0 0.0 0.0 0.0 0,0 0.0 0.0 700,4 01.2 2511.2 0243,2 3309.0 2242. 1030.0 013.2 0.0 0.0 0.0 0.0 0I0CINIONA 20M25021122:l0 3123.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.1 40.0 723.2 71392 .1 443.5 66.0 44.4 0.0 0,0 0.0 0,0 0.0 0.0

C 2015.3 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 40.3 54.2 , 0.0 0.0 0.00. 00 00I10IN. 3229.3 . 0.0 0.0 0.0 0.0 0.0 0.0 4. 40.0I 121.1 ?13.2 022.0 Me0~ 44.4 0.0 0.0 0. 0. 0.0 0.0

2E31211F ItsI PIOJI: S120 500 23502.41 0.0 0.0 0.0 0.0 0.0 0.0 4.0 0. 0. 0.0 0.0 710.0 442:3 2244.4 2112.4 310.2 I 1744.0 3021.2 2033.5 3420.2130A502S1400 U112.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 21. 243,4 440.3 2703.0 25510. 1 221.3 3I3 5 0.0 0.0 0.0

I2K 338.4 0.0 0.0 0.0 0.0 0.0 0.0 0.0 M. . 0.0 0.0 0.I.0 00 0.0 0.0 0.0 30.3 71.4 M2.2I23000 20525.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 21.:1 2024.1 02002.1 9037o.4 4432.7 1024.24 000.2 30345.0 2005.2 3054.3

101 .1a01210 RIM STI,:5 012 M0 2149. 0.0 0.0l 54.0 W6.? 504.2 2003.3 2101.0 I4,.4 320.4 2 47.4& 0.0 0.0 0.0 0. 0 0.0 0.0 0.0 0.0 0.0 0.011411021 500 35453.7 0.0 0.0 0.0 0.0 0.0 0.0 0.0 700.4 191.4 240,3 30222 3402.2 2120,0 2100.4 3232.5 3120.1 3744.4 3017.2 2133.5 3424.2

TIOIdISSIOU 22243.1 0.0 0.0 0.0 3.4 3o.15 255.4 200.0 2M. 7 544.0 2203.1 2028.2 2520.5 2206.3 2051.4 211501.3 2 211.3) 322.5 0.0 0.0 0.0IoC 1939.2I 0.0 0.0 0.0 0.0 0.0 0.0 52.0 207.3 A0. 32.5 01.4 304. 4 10.7 202.0 02.0 0.0 0.0 30.0 72.4 221.

20101. 54324.2 0.0 0.0 50.0 344. 302.0 12243.1 2004.4 1003.12744.0 3424.5 503.1. 1304.3 3952.0 4130.0 42041.0 5024.2 2090.2 3054.0 200.2 284.

of 1200223 N M2971704 1071 1079 19O 2030 21921 232 2103 2004 29011 20M 2017 I9M 2930 2990 2092 2002 1003 200 2105 2904 EFA401A 2112ATION1 200 594. 1 0.0 0.0 3.0 09.0 343.4 405.0 420.4 1250.1 2221.0 22201.2 194.3 0.0 0.0 0.0 0.0 0.0 0.0 C.0 0.0 0.0

2ft003221IM 02414 0.0 0.0 0.0 0.4 0.4 4.0 04.0 234.2 225.0 273.4 203.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0. 0.0IC443K. 0.0 0.0 0.0 0.0 0.0 0.0 0.0 33.0 32.3 0.0 0.0 0.0 0.0 0.0 0,0 0. . . .

10200. 445.4 0.0 0.0 3.1 94.4 344.0 500.2 704.5 2015.0 241.10 2423.2 2093.2 0.0 0.0 0.0 0.0 0.0 0.0 0.0 10.0 0.0

701.000 21:1002025 500 20040.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 2.3 30.5 400.0 2234.0 001.0 2350.7 2523.4 2035.4 742.0 502.0 0.0 0.0 0.0IRNMISSIM lo20225 0.0 0.0 0.0 0.0 0.0 0.0 0.0 2.4 it. 50.4I 332.2 324.0 203.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

IK 404.4 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0, 0.0 0.0 0.0 33.0 197.0 320.2 241.2 0,0 0.0 0. 0.010141. 23300.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 2.0 02.0 000. 2025.2 2324.0 2400.4 2722.5 2252. 1004,0 562.0 0.0 0.0 0.0

70N 1010 22211=2i s0o 5623.3 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 64.4 2003 902.7 042.8 1242.5 2024.1t 022.7 372.4 0.0 0.0 .0.0IOC 444.1 0. .0 0.0al 0.0 4. 0.0 0.0 0.0 0 .0OI 0.0 0.0 0.0 4.0 30. 241.2 201.0* 201.1 0.0 0.0 0.0

1001. 4410. 0.0 0.0 0.0 0.0 4.0 0.0 0.0 0.0 0.0 64.4 3011.3 Obl.7 142.0 2401.2 2243.1 2200.2 542.2 0.0 0.0 0.0

lhMALB0ON121A412 220 2 3445. 4 0.0 0.0 0.0 0.0 0.0 0.0 0.0 25.0 50.0 4855 002.1 2004.4 2124.0 21092.09 2324.3 2274.0 0.0 0.0 0.0 0.0INAMISS1520 280.2 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 20.2 25.0 22213.4 12243.3 201. 0.0 0.0 0.0 0.0 0.0 0.0 0.0

I K 022.4 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 17.0 214.0 377.7 202.0 0.0 0.0 0.0 0.010241. 2475.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 25.0 40.2 0110.15 2005.0 3241.7 3200.2 3200.0 2702,0 2320.1 0.0 0.0 0.0 0.0

2111512F0EV IE MPt0 jJ~ IE 500 42012.3 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.4 0.0 471.4 542.2 2742.1 3240.1 442.2 7003.0 9004.41 9940.0 20110.3 20740,4IV" ION ISPI S02.3I 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 00. 1004.4 1222.2 2254.2 2722.2 1202.3 2224.0 2110.1 2010.0 2421.1

I C 2302.5 0.0 0.0 0.0 0.0 0.0 m 0.0 0 .0 0.0 0.0 0.0 0. .0 0.0 0.0 9.0 0.0 0.0 34.5 310.2 002.8101AL 30:195.2 0.0 0.0 0.0 0,0 0.0 0.0 0.0 0.0 0.0 0.0 744.2 2455.7 3869,8 5024.0 8220.3 0631.2 22230. 220MA 23027.4 2323.0

101LEA117K 0101400 20120i 20032.2 0.0 0.0 3.1 14.0 343.04 405.0 420.4 2200.7 2207.0 2003.1 I2130,0 2004.4 29124.0 230.0 2324.3 12174.1 0.0 0. 00 0001113 0071404 . 0.0 0.0 0.0 0.0 0.0 0.0 2.3 HIS.5354.3 2045.1 2522.4 5044.2 1202.0 0344.2I 046N4 10120.0 01440 2034. 04.

10001221021 23112.4 0.0 0.0 0.0 0.4 0.4 4.1 14.0 137.1 210.5 2040.0 2234. 2343.0 2165.4 2154.2 2222.1 2321.3 2224.0 2010.1 2702.9 2421.11O £143. 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 33.0 32.3 0.0, 0.0 220.0 522.0 345.2 034.5 W31.3 14.5 310. 902.3

10102. 223M5.7 0.0 0.0 3.3 94.4 3414.0 500.1 104.5 2323.7 2520.6 3453.3 1030.4 61090.0 20002.5 23200.1 4210.4 22325.0 22322.1 2232.2 23021.4 137$0.9

P0 31A412M097-6 06224 2121 Ills 20lt 203 21211 203 2033 2014 2035 l 2004 1 I 203 203 2900 2002 2092 1903 2004 290 290 pIfIAL. 0182 OlAliP 2001220 70140.5 20.8 222.4 410.7 1544.0 2206.4 3444.3 4070.3 335.6 3223.2 4240.2 4233.5 400. 7420.0 3035.9 4341.5 41112.2 3224.7 3242.4 25142.3 2427.31

31*12WON 140 245335.7 0.0 0.0 0.0 0.0 0.0 427 2.7 2722.1 550. 20IP10. 24447.2 122135.7 27232.4 23033.5 251634.4 24012.5 32404.4 27302.7 2400.7 21323. 3 04.1 0.2 22.5 143.4 250.3 345.7 425.5 Jill.5 2302.4 0124.12 04vio2l 7 0050 84.100. 95,1.0 111710.51 2232.7 5141.4 2072.5 p27203.0 0.0 0.0 0.0 8.-,24.4 s. ' 01 3041.2 3262.2

1,131. AC1.1977144 .0 AN~.~1 TA: ~M: 32J .4 : t47: 25: . l?:y ..: I - ': "1 0. .2 10100.~~~~~lti 422022.0 22.0 225. 40. 3 2450.3 210. 4417.2 0234.1 720.0 21747.0 22170.0 29407.0 294.030.0 44.022.0 42222.0 425.0 V3943. 3134.0274.

IMUAIIVI 42202.0 22.0 234.2 935.4 2502.7 5212.2 000.3 05704.0 22040.0 30722.1 5400.2 41 041.0 224203.2212002.0 232040.2 22024.0 272430.3 325464.0 551123.0 33103243422011.0

INDIA

NATIOA IHERIIAL PWR CWORAION LINIIE).............................

RINHO POHER IRASYISSION PROJECt.................................

FIlNACI16 PLM

COWERIN F15lAL YEARS FY1977 IO FT 1996

(RUPEES HILLION)

*tggegg | tVSStsl amuiosBtl2as loasg xx ss: no IS 2 sr SSansW Saw egg go mag@gBWsU sls * mass *|soxg suntasJ naussoIS8l| % rare S *83CRE *|e88 wwllS:s5SWS sg3Xg

TOTAL 1977-96 ACTUAL ACTUAL ---------------------------------------- EROECED- -------------------------------------------------------FISCAL YEAR ENOING MARCH 515T US I NIL RS.NIL 1977-13 1984 1"5 t996 1997 19E 1969 1990 1991 1992 1993 1994 195 199t23 20122222assuses ag-awl 0 0 rare Iran ::II Is si::: : t: S:S:S:: a xstxx * I|wlsl ansxxgBBlszsaos as|tllsl*|ss$||sssalZlBltstt|gessaelws

SOURCE OF FUNDS.u'.uu.s.susas.mI

INTERNAL CASH BEWERAI IN 19.929 239,131 lea 777 2,021 3,402 4,133 5,969 8,937 12,413 17,179 22,792 20,751 35,75 43,ff5 52,7W......................

OING CAPITAL-DECREASE/UINCREASE) 11,476) 117,709) 702 1343) 11,222) 1532) (265) 173) (1,3551 (1,2811 11,6341 11,9481 (1,9521 (2,105) (2,343) 13,456)

LESS. DEBI SERYICE 17,935) (95,215) 1651 1221) (616) 1955) 11,356) 11,9961 (4,326) 16,249) (1,957) 19,557) 111,125) 113,193) 11t,5101 121,1291PRELININRY DEFERRED EIPENSES (3) 135) 135) (0) (0) 10) 10) (0) (0) t0) 10) 10) (0) 10) (0) 10)

CONTRIiUT1N" 10 INVESIMENT 10,514 126,172 790 213 183 1,915 2,512 3,909 3,256 4,953 7,6137 11,287 15,774 20,460 25,032 2i,201.......... ...........................

EI)TERA FINANCIN6

SNAR CAPITAL 14,419 173,026 11,910 4,204 9,159 13,369 16,673 13,177 19,239 13,294 25j603 26,799 15,699 0 0 0LOWT-TERN LOANS I 14,916 179,129 3,194 2,753 3,405 6,895 10,512 12,520 12,313 12,001 9,949 4,034 12,793 2b,019 35,473 29,157SNORT-IERHLOANS 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0LEISSH0:RT-TERH DEPOSITS (4,676) (56,1161 0 0 0 0 0 0 0 0 0 0 0 16,970) 122,636) 126,601

1OTAL SOURCE OF FUNDS 35,243 422,911 15,794 7,170 11,747 22,179 29,697 29,606 34,005 36,048 42,259 42,122 44,256 39,609 37,169 29,7433333:33333333rn33:3333 m..sovumz *3333333 maa...su uze-smuEm WS133333 u.aumass aeufsumsn mouamusa u333333 suuseWou WIDSIZs3u :21::::, :gz2zuuz XZEiama auag *3u3333sa 3nst

INWESTNENT REOUIRhENiS:

TOIAL INVESlTlEI REQUIREIENTS

CAPIrAL INVESTHENY PR06RAII(Including Interest during construttion) 55,243 422,911 15,794 7,170 11,747 22,179 29,697 29,606 34,006 36,049 42,259 42,122 41,256 39,608 37,869 29,743

I CNIRIIUIION To INVESiNENIJ[contribution to investment am the 2Iof average 3 year capital espinditure) 29.92 5.02 3.02 1.61 8.62 1.52 13,21 9.42 13.7Z 19.21 2.6.2 35.6K 51.71 6.1% 94.62 '

.................. ........................... ____ .....__..__

I/ Includes tolending of IDA Credits/IIRD Loans, Federal Reoublic of Geruany,OPEC, U.K., U.S.S.R. loano and other sources of co-f,nainirq.

NATIONAL THERMAL POWE'R CORPORATION LIMITED

CDMNIOIAOTED INCOME STATEMENT

COVERING OPERATION! P12993 THROUGH FY1996

(RUPEE! MILLION)

I : 2: :n:2:z:::22222 h:.:u.::::::::::::::uhuusnu~~~~~..fhu...........h....................... r-e... ...

ACTUAL ACTUAL.- --------------------- PROJECTED…......-----..................IOTALFISCAL TEAR ENDING MARCH lIST 1993 2984 2995 9296 2991 1999 1999 1990 ?992 2992 1993 2994 2995 1996 2993-96

POWER GEHEPATION II09 4267 9972 12299 25154 29574 21927 36956 47606 59222 72057 92557 94630 206162 588067LESG:AISIILL1ARI CONSUMPTION 15 432 981 1299 1510 1954 2495 3297 4041 4982 5900 6714 145% 3505 49157

(DIAL POVET' BALES (OVhd 1031 3935 7994 11697 23644 27720 25422 33159 43565 54242 £5151 75909 96979 97656 533492

SULk SUPPL0 TARIFF (PAISE PER AVId 372.30 36,45 42,37 47,96 50.60 56.02 60.20 63.92 67.95 73.07 71.36 92.34 97.60 93.22 76.92

OPERATING SALES REVENUE 334 2399 3393 5605 6904 9927 25305 22542 29602 39632 50405 62424 76297 92031 423695................... 2*2.22 232223 2*3 .2..3223. ........ 20233 ... S322*22232 22823323 022.2323 3322323222*2 2 2332233 32 22233 3332 X22 22223

OPEPATING ETPENSES: GENERATION

FUEL: NORTHERN REGION 245 365 595 752 845 2302 2044 2729 3722 5066 6466 7495 9357 9692 49594VISIORN REGION 0 1229 250 336 365 623 2269 2299 3005 35298 4250 5309 71223 9032 373122SOUTHERN REGION 0 122 225 463 589 639 995 2314 2099 2127 3299 3802 4592 5204 25192EASTERN FEVION 0 0 0 265 373 469 509 552 937 2055 3534 4906 6252 7477 27229

tOTAL FUEL 245 505 2070 2726 2t72 3033 4737 6963 9152 23376 17349 21512 26329 32505 .240063

OPE'ATITHS I MA1NTEHANCE: NORTHERN REGION 66 127 110 225 255 10 500 599 692 904 1222 1209 2302 2573 9739NCr:iRNl REGION 0 27 95 203 203 220 493 793 93/ 2029 1268 2411 2753 2025 20232FPI"FHERM RESGIN 0 2 96 220 222 222 275 270 345 377 442 599 689 639 4027EASTERN RE;TO0N 0 0 0 97 242 254 154 254 303 640 976 2295 2359 2830 6704

TOTAL 0Ir M 64 146 272 435 523 799 2322 1906 2266 2939 3707 14429 5202 5922 29'6122

DEFQECIATIDN: NORTHERN REGION 21 42 223 259 164 2RA 676 991 992 2250 2651 2964 2964 2297 12256AES'EGN REGION 0 I23 9! 244 144 144 2Ys 722 (000 2026 2244 2550 205 2620 22022SOUTHEPN RESGIN 0 122 73 266 271 272 171 356 502 629 627 844 2262 2262 6027142TEP REGION 0 0 0 a9 la, "l6 226 216 2216 669 2274 2800 2033 2373 9299

rOTAL DEPPEC'N 2 61 289 557 6&2 929 2357 2274 2709 3563 4793 6259 7214 9432 39906

TO-TAL t'ENEPIMIT JFERATIN W4 iENSES 223 719 2630 2709 3356 4650 7426 20943 24727 29978 25999 32099 38145 45759 209582

:RANSYISSIYI: OFtAlIA UiFENSES

O4'ERAl2TO5 N AINTEHAHCE I 22 52 77 138 309 349 tOt 525 599 135 922 923 4791DEPRECId 13N 0 2 I 12 24' 209 386 9bb 2021 2066 2395 (637 2934 2220 20670

TDTAL 1UNSFISSICH OPERATING EiPENGES 2 5 37 223 224 347 695 2255 2427 2592 1993 2372 2745 3043 25659

TOTAL 3tERATTWG I)PENIES 224 725 26&' 2412 3590 4797 8222 22191 24254 22469 27342 34461 42390 49802 224439.... ................. ssomes3*22*223 ........3322222 323332 33322332 5232:22*2 22 0zzz 2133022gess 22202222232: 32233223 32322321 23332122 11233232 23332222a

OPERATING INCOME (DUFPE INTERESI' 220 615 1716 2774 3324 4930 7294 9343 23449 29263 22563 27963 34907 42236 2199256.............................. M..... ........... 32 e2t: 2321:2: C2232s 122 2 2se 22… 12 22282 …msz -2 = 22ZsRz.- 222auz2 slzz

LEiSSTINIERESI ON 0045 454 459 792 2273 2279 3529 5076 6645 9005 9906 9932 122222 15994 29795 9545DEWUC INTERESI CAPIIALISED 389 239 266 323 845 2629 2552 2329 2392 749 743 2972 3068 3232 27464

NET INTEREST CHARGED TO OFERA'IOCNS aS 222 426 955 2334 12999 3525 5326 6624 9051 9069 10340 22926 26624 77531DEFERRED EAPENGEG WRITTEN OFF 9 5 5 16 0 0 0 0 0 0 0 0 0 0 35

NET EARNINGS 46 449 (095 2903 2990 3031 3469 402: 6324 20206 23474 27623 22982 25622 222640-:2 ::::::::ue-*~::: nn: n::::::n. .2 2..:…::: 2:::202 230202222222

AVERAGE NET RIlED ASSETS IN USE- AT HISTORICAL COST 2803 5999 23499 20592 2*249 39553 72033 999a3 229660 250926 292442 2243 262433 237320-AT REYALUED COST 27412 7075 26062 25062 32973 50226 93922 236990 172212 226244 296364 365054 434958 502222

RATIOS OR OPERATING PERFORMANCE:

OPERATING RATIO TIPER.EOPS. AS I OF DOER. REVT) 64.2% 52.72 49.31 50.5% 52.91 50.31 53.02 56.62 54.61 54.21 55.21 55.22 54.32 53.6%

RATE OF RETURNI ON HISTORICAL COST OF NET ASSETS 6.42 11.31 12.71 13.5% 22.7 122,5%120.11 9.41 22.31 22.01 20.7 1(2.21 13.32 14.72OWPEVALUED COST OF NET ASSETS 2.02 9.32 20.32 20.71 9.72 9.30 7.31 6.2.1 7.21 7.32 6.81 6.31 7.20 7.52

NATIONAL THERMAL POiER CORPORATION LIMITED

RIHAND POWER TRANSHISSION PROJECT

BALANCE SHEE1S

COVERING FISCAL YEARS FY2993 THROUGH FY l196

IWUEES 1ILLIONI

:~:::::::* ': =: :: :: 3*fa1za:s:::::::sz: r s ::: :::: :::::::3:3.3::3: *-:33333:33333:.hz.sS: w::333:33333333:::323:3333: 3333:33*333333s:::::st::::3:3333:fl33: 333:: 3:333s:333g::

ACTUAL ACTUAL ------------------- PROJECTED----------------------------------------------------------FISCAL YEAR ENDING MARCH 31S1 1983 1994 1995 I99t 19B? 1989 1999 1990 1991 1992 1993 1994 1995 199bS :S::2 : :3 : ::_3:3:=:=::333… : :: :: ::3: __ 3 *r==:w:::2::3333 3333fl::31:3:tl 333:223!3333 a:3333:3333::X5: :a:::::3::333 :a :::: *@33333:3 S3 3s:g:::3::uuu:ug:::z::s::

ASSETIS

GROSS FIRED ASSETS IN LVPERATION 3036 9197 19424 21317 31193 52774 96934 115319 141398 189209 235246 276274 318090 345148LESS:DEPRECIAON 68 170 475 1103 1912 2950 4693 7833 11563 16192 22380 30175 39323 49975

NET FIXED ASSETS IN OPERATION 2969 9027 17949 23214 2928G 49924 92241 107485 129935 172016 212866 246099 278767 295873WOKP-IN-PROGRESS 12758 13767 16297 32573 55394 63419 54067 71731 57910 83222 80440 79020 75073 77163

IOIAL FIXED ASSETS 15726 22794 34236 55787 84675 113243 246308 179216 217745 255239 293306 325119 353840 37303b

CURRENI ASSETS:CASH 90 281 37 bO 76 108 174 248 340 461 593 731 993 2049RECEIVABLES 218 842 564 934 1151 1655 2351 3590 4934 6605 8401 10404 12700 15173INYENTORIES 155 424 229 379 470 710 1222 2668 2096 2752 3454 4170 4862 5615LOANS & ADVANCES 269 228 51 75 90 122 178 242 325 427 537 659 799 949SHORI-TERN DEPOSITS LOANS 'O 0 0 O) 0 0 0 O 0 0 0 6970 29506 56116OTHER CURRENT ASSEIS B B 4 4 4 4 4 4 4 4 4 4 4 4

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

TOTAL CURRENI ASSEIS 739 1793 995 1452 1791 2599 4129 5752 7699 10249 12989 22838 49754 78905

DEFERRED EIPENSES 26 21 I6 0 0 0 0 0 0 0 0 0 0 0

TOTAL ASSETS 26491 24598 35137 57239 96466 115942 150437 184968 225444 265487 306295 347957 402594 451942

EGlDITY & LIABILIIIES=:3:5::3:3::3 r:: :3|:

EOUITI:

SHARE CAPITAL ISSUED 11365 15668 241?3 31542 54215 67392 96631 104925 130529 157327 173026 173026 173026 173026SHARE DEPOSITS 445 346RETAINED EARNINGS 46 495 1590 3393 5383 9414 12083 16110 22934 33040 46514 64137 96029 121640

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

IDTAL ERU!It 1185b 16509 25763 4093S5 59599 75806 98714 121035 153462 190367 219540 237163 259044 284666

LIABILITIES:LOANS 3194 5947 9352 26247 26737 39170 5082 62550 70286 72822 83569 106734 139553 162195CURRENT LIABILITIES 2442 2142 22 57 l31 966 1042 1393 2696 2299 3186 4060 4997 5090

TOTAL LIABILITIES 4635 9089 9374 26304 26898 40036 51723 63933 71982 75120 96755 110794 143550 167275

TOTAL EQUITY I LIABILITIES 26492 24598 35137 5)239 86466 115842 150437 184968 225444 265487 306295 347957 402594 451941 rr x=z:: : ::::::: 33:::::: :u.a:uxs :3s3u:uz 3::3.333 3:33333: 3333:333 333:22 :3 : 33333133 333333X3 3323333* Z:::3::: fX 3iX3X

RATIO OF DEBT 10 DEBT PLUS EQUITY 21179 26/74 27/73 28/72 31i69 34/64 34/66 34164 31/69 28/72 28172 31/69 35/65 36/64

INDIA

NAIOINAL THERMAL PONER CORPORATION LIMITED

............................................RIHAND POH£R IRAKSISStIIO PROJEC1

STATEMIENT OF SOURCE AND AFPLICATION OF FUND6

COVERINO OPERATIONS FY1983 THROUGH FY1996.............. ..........................

(RUPEES MILLION)

IOTAL ACTUAL ACIUAL.....................................PROJECTED................................................FISCAL YEAR ENDINO MARCH 31SI 1917-96 1977-33 1904 1985 1916 1987 ? 191 1959 1990 1991 1992 1993 1994 1995 199

SOURCE OF FUNDS:3333333333333.3

OPERAIIN6 INCOlE (BEFORE INIT 16925t 120 675 1716 2774 3324 4930 7194 9343 13449 18163 22563 27963 34801 42236

DEPRECIAlON 49915 69 102 305 628 809 1039 1743 3140 3730 4629 6189 7795 9148 10552.. i ..... ........ ........ ........ ..... ....... ........ ........ ........ ........ ..... .. ........ ........ .....

TOTAL INIERNAL CASH 6ENERATION 219131 IUS 777 2021 3402 4133 5968 6937 12243 17179 22792 28751 35759 43955 52793................ ..................... _

LOANS 179S29 3194 2753 3405 6895 10512 12520 12313 12801 8969 4036 12713 26018 35473 20157

EQUITY SHARE CAPITAL 173026 11810 4204 0159 13369 16673 13177 19239 10294 25603 26799 15699 0 0 0

I01AL SOURCE OF FUNDS 591996 15192 7734 13555 23666 31311 31665 40499 43575 51750 53627 57233 61776 79426 50945|ssssssswssss"sssXlsX gmonsoons XXIMsaws malsomn sse asses stmella vlotwlass ses ~mvlesstl g|| s$sessio onsoxons sommossw onesess songless llB"|81agBll

APPLICATION OF FUNDS

CAPITAL ETPENDIIURE IINCLUDINS IDC) 422911 15794 7170 11747 22179 2967 29606 34308 36043 42259 42122 44216 39606 37069 29746

LOAM INIERESI-CHARGEABLE TO REVENUE 77591 65 221 616 955 1334 1899 3525 5316 6624 5057 9069 10340 12926 16614

LOMN AINRIOI1AIION 17634 0 0 0 0 22 87 801 933 1233 (500 2036 20853 3654 4515........ .......... ........ ........ ........ ........ ........ ........ ....... ........ ........ ........ ........ ........ ...................... .. _

IOIAL DEOI SERVICE 95215 65 221 616 955 1356 19t6 4326 6249 7657 9557 11125 13193 16590 *1129. ...... ... .....

PRELIINARIY EFEkRED EIPEHSE 35 35 0 0 0 0 U 0 0 0 0 0 0 0 0

SHORT-IERM DEPOSIIS/ILOANS) 56116 0 0 0 0 0 0 0 0 0 0 0 6870 22636 26610

OTHER NORKIhN CAPIIAL*INCREASE/IDECREASEI 17709 -702 343 1222 532 265 73 (355 1211 1634 1945 1(52 2105 2343 3450

.h...... ........ ..... 33. .. 3.33.. ........ ........ ...... ...... ........ ........ ........ ........ ........ ........ ........

TOTAL APPLICAT(OM OF FUNDS 591906 15192 7734 13565 23666 31319 31665 40499 43579 51(50 53627 57233 61776 79429 90945

DEBT SERVICE COVERAGE 2.5 2.9 3.5 3.3 3.6 3.0 3.0 2.l 2.0 2.2 2,4 2.6 2.7 2.7 2.5

Z~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~

11^~~~~1014 eZ101 illI111 OIW4ENL PMR ClS R TOISI WIND

RUtElP KIWi IOf O UEILIO *1IS....................... _

COYIEIN OWUTII F 113 IUOW F1I"2... . ... . ........ . .... _., ..... .

liRWI NiLLIUS)

FIVAL 11*1 5971 1913 1979 2930 292 93 5 191 4 M 5963 I936 5931 1`933 599 2919 19 95I" 29M 299 299 1991 29

MKAlUAIP FAICTUR 0 PAIN f111 P M 1n 1.51 1.5 0.01 14.11 10.91 10.71 4.41 4.;1 3.51 3.52 3.5 3.52 3.5s 151 3.52 6.0 6.92 k.il 6.93 6*.n

_ __ ..............

CW5TA. [ISiKiU2TINI 15 223 631 1506 2515 3965 5377 6034 9351 15324 202340 2005 2 193 212fl 33454j 110 31331 2727SINLATIW 25 223 334 2330 4155 0520 2 4091 20112 2932 4414 43 34996 220046 5332 2726 317 20112 Is ph3 3919

CAPfITAL El TE SCSi3A1IIE - RNALUI 10.9 ?2553 360.1 2479.1 5 5223 i.? 5M4 233172, 34192.9 5350, I 1. 106422.55427503 133 233334.1 2331I7337135153 19 01 73023.VORS-WIPP9OW91U1MANCE 2 223 334 2360 3 36 12238 11293 2319 293 453 471 497 671 730 693 454 639 624 76

2 OF CIUUM P.E2PIID. 200.92 200.01 200.02 500. 0 72 A 1 3. . 9 s,i32 46 31.2 N 4.02 33.02 42.31 4,73 , 4532 3, 7 . 2. 23.11

3TIT2EI* 51'C114T2111:KALu V iO 0.0 9.0 0.o 0e0 53. 5392.9 3141.0 9122, 11417.9 22420.2 23459.1 4735,13234.9 101335,0 137201,9 232,6 241934.6 291744.5 34"15.7 IM.3

................. _

WIT.l El IIUSILUIIYEM 0 23 09 250 34 2522 101156 2391 9O3M 9596 nu 007 myl30 9643 0m35 I MlICILATIYI 0 23 i1 232 2 5ll

MJlIAL IR1111111IUIICIRIlI6E- I VAIKIO 0.2 22.3 11.1 242.2 640,9 12 n 2 297.91 321 103.0 1" 02. 211 3,61 JI 6r.4 I 111 993 106. 12727.'3 1214%, 134 I541I~~~~-51*PRO3M11s3ALNE1 0 53 31 232 117 ~~~~~~~~~~~ 1929 331 23 53123 6525 2333 266 7522 9969 517 if6505 210 0349

2 P MU1K1C1WU..CMAE5PE52. 200.02 200.02 500.02 Im.10 200.02 4.1 5.0 64.92 43.02 54.25 64,02 53.45 17.32. I94 2.42 22.22 211.32 27,2 'P.2 0.1

11M15351120o-5W*OI2IONS) IIIW,LI 0.0 0.0 0.0 0.0 0.0 70.0 315.2 2255.5 3056.0 6207.5 1163.3 5721.?9 40352.3 49705.7 54161.5 7269,3 3706*9,1 206739.6 1222591.492574,2

3IIanICII 3.52 0.0 0.0 0.0 0.. 0.0 0. 66,2 110.1 3 412 44 M. 3 714 996.1 543.5 262.3 474 493.1 un9. 11.7 1011 inq.ilUT2ni2 2.61 0o. 0.o 0.0 0.0 0. 0 oo . 9.3 29.0 73.4 12164 130. 44,51 1049.2 2Im9.3 Iwa UnI nn. n . 32.TOTAL 0 \ 0,0 63 120 362 25 946 1227 21225 392 44 6210 NU 10011 1 I 1

AREM MElY VALIEYUO S4 11T-2CPEIATIOI 00. 0.0 0.0 0.0 2.6 913.5 2742.4 1014, 6 l061 25060.6 32917.4 512115. 932.5 234690 5172122. 226249.2 296.3 36 . 43497.6 502110.3.... _.._................. ............

C vim 5933 514 93 n 936 I"9 Im I53 50 2I9 im I29 14 9m 296

11U16 All REYALLYD AI5MTII30PUA141I0 2142 7073 26065 25051 3297 51212 93911 W90 171212 226244 264 601 4349 5011OI

PI5:I SKIU-I25RTPICN. U P15 520.0 615.0° 57605@° 2714,0 ° , 4930,0* 1194,0 93g43,0 23444.0t 13263.0' 22563.03219430l 34g01° 42226.9WiNATIN ICN-NISTORICAL r IS ~ ~~~~~~~~~~~~~~~~~~~~~... ........ . .. ............ .... ... ... .... .. . ...... .... ........ ........ .... . .. ........ ........AMtNPMC IIUD-NIITM5ICAL IIIIII 2.0 49. 0 305.0 6261 ,0 3o0.0 1201-10 M114. 3140,01 3730,0 4TWO 23. 1 793.0 9543.: INN 04L113:KFICIA1100-RIMMIED HUllI 48.0 229.9 Ji, 25.5 946.2 I 2226.7 32124.6 3923,0 4139,7 6220.3 3433.;1203272 12936.3 25405.0

PW liE IKOE-*IEVALU ll 43111 54,0 .24.5 5659,1 241.9 3234. 4142.3 452.4 6I555.0 12t 4I31.1 29247.7 24949.9 09.2 37333.0

RAT[E P 3tl5N ON l VALEO AUIVI 2.02 o 3n 0.32 50.7 9.,/ 9,31 7.3 6. n 7.22 7.n ,on ion 7.51 7o52

3611 Of ItlUIIH ON HItORICAL I1Stl5 6.6 I 1 2.3 7 12.11 13.31 22.72 12.511 2012 9.42 11.31 12.01 11.71 12.21 23.32 54.7

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

INDIA

NA7IONAL IHERMAL PONER CORPORATION LIM1IED................. I.........................

RIHAND POWER TRANSMISSION PROJECT... ............ ......................... ........

PROJECTED REBIONAL TARIFFS VERSUS LONG-RUN MARGINAL COSTS lLRHCI

COVERING FISCAL YEARS FY19S5 THROUGH FV 1,96

IPIASE PER KNh)

FISCAL YEAR 1993 1994 1995 1986 1991 19E6 1999 1990 1991 1992 1993 1994 1995 1996

NORTHERN REGION:

WLK SUPPLY IARRIF .32.3 35S8 40,0 44.7 4t.8 56.9 62.2 b5,3 7D.5 78.0 92.1 87.2 92.3 97.7LRMC-ESCALATED FRON FYI1S4 44.4 49.2 52.3 56.7 61.5 66.7 72.4 78.6 03.3 S: 3 93.6 99.2TARIFF AS 2 OF LRNC 90.1 92.7 99.5 100.4 101.2 97,9 97.4 99.2 9E.6 99.9 99.6 99.5

WESTERN RE61ON:

SULK SUPPLY IARRIF 0.0 36,0 40.0 44.7 46.9 52.5 57.1 612. 6b.3 71.0 75.0 79.4 04,3 89,4LRMC-ESCALAIED FROM F11984 39.2 42.5 4b.1 50.0 54.3 59.9 63,9 69.3 73.5 77.9 92.6 97,6TARIFF AS % OF LRHC 102.1 105.1 201.6 105.0 105,2 104.9 103.9 102,5 102.0 101.9 102.1 102,1

SOUTHERN REGION:.. ..........

BULK SUPPLY IARRIF 0.0 50.0 54.1 56.1 50.0 59.5 63.2 67.6 61.3 69.4 73.5 79.8 86.5 93.9LRNC-ESCALARED FROM FY1984 42.6 46.2 50.2 5414 59.0 64.0 69.4 75.3 79.9 94.6 99.7 95.1TARIFF AS % OF LRMC 127.0 121.4 115,8 109.4 107.1 105.6 97.0 90,9 92.0 94.3 96.4 98.7

EASTERN REGION:....... ....... ..

BULK SUPPLY TARRIF 0,0 0.0 0.0 I2.5 54.0 55.5 57.0 59.2 b5.6 71.9 76.3 81.4 97,0 92.6LRMC-ESCALATED FROM FY1984 42.0 4I.b 49.5 53.7 59.3 63.3 69.7 74.5 79.0 93.7 99.7 94.0TARIFF AS % OF LRNC 115.0 109.0 103,3 97.8 92.0 95.5 96.5 96,6 97.3 98.1 98.5

PROJECTED ItARIFFS: 2 COMPOUND AVERAGE ANNUAL INCREASE.. .......... .................. ... ...... .. ....................

NORTHERN REGION: FY1903-9h 8.92

NESTERN RE61ON: FY1984-96 7.92...........

SOUTHERN REGION: FY1964-96 5.42.. .... .......

EASTERN REGION: F'19G6-96 5.91..... ........ .

NTPC AVERAGE FY1983-96 8.51.......... ......... .

-65- ANNEX 4.8Page 1 of 7

INDIA

NATIONAL THERMAL POWER CORPORATION

RIIAND POWER TRANSMISSION PROJECT

Assumptions for NTPC Financial Projections

1. The financial statements in this report reflect NTPC's financialposition and operations for the period FY77 through FY96, and consist of:

(a) income statement (Annex 4.3) with supporting statementsand schedules of tariffs compared to Long-Run MarginaLCosts (Annex 4.7), rates of return on net revalued assets,(Annex 4.6), and scheduled commissioning of power plants(Annex 2.2);

(b) statement of source and application of funds (Annex 4.5) withsupporting financing plan (Annex 4.2), and investment program(Annex 4.1); and

(c) sumnarized balance sheets as at March 31st of each year(Annex 4.4).

2. FY'83 and FY'84 data reflect actual operating results while thefinancial projections for FY'85 through FY'96 are based on the followingassumptions:

-66-


(a) Stabilization of Power Generation:

Operating GWhs/MW CGhs/UnitHours/year per year per year

200 NW UNTTS: - First 6 months : 2500 2.5 500- Next 6 months : 4000 4.0 800- Second year 5500 5.5 1100

210 MW Units: - First 6 months : 2500 2.5 525- Next 6 months : 4000 4.0 840- Second Year : 5500 5.5 1155

500 NW Units: - First unit commissioned at each station

- First year : 2500 2.5 1250- Second year : 4000 4.0 2000- Third year : 5000 5.0 2500- Fourth year 5500 5.5 2750

500 MW Units: - Subsequent units of each station

- First year : 2500 2.5 1250- Second year : 4000 4.0 2000- Third year : 5500 5.5 2750

-67-


(b) Fuel Costs:

Northern RegionSingrauli Rihand Muradnagar

Coal: 200 & 210 MW Units- Calorific Value (Kcal/Kg) 5600 N/A 3800- Heat Rate (Kcal/KWh) 2131 N/A 2043- Boiler Efficienty Z 07.49Z N/A 87.52X- Kgs per KWh 0.435 N/A 0.614- Price per ton-Rs 231.40 N/A 330.19- Cost per Glh: Base Cost 1984 0.1007 N/A 0.2027

Coal: 500 MW Units- Calorific Value (Kcal/Kg) 5600 4520 N/A- Heat Rate (Kcal/KWh) 2016 2027 N/A- Boiler Efficienty Z 86.63Z 87.00Z N/A- Kgs per KWh 0.416 0.515 N/A- Price per ton-Rs 231.40 201.86 N/A- Cost per Glh: Base Cost 1984 0.0963 0.1040 N/A

Fuel Cost Factor to include Oil 120.0X 120.0Z 130.0%

Southern.Western Region Region

Korba Vindhyach Ramagundam

Coal: 200 & 210 NW Units- Calorific Value (Kcal/Kg) 3800 4520 4300- Heat Rate (Kcal/KWh) 2043 2150 2014- Boiler Efficienty 1 87.522 864.9% 88.60Z- Kgs per KWh 0.614 0.550 0.529- Price per ton-Rs 112.84 201.86 228.91- Cost per GWh: Base Cost 1984 0.0693 0.1110 0.1211

Coal: 500 MW Units- Calorific Value (Kcal/Kg) 3800 N/A 4300- Heat Rate (Kcal/KIWh) 2016 N/A 2033- Boiler Efficienty Z 86.69% N/A 87.28Z- Kgs per KWh 0.612 N/A 0.542- Price per ton-Rs 112.84 N/A 228.91- Cost per Glh: Base Cost 1984 0.0691 N/A 0.1241

Fuel Cost Factor to incLude Oil 130.0Z 120.0Z 120.01

-68-


Eastern Region All RegionsFarakka Kahalgaon New Projects

Coal: 200 & 210 MV Units- Calorific Value (Kcal/Kg) 3200 3200 3800- Heat Rate (Ical/KWh) 2020 2150 2043- Boiler Efficienty Z 87.16% 86.49% 86.69%- Kgs per KWh 0.724 0.777 0.620- Price per ton-Rs 113.36 113.36 201.86- Cost per GWh: Base Cost 1984 0.0821 0.0881 0.1252

Coal: 500 MW Units- Calorific Value (Kcal/Kg) 3200 N/A 4520- Heat Rate (Kcal/KWh) 2027 N/A 2027- Boiler Efficienty % 86.69% N/A 87.00%- Kgs per XWh 0.731 N/A 0.515- Price per ton-Rs 113.36 N/A 201.86- Cost per GWh: Base Cost 1984 0.0829 N/A 0.1040

Fuel Cost Factor to include Oil 130.0% 130.0% 130.0%

The escalation rates applied to the above base 1984 fuel costs forcalculating cost increases and tariff fuel surcharges were are set out in(c) below.

Cc) Escalation Factors

The financial projections and project costs are based on 1984 pricesescalated at the following rates, except for orders already placed, in whichcase, escalation is applied from award dates onward:

Fiscal Year Foreign Costs Local Costs

FY'85 8.0% 8.5%FY'86 9.0% 8.5%FY'87 9.0% 8.5%FY'88 9.0% 8.5%FY'89 7.5% 8.5%FY'90 6.0% 8.5%FY'91 6.0% 8.5%FY'92 and thereafter 6.0% 6.0%

The turbo-generators and boilers are, however, subject to the followingmaximum price escalation from the date of order:

Singrauli 200 MW units - 25%Korba, Ramagundam, Farakka, and other 200/210 MW units - 20%

-69-


(In the case of Vindhyachal (210 MW units) fixed-price contractsapply)

500 MW units for all projects - 15% Turbo - generators- 20% Steam - generators

Physical contingencies

Civil works - 10% of construction c:ostsEquipment - 5% of equipment costs

(d) Operations & Maintenance Expenses

Power stations - 2.5% on original cost of 200 MW pLant- 2.0% on original cost of 500 MW plant

Transmission - 0.5% on original cost

Ce) Depreciation

Power stations - 3.1% on original cost of plantTransmission - 2.6Z on original cost

Cf) Auxilliary Consumption

Auxilliary power consumption for station use has been assumed at 10%for 200/210 MW units and 7% for 500 MW units.

(g) Tariffs

Tariffs have been determined from the formulae of the Regional bulksupply contracts which provide for:

Ci) fuel costs with an automatic fuel price adjustment clause;

(ii) depreciation applied to capital costs escalated to currentcosts;

(iii) operations and maintenance costs based on capital costs forpower plants and transmission facilities, escalated to currentcosts;

(iv) loan interest at the prevailing GOI interest rate (currently13.5%) on estimated balance of loan principal outstanding;and

(v) return on equity at 10% on projected equity.

-70-


(h) Capital Requirements

(i) The proposed Bank loan would be made directly to NTPC for a20 year term with GOI guarantee, principal repayments in equalannual installments over 15 years (subsequent to a 5 yearperiod of grace), and at an interest rate of 10.08Z per annum.

(ii) Other capital requirements would met by NTPC's internal cashgeneration combined with GOI advances in the form of equity andshare capital subject to the condition that unpaid loans, at theend of each year, does not exceed share capital and retainedearnings. Equity capital advances would preceed GOI loanfunding.

(iii) GOI loans (including the onlending of previously approvedcredits and loans) are assumed to finance projects includedin NTPC's investment program. Interest on Loans upto the date of commissioning of each unit of plant, would becharged to construction (capitalized), while subsequent interestaccrued would be charged to Revenue. Repayment of principalis assumed in 30 semi-annual installments commencing on thefirst anniversary following the end of the five year graceperiod. The total loan drawdown for each year, and for eachproject, is assumed as a separate COI loan for purposes ofloan repayments.

(i) Iorking Capital

Variations in working capitaL represei.t the difference of currentassets less current liabilities between the b:ginning and the end of eachyear.

(j) Balance Sheet(i) Cash is assumed at 10 days oper;.ting expenses less depreciation.

(ii) Receivables are assumed at a level of equivalent to one-sixthof total operating revenue for each year.

(iii) Inventories are assumed at a level equivalent to 15 days coalcosts (including fuel surcharge), 60 days oil costs, 1.5 yParscost of spares requirements, and 6 months cost of chemicals andlubricants.

(iv) Loans and advances are assumed at 1% of annual revenue plus anadded Rs 2 million per year to provide for loans to officers.

-71-


(v) Other current assets are assumed to be a constant figure of 4million each year.

(vi) Current liabilities are assumed at 1X of annual fuel costs,plus 15 days of salaries, plus 2Z of annual operations andmaintenance costs, and loan principal repayments projectedfor the subsequent year.

(v) Loans and advances are assumed at 1Z of annual revenue plusan added Rs 2 million per year to provide for loans toofficers.

-72-


INDIA

NATIONAL THERMAL POWER CORPORATION LIMITED


Commercial Arrangements for Sale of NTPC Power

1.01 The Memoranda of Understanding (MOUs) received for SEB's of theNorthern (Singrauli) Region, and SEB's of the Western (Korba) Regionrepresent interim agreements between NTPC and the relevant SEBs for the saleof power. The MOU contracts expire on March 31, 1985 for the Northern Regionand March 31, 1986 for the Western Region, or when replaced by revised bulksupply contracts, whichever occurs earlier. Although the MOU's defined mostof the factors, terms and conditions considered by the Bank to be requiredin order to be satisfactory, clarifications wers sought, during negotiationsfor Loan 2442-IN, concerning the validity of the contracts after theirexpiration dates, provision for a capacity charge, provision for NTPCprofits, and the calculation of the flat tariff rates. During negotiationsGOI and NTPC provided satisfactory clarification on these points. The Indiandelegation provided a copy of a legal opinion verifying that the interimcontracts (MOU's) will remain legaLly valid and binding after theirexpiration date and until replaced be revised contracts. They also provideddetails of calculation of the interim flat rate tariffs clarifying that therates included correctly, all factors which were of concern to the Bank,which included a NTPC profit component of 10Z on NTPC equity, and loaninterest at the GOI onlending rate (currently 13.5X). It was also clarifiedthat the interim contracts include provision for a commitment (capacity)charge, which is not at present recovered as a separate element in thetariff, but is covered by the overall variable tariff rate. The Indiandelegation expLained that at the present stage of deveLopment, theinter-state transmission systems had not advanced to the point where NTPCcould ensure supply of the SEBs' agreed power allocations. Owing to thecontractual financial penalities of non-supply of allocated power, which area part of the commitment charge provision, it was considered premature atthat stage for NTPC to biLl SEBs for power sales on the basis of a two-tiertariff (fixed commitment charge plus variable energy charge).

1.02 Contracts have not yet been received for the Southern Region(Ramagundam) or for the Eastern Region (Farakka) which were due in May 1983and July 1984 respectively. As the Bank mission emphasized during previousmissions, and during appraisal of the proposed project, satisfactorycontractual agreements between NTPC and the relevant SEBs for the sale ofpower are essential to ensure the financial viability of NTPC. Submissionto the Bank of signed contracts for the States of the Eastern and SouthernRegions was made a condition of effectiveness for Loan 2442-IN. At the

-73-


request of GOI, the Bank has recently extended the date of loan effectivenessto May 6, 1985. During negotiations for Loan 2442-IN, GOI and NTPC agreed toprovide to the Bank revised bulk supply contracts for all four Regions, byMarch 31, 1986, incorporating the following provisions:

(a) Provision for periodic renewal of the contractsbeyond the initial validity period;

(b) At the time of renewal, replacement, or extension ofthe contracts, but in any event at not more thanthree-year intervals, revision, where required, of thetariffs and the factors for their calculation toensure recovery of NTPC's operating costs and loaninterest, and generation of a satisfactory level ofnet income;

(c) Provision that a commitment (capacity) charge be introducedat a time considered appropriate by NTPC; and

(d) Definition of the NTPC profit component of the tariffs.

1.03 In respect to power transfers to SEB's outside of a particularRegion, the sales of NTPC power will be priced at the bulk supply tariff rateof the receiving region for sales within the committed power allocation ofthe relevant SEB. Where sales are in excess of the committed allocation, rhetariff rate of the generating region would apply to that portion in excess ofthe committed allocation.

1.04 NTPC bulk supply contracts establish regional tariffs for NTPC powersales in eash respective region. Operating costs applicable to thetransmission facilities of the Central Power Transmission Project and theproposed project will be absorbed by the relevant regional NTPCorganizations. Recovery of such costs, therefore, are reflected in theregional tariffs as a separate component of these tariffs. The bulk supplycontracts provide for an automatic monthly adjustment to current fuel prices.

-74- ANNEX 5.1Page 1 of 4

INDIA


Internal Economic Rate of Return

As described in Chapter 5, the proposed Project forms an integralpart of the expansion plan for the Northern Region and, therefore,cost-benefit analysis needs to be carried out on the whole program ratherthan on the Project in isolation. The Northern Region's investment programduring the period FY'85-FY'95 has, therefore, been analyzed. Capital cost,incremental operation and maintenance, incremental fuel cost and benefitstreams are all shown in Table 1. Assumptions underlying these figures aredetailed beLow.

Capital Costs

Anticipated capital expenditure on generation at financial prices hasbeen converted to economic prices by (i) expressing the imported content atcif prices; (ii) valuing unskilled local labor at 0.75 of the market wagerate; and (iii) applying the estimated standard conversion factor, 0.8, tolocal costs. Transmission and distribution capital expenditures have beenestimated at 40% of generation expenditure.

Operation and Maintenance Costs

Incremental annual operating and maintenance costs have beenestimated as the following percentages of capital value: thermal generatingplant 2.52, hydroelectric 1.13X, and transmission and distribution 1.0%

Fuel Costs

Incremental fuel costs arise only from coal-fired thermal plantincluded in the Region's investment program. Average fuel consumption ofnew coal-fired plant has been estimated at 0.61 kg of coal/kWh plus 0.015liter/kWh of fuel oil at Rs. 2.8 per Liter, the latter being required forflame stabilization. The economic cost of coal at the pit head has beenestimated at Is 172/ton. It has been estimated that 65Z of incrementalthermal generation will be in minemouth stations and 35% will be in loadcenter stations. The average economic cost of coal delivered to load centerstations has been estimated at Rs 350/ton.

Case 1. Benefits

Case 1. benefits are based solely on incremental revenue at existingtariff levels. Incremental sales attributable to the investment program are

-75-


shown in Table 1. These allow for system Losses which are assumed to remainconstant at 20% of net, generation. The average existing tariff is estimatedto be Rs. 0.46/kWh which, after applying the v:andard conversion factor of0.8, corresponds to an economic value of revenue of Rs. 0.37/kWh.

Case 2. Benefits

In Case 2, the benefits of incremental consumption include eLementsof consumers' surplus for both industrial and agricultural consumers.Surplus has been imputed at half of the difference between the averagetariff, and the alternative cost of autogeneration for industrial consumersand diesel pumping for agricultural.

The cost of industriaL autogeneration has been estimated as follows:

Purchase price (incl. installation) Rs 4,300/kWLife of set 15 yearsAverage utilization 30%Discount rate 12%Operation and maintenance cost Rs 215/kW per annumFuel and lubricant Rs 0.80/kWhAverage cost Rs 1.12/kWh

The cost of electricity which would make electrical pumping equiv-alent to diesel is calculated as follows:

-76-


Electric Diesel

Motor/engine size 5.0 HP 7.0 HPLife Years 15.0 10.0Investment Cost Rs. 4000 Rs. 10250Cost of diesel/hr - Rs. 4.82

Annual Costs

Annual Charges Rs. 526 Rs. 1668O&M Rs. 890 Rs. 2500Electricicy/diesel(800 hrs/year)Electricity costingX /kWh Rs. 2984 X Rs. 3853

Total annual cost Rs. 1416 + Rs. 80212984 X

Marginal cost of electricity X = (8021-1416)/2984at which diesel and electricity = Rs. 2.21/kwhare equivalent

Average industrial and agricultural financial tariffs in the Northernregion are estimated at Rs. 0.54/kWh and Rs. 0.21/kWh respectively.Estimated willingness to pay, cnnverted into economic terms at a standardconversion factor of 0.8, is therefore Rs. 0.66/kWh for industrial and Rs.0.97/kid' for agricultural. Combining these with revenue estimates of thebenefit to other consumers gives an average benefit of Rs. 0.72/kWh ineconomic terms.

Table 1 - Northern Region Least Cost Expansion Program and Economic Rate of Return(Rs Million)

OperationCapital & TotaL Incremental Benefits

FY Ependiture Haintenance Fuel Cost Sales Rs.0.72/kWh Balance(Gwh)

85 1389 1389 - 138986 4042 4042 - 404287 10342 10342 -1034288 14018 14018 -1401889 20073 63 64 20200 221 159 -20041

-77-


90 21752 207 613 22372 2354 1697 -2067591 18044 654 11i46 19844 5938 4281 -1556392 15098 1095 2593 18786 L2446 8974 - 981293 12615 1400 3941 17956 20082 14479 - 347794 11284 1726 5049 18059 30742 22165 - 410695 9588 1566 6180 17334 39438 28435 1110196 1566 6582 8148 42863 30904 2275697 1566 6900 8466 45629 32899 2443398 1566 7164 8730 47954 34575 2584599 1566 7394 8960 50006 36054 270942000- 1566 7394 8960 50006 36054 27094

2020

IRR = 13.3%

-78-

ANNEX 6.1

INDIA


RELATED DOCUMENTS IN THE PROJECT FILE

1. Rihand STPP Associated Transmission System, Feasibility Report NTPC,January, 1984.

2. Report on Power System Planning Studies on Rihand Transmission,CEA and HQI, September 1984.

3. Agreement between NTPC and Hydro-Quebec International, Canada,March, 1984.

4. Sectoral Data for World Bank Appraisal of National Capital RegionThermal Station, CEA, Delam, August, 1984.

5. Corporate Plan 1985-2'000, NTPC, March, 1984.

6. A report on National Power Plan (INDIA), Generation Expansion Program(1981-82 to 1996-95), CEA, April, 1983.

7. Project Detailed Cost Estimate - COMPASS, December 6, 1984.

8. Financial Statements of UPSEB, PSEB, RSEB, and HSEB.

9. NTPC, 8th Annual Report, 1983-84

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