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Document of

The World Bank

FOR OFFICIAL USE ONLY

Report No. 5831-IN

STAFF APPRAISAL REPORT

INDIA

COMBINED CYCLE POWER PROJECT

February 28, 1986

Power and Transportation DivisionSouth Asia Projects Department

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

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CURRENCY EQUIVALENTS

Currency Unit = Rupees (Rs)Rs 1.00 = Paise 100US$1.00 = Rs 13.00Rs 1.00 = US$0.0769Rs 1,000,000 = US$76,923

MEASURES AND EQUIVALENTS

1 Kilometer (km) = 1,000 meters (i) = 0.6214 miles (mi)1 Meter (m) = 39.37 inches (in)1 Cubic Meter (M3 ) 1.31 cubic yard (cu yd) = 35.35 cubic feet (cu ft)1 Thousand Cubic Meter (MC4) = 1,000 cubic meters1 Thousand Cubic Meter (MCM) = 1,000 cubic meter1 Barrel (Bbl) = 0.159 cubic meter1 Normal Cubic Meter = 37.32 Standard Cubic Feet (SCF)

of Natural Gas (Nm3)1 Ton (t) = 1,000 kilograms (kg) = 2,200 pounds (lbs)1 Metric Ton of Oil = 7.60 barrels

(39 API)1 Kilocalorie (kcal) 3.91 British Thermal units (BTU)1 Kilovolt (kV) = 1,000 volts (V)1 Kilovolt ampere (kVA) = 1,000 volt-amperes (VA)1 Megawatt (MW) = 1,000 kilowatts (kW) = 1 million watts1 Kilowatt-hour (kWh) = 1,000 watt-hours1 Megawatt-hour (MWh) = 1,000 kilowatt-hours1 Gigawatt-hour (GWh) = 1,000,000 kilowatt-hours1 Ton of Oil Equivalent (toe)= 10 million kilocalories

ABBREVIATIONS AND ACRONYMS

CEA - Central Electricity AuthorityCTG - Combustion Turbo-GeneratorHRB - Heat Recovery BoilerGAIL - Gas Authority of India LimitedSOI - Government of IndiaHBJ - Hazira-Bijaipur-JagdishpurICB - International Competitive BiddingLCB - Local Competitive BiddingLSHS - Low Sulphur Heavy StockLPG - Liquefied Petroleum GasLRMC - Long Run Marginal CostMHCMD - Million Cubic Meter per DayMOU - Memorandum of UnderstandingNGL - Natural Gas LiquidsNHPC - National Hydro Electric Power Corporation, Ltd.NPP - National Power PlanNREB - Northern Region Electricity BoardNTPC - National Thermal Power Corporation, Ltd.REB - Regional Electricity BoardREC - Rural Electrification CorporationSEB - State Electricity BoardSTG - Steam Turbo-Generator

NTPC'S FISCAL YEAR (FY')April 1 - March 31

1/ The US$/Rs exchange rate is subject to change. Conversions in thisreport have been made at US$1 to Rs 13.0, which represents the projectedexchange rate over the disbursement period.

FOR OFFICA USE ONLY

INDIA

COKBINED CYCLE POWER PROJECT

LOAN AND PROJECT SUMKARY

Borrower: India, acting by its President

Beneficiary: National Thermal Power Corporation Ltd. (NTPC)

Amount: US$485 million

Terms: Repayment over 20 years, including 5 yearsgrace, at the applicable rate of interest.

Onlending Terms: From the Government of India (GOI) to NTPC,with repayment over 20 years, including 5years' grace, at an interest rate of not lessthan 13.0Z per annum. GOI would bear theforeign exchange and interest rate risks.

Project Description: The Project's main objective is to assist inmeeting the electricity demand in the Northernand Western Regions of India through theaddition of about 1,500 KW of thermalcapacity. The Project comprises theinstallation of three combined cycle powerstations located at Kawas (Gujarat), Anta(Rajasthan) and Auraiya (Uttar Pradesh), aswell as the associated transmission system forconnection to the grid. This Project willintroduce combined cycle as a new technologyas well as natural gas as a fuel for powergeneration. The gas will be providedessentially from the off-shore South Basseingas field and through the Hazira-Bijaipur-Jagdishpur (HBJ) pipeline. There are nounusual risks. NTPC is experienced in thedesign and construction of generation andtransmission facilities but will receiveassistance from consultants in relation to thecombined cycle units, as these represent a newtechnology for both NTPC and India.

Thi document hs a nstrited disibution and may be used by recipients only in the performanceof the officid dutieL Its contents may not otberwise be disclosedwnthout World Bank mbnoiiaton.

Estimated Cost: 1/

Local Foreign TotalUS$ million

Preliminary and Civil Works 59.9 4.4 64.3Main Electromechanical 158.9 411.2 570.1Equipment

Auxiliary Electromechanical 67.6 80.8 148.4Equipment

Fuel Supply Equipment 4.4 9.0 13.4Transmission System 110.1 15.1 125.2Consultancy and 5.6 5.2 10.8Technical Assistance

Engineering and 62.2 - 62.2Administration

Total Base Cost 468.7 525.7 994.4

Physical Contingencies 24.2 27.5 51.7Price Contingencies 82.8 112.4 195.2Total Project Cost 575.7 665.6 1,241.3

Interest duringConstructionBank - 37.4 37.4Other 4.3 3.0 7.3

Total Financing Required 580.0 706.0 1,286.0

Financing Plan:

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

IBRD Loan - 485.0 485.0GOI/External Borroving 475.2 221.0 696.2NTPC 104.8 - 104.8

580.0 706.0 1,286.0

1/ Includes taxes and duties of about US$127.3 million.

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Estimted Disbursements:

Bank FY FY87 FY88 FY89 FY90 FY91 FY92-(W$[illion)

Annual 37.0 133.0 150.0 90.0 50.0 25.0Cumulative 37.0 170.0 320.0 410.0 460.0 485.0

Rate of Return: Northern Region 12 Western Region 13%

INDIA



Table of Contents

Page No.

Is SECTORAL CONTEXT .................. 1

Comercial Energy Resources ........ ......... ... 1Electricity Supply and Demand ........................... .. .... 2Organization of the Power Subsector .................-......... 3Finance and Pricing ... ........................................ 4Power Subsector Planning ...... ...... **..0............ 5Management and Operations ...... o ...... .-.......... *......**..* **** 5GOI's Strategy in the Power Subsector ......... 60.....0........ 6Bank Group Strategy in the Power Subsector .................... .. 8Bank Group Participation ............................. ... .. .. 10

II. THE BENEFICIARY - NATIONAL THERMAL POWER CORPORATION LIMITED .. 11

Existing Facilities and Development Program ............... 0... 11Organization and Management .................................. . 11Recruitment and Training ... ... .......... .*.... ....... .. .... 12Performance ..........o.. 0 . . ......... ..... ...... ......... 13

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

Project Setting ............ ................. . 14Project Objectives .. ................... 14Project Description .... ................................ 15Fuel Supply .......... 0.......... .................. ....................... 15Engineering and Construction ............. ............. . ... 16Project Preparation and Implementation Schedule ............... 17Project Costs .....................-.................................. ..... 17Project Financing .. ........... ..................... 0..... .... 19Procurement ...... ....... * .............................. 19Disbursement .............................................................. 21Ecology - ................... ........ 21Project Risks ............ o ................. 21Project Monitoring ..... .............. ......... ........ 22

This report has been prepared by Messrs. E. Linard de Guertechin (PowerEngineer), Suman Babbar (Power Engineer), John B. Creasor (FinancialAnalyst), Wynne P. Jones (Economist), and M. Sharma (Consultant).

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IV. FINANCE ................................... 23

Accounting Organization and Systems ........................... 23Past Financial Performance *......se...................... 23Future Investment and Financing ............................... 25Future Financial Performance .................................. 25Regional Tariffs ......... ................. ............ 27Commercial Arrangements for Sale of Power ..................... 28Taration ......................................... ........... 29Bank Loan for the Proposed Project ...o ......................... 29Audit ..........................................ss.s........ 29

V. PROJECT JUSTIFICATION AND ECONOKIC ANALYSIS ......o. ............ 30

Least Cost Analysis .... .......... ............................. 30Internal Economic Rate of Return ............................... 30Justification for Bank Involvement ............................ 32

V*I. ACREEMENTS AND RECO9EKENDATION ................... 33

Agreements ..................................... 33Recmmndaio .............................................34

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ANNEXES

Page No.

1.1 Electricity Generation, Sale and Pattern of EnergyConsumption - All India ............6....................... 35

1.2 Forecast of Regional Power Demand in India FY'86 - FY'95 ....... 361.3 Previous Loans and Credits to India Power Sector

(June 30, 1985) ...................*......................... 372.1 NTPC Schedule of Comfissioning of Power Plants ................ 382.2 NTPC Organizational Structure ................................. 402.3 NTPC Generation Facilities - Operation Performances .......... 413.1 Electricity Generation and Consumption

and Power Supply Position of Western Region ................. 423.2 Electricity Generation and Consumption

and Power Supply Position of Northern Region ........ 443.3 Detailed Project Description .................................. 463.4 Implementation Schedule ...e.. .. ..... ................. 493.5 Project Cost Summary ................................. 523.6 Estimated Schedule of Disbursement ............................ 534.1 Investment Program ...................... ........ 544.2 Financing Plan Covering Fiscal Years FY'77 through 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 .................. ... ................. . 634.7 Projected Regional Tariffs versus Long-Run Marginal Costs ..... 644.8 Assumptions for NTPC Financial Projection ............... ....... 654.9 Commercial Arrangements for Sale of NTPC Power ................ 725.1 Internal Economic Rate of Return ............. ................... 746.1 Related Documents in Project File ............................. 79

NAP

IBRD 19105

INDIA



I. SECTORAL CONTEXT

Commercial Energy Resources

1.01 India's principal commercial energy sources comprise coal, oil, gashydro and nuclear energy. Of the nonrenewable resources, coal is the mostabundant. Reserves of thermal coal have been estimated at slightly more than100 billion tons, of which 25 million are proven. Although reserves areample, the quality of coal produced is generally low and is deteriorating.The high ash content, up to 5OZ, increases power station capital and operat-ing costs and exacerbates the problems that Indian Railways has in moving thevolume of coal required for power generation. GOI's policy of concentrateddevelopment of pithead stations helps to address the transport problem butdoes not reduce the other costs associated with poor coal quality. In anycase this policy is constrained by pollution and water availability. COIappointed the Fazal Committee to examine the problems of coal supply tothermal power stations. This committee, which reported in October 1983, madea large number of recommendations, affecting all aspects of supply from coalpreparation to railway operations (para 1.14); the great majority of theserecommendations have been accepted by GOI. The Bank is supporting GOI'sefforts in this area through its lending to the coal sector. The DudhichuaCoal Project includes studies to examine coal linkages and identify potentialimprovements in handling and transportation facilities. Coal quality is alsobeing addressed, particularly through the inclusion of kppropriate qualityincentives in coal supply contracts.

1.02 Proven and probable petroleum reserves comprise approximately 510million tons of oil and 390 million toe of natural gas. Despite recentincreases in domestic production, India still imports about one third of itsoil requirements, which in FY'84 cost the equivalent of 40Z of its merchan-dise exports. GOI has therefore given high priority to oil and gas explora-tion and, at the same time, has implemented measures, including economicpricing, to restrain the rapidly growing demand for oil products, par-ticularly middle distillates. In the past, GOI has generally limited naturalgas to premium markets such as petrochemicals and fertilizer; however, delaysin the construction of gas infrastructure have resulted in substantialvolumes of gas being flared. The Bank has encouraged GOI to develop thenecessary infrastructure and to allow other economic uses of gas including

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power generation. In response, COI has begun to invest in pipelines and hasrecently revised its policy on the use of gas for power generation(paras 1.14 and 1.15).

1.03 India's hydroelectric potential is equivalent to about 100,000 MW.At present only 14,000 MW have been developed, 4,700 MW are under construc-tion and a further 23,000 MW are being studied for future development. Theprominent role of hydro generation in regional least-cost power developmentplans has led GOI to emphasize the need to accelerate hydro development;however, progress has been slow owing to the lack of financial resources ofstates with the greatest hydro potential, the time required to resolve waterrights and environmental issues, and the limited technical resources avail-able for the simultaneous preparation of a large number of hydro schemes.Attempts to address these issues through increased central sector involvementhave so far met with limited success (para 1.07).

1.04 The country's uranium reserves could support a modest nuclear program(8,000 - 10,000 MU), and thorium reserves are enough for a large fast breederprogram. India's nuclear power generating capacity is currently 1,095 MW.

Electricity Supply and Demand

1.05 Almost 60% of India's electricity is generated from coal, 34% fromhydro, and the rest from oil, nuclear energy, and natural gas. Although anumber of thermal projects are planned for the short-term, the shares ofhydro and nuclear are likely to increase in the long run. Electricity losseshave risen slowly but steadily over the last few years and now exceed 26Z ofgross generation. The deteriorating quality of coal has increased sta-tion-use and the large expansion in very low load density rural electrifica-tion, together with otherwise inadequate investment in transmission anddistribution, has increased system losses. The Bank has stressed the impor-tance of balanced investment to reduce system losses and will continue tosupport transmission and distribution investments designed to achieve thisobjective.

1.06 Over the past two decades, the consumption of electricity has grownapproximately twice as fast as total commercial energy consumption and nowaccounts for more than 30% of the latter. Even though the power subsectorreceives 20-25% of total public investment, electricity supply has not keptpace with demand and shortages have been prevalent throughout the country.During the last five years, shortages have been estimated at, on average,about 13Z of electricity requirements. The principal sectoral shares oftotal electricity consumption are: induscrial, 512; agricultural, 18Z; anddomestic, 9%, (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 annual rate of 8% during the past two decades although the increasingseverity of power shortages suggests that potential demand has grown more

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rapidly. The Central Electricity Authority (CEA) has forecast demand growthin the range 10-llZ per year between FY85 and FY95 (Annex 1.2). However,actual growth will continue to be supply constrained.

Organization of the Power Subsector

1.07 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; CEA isadministered by the Department of Power within the Ministry of Energy and theNational Thermal Power Corporation (NTPC), the National Hydro-Electric PowerCorporation (NHPC), and the Rural Electrification Corporation (REC) arecentral sector corporations responsible to the Department of Power. SEBswere instituted under the Electricity (Supply) Act, 1948 (the Act), topromote the development of the power subsector and to regulate private licen-sees such as the Tata Electric Companies. Although SEBs are supposed to beautonomous in managing their day-to-day operations, in practice they areunder the control of State Governments in such matters as capital investment,tariffs, borrowings, pay, and personnel policies. As a first step towardsnational integration, the SEBs have been grouped into five regional systems,each coordinated by an REB. Coordination responsibilities include overhauland maintenance programs, generation schedules, interstate power transfersand concomitant tariffs. CEA was created in 1950 to develop national powerpolicy and to coordinate the various agencies involved in supplying elec-tricity. It is formally responsible for vetting investment proposals,providing consulting support to SEBs, assisting in the integration of supplysystems, training oi personnel, and tesearch and development. However, inits execution of these responsibilities, CEA has been severely limited byshortages of skilled staff and other resources. Without any direct respon-sibility for the provision of finance it has been unable to assume a verypositive role in the development of the subsector. In view of this, GOI iscontemplating the formation of a Power Finance Corporation to complement CEAin fostering development of the subsector (para 1.16). NTPC and NHPC wereformed in 1975 to construct and operate large power stations and associatedtransmission facilities. They sell bulk power to the SEBs for distribution.NTPC has had marked success and has grown rapidly. In contrast, NHPC isstill struggling to establish a role for itself; the states control waterrights and are reluctant to relinquish hydro sites to the Center. This hasprompted GOI to explore joint ventures between the Center and states for thedevelopment of hydro schemes. REC was established in 1969 to coordinaterural electrification and provide financial and technical expertise for SEBschemes. Currently, REC finances more than 70% of total rural electrifica-tion investment. At present there is no organization with responsibility forthe development of a national transmission grid, although GOI is contemplat-ing the formation of such a body (para 1.17).

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Finance and Pricing

1.08 Although four SEBs are estimated to have made a profit in FY'85, theSEBs as a vhole are astimated to have made a combined loss in that year ofapproximately Rs 11,230 million (US$935 million) exclusive of subsidies,corresponding to a return on historically valued net fixed assets of +2.3%before interest and -8.1Z after interest. Internal cash generation, whichwas equivalent to only about 2.71 of capital expenditure in FY'85, has beencorrespondingly poor. Almost all SEB capital expenditure is financed bydebt, primarily loans from state governments. Recognising the unsatisfactorystate of SEB finances GOI has, through an amendment to the Act notified inApril 1985, required SEBs to earn an annual return, after meeting operatingexpenses, taxes, depreciation and interest, of at least 3Z on their histori-cally valued net fixed assets (GOI does not accept the principle of revalua-tion of assets). The Bank supports this initiative by GOI and has, under theChandrapur Thermal Power Project (Loan 2544-IN), changed the form of itsfinancial covenant to reflect this. Although, in terms of the Bank's conven-tional method of calculation, the return specified in the Act corresponds toa modest return on revalued assets in the range of 4 to 6Z, it, nevertheless,represents a very substantial improvement on current performance. Many SEBs,particularly those of the poorer states, are expected to experience con-siderable difficulty achieving this level of performance. NTPC's tariffs areapproximately equal to its long-run marginal costs (LRMC); however, as is tobe expected from their current financial performance, SEB's tariffs do notadequately reflect LRMCs. An analysis of 1981 SEB tariffs indicated thatthey were on average only 521 of LRMC. While adherence to the stipulatedrate of return would improve the overall level of the tariff, the structureis still unsatisfactory. Tariffs are frequently excessively complex and verylittle has been done through tariffs either to achieve load management or totap selectively consumers' willingness to pay, where this substantiallyexceeds existing tariff levels. At the instigation of the Bank, LRMC tariffstudies were carried out for almost all of the states in the late 1970's.However, these studies were generally of poor quality and the Bank has sinceendeavored to agree with GOI on a methodology for LRMC tariff studies.Progress has been slow as GOI continues to oppose economic pricing of powerfor reasons associated with social and agricultural objectives. In lendingto individual SEB's the Bank will continue to address state-specific programsto improve resource mobilization, for example, by developing financialprograms capable, as a minimum, of achieving the rate of return specified inthe Act. Where higher returns are both feasible and desirable the Bank willpress state governments to use their discretion under the Act to notify ahigher rate of retuiri. So far as tariff structure is concerned the Bank willcontinue to require tariff studies wherever tariff structures appear to bebadly distorted, in order to impress on the relevant authorities the truecosts of cross-subsidisation. This has been done under both the ChandrapurThermal Power Project (Loan 2455-IN) and the Kerala State Power Project(Loan 2582-IN). However, resistance to economic pricing is such thatprogress in pricing reform is likely to be slow (para 1.18).

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Power Subsector Planning

1.09 The Bank has consistently encouraged GOI to pursue integrated plan-ning and coordinated operation of the country's electricity supply systems.In response, GOI has prepared a set of regional least cost development plans,published as the National Power Plan (NPP) in 1983. Although the NPP repre-sents a good first step towards integrated planning, it needs further refine-ment and regular updating. In addition, such a plan can only lead to effec-tive improvements if complemented by measures to bring about coordinatedsystem operation. At present only the Northern Region is achieving this.GOI is encouraging states to reach the necessary agreements on operatingparameters but progress is likely to be slow so long as severe powershortages exist. Even if coordinated intra-regional operation is achieved,inter-regional transfers will be very difficult without the use of directcurrent facilities to overcome problems of frequency control. The first suchfacility, a link between Northern and Western Regions, is being financed bythe Dank under the Central Power Transmission Project Loan 2283-IN). Asecond direct current link has been included in the Rihand Power Trans:ssionProject (Loan 2535-IN). . To facilitate further integration GOI has agreed,under the latter project, to undertake a study of the long-term developmentof a national transmission system and to examine related institutional andcommercial issues. Disparities between the long-term NPP, national five-yearplans, short-term budgets and actual performance have been substantial.Owing to the lack of resources, fewer projects have been included in thefive-year plans than in the NPP and, as a result of inadequate allowance forescalation and delays in project implementation, still fewer have beenexecuted. Consequently, the shortage of power has become more acute and,over the next decade, India expects its power deficit to increase substan-tially. This deficit has undermined rational planning by encouraging rapidexpansion of supply rather than least-cost development; for example, shortergestation thermal plant has been favored at the expense of lower cost hydro.Furthermore, it has prompted overinvestment in captive plant, a second bestmeasure leading to excessive use of high-value petroleum products for powergeneration. In addition to supporting GOI's efforts to increase the supplyof power, the Bank will continue to stress to GOI the role of pricing andload management in eliminating the deficit, and the importance of integratingplanning and pricing.

Management and Operations

1.10 In contrast to the good performance of NTPC, the SEBs' management andoperational capabilities have not kept pace with the expansion of supply. Ingeneral, SEBs have adequately qualified engineering staff, but lackexpeiienced personnel in financial planning and control. The relatively lowstatus and pay of these personnel exacerbates the already significant paydifferential between the public and private sectors and makes it difficult torecruit competent staff. Management practices are generally outmoded and

inadequate. Accounts have been maintained principally to track cash receiptsand expenditures, and there has been little use of accounting information formanagerial purposes. Consequently, the Bank has encouraged GOI to develop anew uniform accounting system for SEBs. After initial delays, implementationi.s now proceeding. In addition, the Bank will continue to support institu-tional development programs through lending to individual SEBs.

1.11 The operations of many SEBs are hampered by the poor condition oftheir plant and equipment. Factors that have contributed to the poor stateof thermal plant include inadequate maintenance (due to capacity shortages),deficiencies in manufacture, lack of spares, and the poor quality of coal; ingeneral, these problems have been recognized by the relevant authorities andcorrective steps are being taken. Distribution systems have suffered frominadequate maintenance and overloading owing to inadequate investment.Rehabilitation, particularly of thermal plant and distribution networks,appears to be a very cost-effective way to improve efficiency and systemcapacity. GOI is currently preparing a rehabilitation program for thermalplant but is less able to effect improvements in distribution. The Bank willcontinue, whenever appropriate, to include rehabilitation components underloans made to SEBs.

GOI's Strategy in the Power Subsector

1.12 In essence the Five Year Plan constitutes the only formal statementof GOI's energy and power policies. Although formalisation of power policy,in particular, is made difficult by the constitutional arrangement in whichresponsibility for power is shared between Center and states (para 1.07),the Seventh Plan, nonetheless, reflects a broad consensus of the objectivesof energy and power policies. The principal objectives of GOI's energypolicy may be summarized as to: (a) develop energy supplies economically ata rate cowmensurate with growth in the economy and social needs;(b) substitute indigenous energy resources for imported petroleum whereverthis is both technically and economically feasible; and (c) encourage therational and efficient use of energy resources. Although power policy isgoverned by essentially the same objectives, alleviation (or at least con-tainment) of acute power shortages suffered nationwide dominates GOI'sshort-term strategy. Over the longer term, achievement of least-costdevelopment assumes greater importance. In addition to the initial steps ofits long-term strategy, GOI's short-term strategy provides for a number ofspecific measures to address power shortages, including:

(a) rehabilitation of thermal plant - a program involving some 30 plantsis currently being finalized (para 1.11);

(b) accelerating the implementation of ongoing projects - a recentreorganization of Government created a new ministry specificallyto monitor and improve implementation of public sector projects;

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(c) permitting industries to invest in captive generation;

(d) permitting the construction of shorter gestation gas or oil-firedplants (para 1.02), for example the proposed Project; and

(e) improving the quality and reliability ef coal supplies, throughimplementation of the majority of the recommendations of the FazalCommittee (para 1.01).

1.13 GOI's long-term strategy requires a blend of policies designed toaddress investment, organizationall institutional and financiaL issues. Withrespect to investment policy, resource constraints will severely limit thequantum of investment available to the power subsector. The Seventh Planallocation is almost exactly half the sum sought by the Working Group onPower, a sum which was itself inadequate to eliminate power shortages.However, broad agreement within India has been reached on qualitative aspectsof long-term investment policy which will emphasize:

(a) accelerated hydro development (para 1.03);

(b) an increased proportion of investment in transmission anddistribution (para 1.05);

Cc) the formation of a national grid (para 1.09);

(d) coal beneficiation to improve both quality and homogeneity(para 1.01);

Ce) diversification of the modes in which coal for power generationis transported, possible examples include the introduction ofcoastal shipping or slurry pipelines;

Cf) diversification of the fuels used for power generation, GOI nowrecognizes that gas fired plant, especially combined cycle, has aneconomic role to play in system development (para 1.02); and

(g) steady growth in the development of nuclear power (para 1.04).

1.14 Long-term organizational/institutional and financial issues are morecontroversial and GOI still needs to identify clearly defined strategies inthese areas. GOI recognizes the institutional and financial weakness of manyof the SEBs but constitutional constraints limit the rate at which the Centercan bring about improvement. Measures which GOI is following include:

(a) increasing the role of efficient central sector institutions,particularly NTPC (para 1.07);

(b) implementation of a uniform system of commercial accounting forall SEBs (para 1.10);

(c) requiring, through recent amendment of the Act, that SEBs earn arate of return of 3Z after all expenses and interest (para 1.08),a significantly more stringent financial requirement thanhitherto; and

(d) a more receptive treatment of private sector proposals for powergeneration, particularly when it can be demonstrated that suchdevelopments are mobilizing resources which would not otherwisebe available to the public sector.

In addition, GOI is contemplating the formation of a Power Finance Corpora-tion as a financial intermediary serving the subsector. Funds lent by theCorporation r'ould be attractive to SEBs because, at least in part, they wouldbe additional to agreed plan outlays. However, loans would be subject toconditionality designed to improve the efficiency and financial strength ofbeneficiaries.

1.15 GOI recognises that the development and operation of an integratednational grid will be difficult to achieve with the present organization ofthe subsector and, as previously noted (para 1.07), COI is contemplating theformation of a separate body with responsibility for the grid. However, manycommercial and institutional problems remain and, as yet, GOI has no strategyfor their solution; although, under the Rihand Power Transmission Project,GOI has accepted that these aspects of grid development need to be addressed(para 1.09).

Bank Group Strategy in the Power Subsector

1.16 The Bank supports the elements of GOI's strategy identified above butfeels that, while each of these elements is desirable, they do not addressall of the serious deficiencies in the subsector. In particular, additionalefforts are needed to address problems in the areas of planning, pricing/loadmanagement, institutional development and finance. The prevalent nature ofthese problems suggests that a sector-wide approach should be sought.However, the comparative autonomy of the states/SEBs from the Center makes itdifficult to achieve progress in this way. With the exception of the intro-duction of uniform commercial accounting in SEBs, few improvements at thestate level have been realized through umbrella projects coordinated by CEAor REC, primarily owing to the very weak control that these institutions areable to exercise over SEBs. Consequently, the Bank is changing the mix ofits lending to the subsector away from umbrella projects, coordinated by CEAor REC, towards a more direct involvement with individual SEBs, wherestate-specific programs can be designed to address areas of deficiency.Initial experience with individual SEBs suggests that the prospects forimprovement are encouraging in most areas except pricing. Despite espousing

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energy prices "which reflect true costs" in both the Sixth and Seventh Plans,GOI and the states have, until now, opposed the principle of economic pricingof power, for reasons associated with social and agricultural objectives(para 1.08). The Bank will continue to press for improvements in both pric-ing and the other areas identified above, e.g. through finan-ial recoveryand institutional development programs tailored to the requirements ofindividual SEBs. However, as indicated earlier (para 1.08), there is con-siderable resistance to financial reforms within the sector. While the BankGroup will continue to encourage the Central and State Government to improvethe financial performance and viability of the SEBs, it is beginning, as amatter of strategy, to work only with those SEBs that are prepared to intro-duce measures to bring about improvements in their financial condition andperformance.

1.17 In parallel with lending to individual SEBs the Bank proposes con-tinued support for expansion of the central sector, because: (a) increasedreliance of the states on central sector generation appears to be the bestway to encourage decisions at the state level consistent with the nationalinterest; and (b) a high proportion of central sector generation sold ateconomic tariffs will help to improve tariffs to final consumers. The dif-ficulties that GOI has experienced in bringing hydro projects into thecentral sector mean that NTPC will continue to be the main vehicle for theBank's support of the central sector. NTPC's record to date is impressive.However, it is still far from being a mature institution and, owing to itsrapid development, it will continue to face problems in which it couldbenefit from Bank support. As far as CEA is concerned, the Bank feels that areview of its organization and functions would now be timely and, in itsdialogue with GOI, the Bank will discuss the possibility of such a review,coupled with technical assistance to improve CEA's capability to meet itsresponsibilities, which may require redefinition as a result of the review(para 1.07).

1.18 In addition to ridressing areas in which GOI's strategy appearsdeficient, it is approl. ate that the Bank should focus on aspects of thestrategy already adopted, where the Bank can do most to catalyze progress.In this respect specific aspects identified include:

(a) the formation of the national grid - the Bank will continue tosupport projects such as the Central and Rihand Power TransmissionProjects, the latter will afford the Bank the opportunity for anactive involvement in studies of long-term transmission development(para 1.09);

(b) accelerated hydro development - by broadening lending operationsto encompass individual SEBs the Bank is able to support hydroprojects and, where the additionality of the Bank's funds to planoutlays is crucial, it is able to bring about developments whichmight not otherwise take place; and

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(c) elements of strategy that involve concerted action by organizations,both inside and outside the power subsector - the Bank cancoordinate its own lending operations within the differentsubsectors in order to improve intersectoral cooperation. Priorityexamples concern improvements in coal quality and transportation,and the use of natural gas for power generation.

Bank Group Participation

1.19 The Bank has made 21 loans (US$2,709 million) and 17 IDA credits(US$2,409 million) for Indian power projects (Annex 1.3). Nineteen projectshave been completed: 12 generation, 5 transmission, and 2 rural electrifica-tion. Projects currently under implementation include 11 generation, 3 ofwhich are hydro, 2 transmission, 1 rural electrification, and the KeralaPower Project, the most recent project to be approved by the Bank, whichincludes a broad spectrum of generation, transmission and distribution. Withrespect to NTPC projects, the first-phase projects at Singrauli, Korba, andRamagundam were commissioned on or ahead of schedule. The second-phaseextension at these sites, the Farakka and the Rihand Power TransmissionProjects are proceeding satisfactorily. The Third Rural ElectrificationProject, which has suffered significant procurement problems, is about twoyears behind schedule.

1.20 A performance audit conducted in 1980 for the Second Power Transmis-sion Project (Credit 242-IN) concluded that the project succeeded in helpingthe nine SEBs extend their transmission systems to meet their growing powerrequirements. Utilization of generating capacity in these SEBs exceeded theappraisal forecast. However, the audit highlighted the difficulties ofeffecting institutional improvements in the absence of a close workingrelationship between the Bank and beneficiary SEBs.

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II. THE BENEFICIARY - NATIONAL THERKAL POWER CORPORATION LIMITED

2.01 NTPC, the beneficiary of the proposed loan, was established in 1975an a publicly owned utility, under the general supervision of the Ministry ofEnergy. It is responsible for designing, constructing, and operating largethermal power stations and transmission lines, and for the sale of powergenerated to the SEBs. NTPC has broad powers to carry out its operationsexcept for decisions on investment plans and financing which require Govern-ment approval before implementation. NTPC is also subject to periodicexamination by the Committee on Public Undertakings, a body established byGOI to monitor the performance of public sector enterprises.

Existing Facilities and Development Program

2.02 NTPC commenced generating electricity in 1982 and, by the end ofFY85, operated 11 new 200 MW units (5 at Singrauli, 3 at Korba and 3 atRamagundam) and 2,130 km of 400-kV transmission lines. In addition, it hasunder construction 7 power plants with a total capacity of 810C MW and11,000 km of transmission lines; NTPC also operates the 720 MW Badarpurstation near Delhi, and is responsible for construction of the 270 MW captivepower station being established at Korba for the Bharat Aluminium Company, ona management-fee basis. NTPC has formulated a corporate development plan forthe period 1986-2000 reflecting NTPC projects identified in the NPP(Annex 2.1). Although the plan is feasible in terms of NTPC's technicalcapability, it is likely to be revised downwards to reflect the resourcesallocated to NTPC in the Seventh Plan, which is presently being finalized.

Organization and Management

2.03 In response to the rapid increase in NTPC's operational and construc-tion activities, a study to develop a decentralized organizational structurewas initiated in 1981, with assistance from power utilities/ consultants inthe UK and the USA. On the basis of this study, NTPC adopted a regionalorganizational structure in August 1982, with each Region under the charge ofan executive director responsible for the design, construction and operationor generation and transmission facilities. Regional headquarters have beenestablished for:

(a) the Northern Region, with responsibility for the power stations atSingrauli and Rihand, together with the associated transmissionsystem;

(b) the National Capital Region, with responsibility for the powerstation at Badarpur and the planned station at Muradnagar;

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(c) the Western Region, with responsibility for the power stations atKorba and Vindhyachal, together with the associated transmissionsystem;

(d) the Southern Region, with responsibility for the power station atRamagundam and the Southern Regional Transmission System;

(e) the Eastern Region with responsibility for power stations at Farakka,Kahalgaon and Talcher, together with the associated transmissionsysten,.

Recently, NTPC has centralized design and procurement in order to utilizetrained manpower more efficiently. It has also created the post of Director(Projects and Operations) to ensure that adequate attention is given to powerplant operations.

2.04 With decentralization, the corporate headquarters is progressivelyconcentrating its role on policy-making and the provision of functionalguidance to the Regions and operating divisions. The principal corporatefunctions are finance, personnel and administration, planning and monitoringdesign, procurement and commercial. The finance, personnel and design groupsare headed by Directors who are members of NTPC's Board. The procurementgroup is responsible to the Executive Director (Corporate Contracts andMaterials). The planning and monitoring group reports to the Chairman andManaging Director and the commercial group to Director Finance. The presentcorporate organization structure is shown in Annex 2.2.

Recruitment and Training

2.05 Recruitment is progressing satisfactorily and is expected to meetNTPC's expanding operational needs. By April 1985, NTPC had about 14,200employees. This number is expected to reach about 32,000 by the end ofFY'90. Initially, NTPC emphasized the recruitment and training of execu-tives, engineers and supervisors, who account at present for nearly 40X ofits staff. However, with the increase in operating plant, the emphasis hasbeen gradually shifting toward the recruitment and training of skilledworkmen and plant operators, who will account for about 70% of staff byFY'90. Training centers have been established at NTPC's plant locations.These centers, with workshops, training materials, and hostel facilities, aredesigned to train young graduates, diploma holders and operating staff. NTPCalso provides specialized training in management and other aspects of thepower sector at the Centre for Education in Power Management in Delhi, theCentral Institute of Training at Badarpur and other academic institutions.In addition, specific programs are organized in collaboration with powerorganizations of international repute, e.g. the Central Electricity Gener-ating Board (U.K.).

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Performance

2.06 NTPC's construction performance has been satisfactory with most ofthe generating units and transmission lines being completed within theplanned construction time. Such delays as have arisen in projects have beenprimarily due to delays in placement of orders for the major equipment(boiler and turbo-generators) and not in actual construction. Transitionfrom construction to operation is also being carried out successfully. ?TPChas, with the assistance of Central Electricity Generating Board (U.K.),prepared detaiLed procedures for plant commissioning, operation and main-tenance. Major emphasis has been placed on the introduction of maintenanceplanning using computers and standard work procedures. Generating units underoperation have achieved satisfactory generation levels (Annex 2.3). AResearch and Development unit has been established to carry out appliedresearch and to assist in outage analysis.

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III. THE PROJECT

Project Setting

3.01 India's chronic power shortages together with the slow progress inthe implementation of hydro projects (para 1.03) have led to an emphasis oncoal-fired generation projects. Consequently, over the past 14 years theannual consumption of coal used in power generation has risen from 15 milliontons to 65 million tons. This expansion has placed a severe burden on boththe coal industry and the railways with the consequence that deterioratidgcoal quality and transportation problems have increasingly affected theoperation of power plants (para 1.01). In order to relieve some of thepressure on the coal and transport sectors, which would result from increasedreliance on coal-fired plants, the Bank has encouraged COI to review its gaspolicy, which has in the past reserved gas for uses such as fertilizer andpetrochemicals (para 1.02). Economic opportunities to extend the uses of gasare provided by the development of the large South Bassein and satellite gasfields, together with associated gas from the Bombay High field. Natural gasproduction could triple or quadruple in the next decade. A priori, use ofsuch gas for power generation would be attractive for parts of the Northernand Western Regions which are remote from both the coal fields in the east ofIndia and the hydro resources in the far north. To provide the infrastruc-ture necessary for the use of gas, OI has decided to construct a 1,700 kmgas pipeline from Hazira to Jagdishpur, the HBJ pipeline, which will traversethe states of Gujarat, Madhya Pradesh and Uttar Pradesh, with a spur intoRajasthan (Kap IBRD 19105). Although the initial purpose of the pipeline wasto supply gas to six fertilizer plants and a number of liquid petroleumgas (LPG) plants, the prevailing power shortages in both regions (Annexes 3.1and 3.2) and difficulties in coal transport make short gestation, highefficiency, gas or liquid fueled combined cycle plants attractive. In thelight of this, OI has agreed to allow the use of gas for power generationand has sanctioned three combined cycle stations with a total capacity ofabout 1,500 MW. These would be located at Kawas in Cujarat, Anta in Rajas-than and Auraiya in Uttar Pradesh.

Project Objectives

3.02 The objectives of the proposed Project are to:

(a) provide power in the Northern and Western Regions which are currentlysuffering acute power shortages;

(b) diversify the fuels used in power generation, through the use of gasor liquid fuels, in regions which are short of hydro and coal resour-ces;

(c) relieve pressures on the railway and coal sectors; and

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(d) introduce into India combined cycle technology which would providean efficient, reliable, flexible and economic source of power.

Project Description

3.03 The proposed Project consists of:

(a) three combined cycle power stations at Kawas (Gujarat), Anta (Rajas-than), and Auraiya (Uttar Pradesh), comprising combustion tur-bogenerators, heat recovery boilers, and steam turbogenerators, witha total installed capacity of about 1,500 NW (site rated); electricaland mechanical auxiliary equipment; and the provision of associatedcivil works and ancillary facilities;

(b) about 950 km of 220-kV and 375 km of 400-kV single- anddouble-circuit transmission lines connecting: the Kawas station withNavsari, Baruch, and Valthan in Gujarat; the Anta station with Bhil-wara, and Dausa in Rajasthan; and the Auraiya station with Agra andBallabgarh in Uttar Pradesh; together with new or extended substa-tions and associated auxiliaries; and

(c) technical assistance for the engineering, testing and commissioningof the combined cycle power stations.

Details are described in Annex 3.3.

Fuel Supply

3.04 The power stations which comprise the proposed Project will burnprimarily gas but will be constructed with provision for the use of liquidfuels in order to maximize flexibility. Cas supplies will come principallyfrom the South Bassein field which has reserves of about 205 billion cubicmeters and is being developed under Bank financing (Loan 2241-IN). The fieldhas recently been connected to the mainland at Hazira, which is the site forthe gas treatment plant and is close to the proposed Kawas power station.From Hazira, gas will be transported by the BRJ pipeline to inland consumerswhich include six fertilizer plants and the proposed Anta and Auraiya powerstations. The HBJ pipeline, which was appraised by the Bank, is to be imple-mented and operated by the Gas Authority of India Limited (GAIL), a publicsector corporation responsible to the Kinistry of Petroleum. GAIL hasrecently awarded contracts for the supply of pipes and tenders have beenreceived for a turnkey contract for all associated equipment and pipelineconstruction. GAIL expect. to award this contract very shortly. The plannedconstruction timetable is consistent with NTPC's schedule for the threecombined cycle units (para 3.08). In order to ensure coordinated developmentof the HBJ pipeline and the combined cycle units, confirmation by GOI thatthe contract for the pipeline construction has been awarded, would be a

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condition of effectiveness for the proposed loan (para 6.01(a)). In additionGOI agreed that disbursement under the loan would be conditional on signatureof the pipeline construction contract by October 31, 1986 (para 6.02(a)).At the moment OOI's plans for fertilizer development are such that it canonly guarantee 4 million cubic meters per day (MMCMD) of gas for the proposedProject as against the 6 MMCMD required for complete gas operation of thethree combined cycle plants. However, the fertilizer plans on which thisis predicated appear overoptimistic and, in addition, Bank Industry Depart-ment data indicate that the specific consumption of the fertilizer factorieshas been overestimated. It therefore seems very likely that a full 6 MMCMDof gas will be available for power generation. However, in view of thepossible shortfall, provision will, as previously noted, be made for Liquidfuel operation. The Bank is satisfied that, in the absence of gas(para 5.02), such operation would be economically justified. In any caseprovision for liquid fuels (natural gas liquids (NGL) or naphtha) isdesirable in order to cater for possible interruptions to gas supplies.During negotiations GOI gave an assurance that 4 MMCMD of gas wiLl be madeavailable for the proposed Project and that, to the extent that a full 6MNCMD of gas is not available, liquid fuels will be made available (para6.02(b)>.

3.05 To date GOI has not made a formal decision on the way in which gaswill be priced for power generation. However, during appraisal of the HBJpipeline, GOI has intimated that the price of gas for uses other than fer-tilizer would be based on fuel oil parity, which at this time wasapproximately Rs 1,800 per thousand cubic meters (MCM). At least in themedium term, a price related to fuel oil would adequately cover the estimatedeconomic opportunity cost of gas and, in so far as this price may exceed theopportunity cost, it would not cause significant economic distortion (higherplant availability would still leave gas as the preferred fuel) and it wouldbe desirable for reasons of resource mobilization. During negotiations GOIcorfirmed that the minimum price of gas supplied to the proposed Project willbe based on fuel oil Parity (para 6.02(c)). In addition, GOI and NTPC gavean undertaking that supply contracts between NTPC and the appropriateauthorities for the supply of gas for the operation of the proposed Projectwill be concluded at least six months prior to the commissioning of the firstcombustion turbine under the proposed Project. The supply contract will befurnished to the Bank for prior review and comment (para 6.03(a)).

Engineering and Construction

3.06 NTPC has considerable experience in installing and operating thermalpower stations and associated high voltage transmission systems. However,combined cycle units will introduce a new technology and the corporation doesnot yet have tne appropriate expertise. Although NTPC has prepared thebidding documents, it will need assistance in defining performance criteria,evaluating bids, finalizing the design proposed by the selected bidder, andin monitoring the manufacture, testing and commissioning of equipment. NTPC

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would engage consultants, satisfactory to the Bank, to assist them in per-forming these tasks. These technical services, estimated at about 170man-months, would be financed under the proposed Project. NTPC has adequateexperience in the design and construction of 220-kV and 400-kV transmissionlines.

3.07 The stations at Kawas and Auraiya will be located close to the gaspipeline, while, owing to difficulties in water supply, the Anta station willrequire a spur pipeline of about 16 km. Cooling water will be supplied fromirrigation canals with the installation of pondages in order to secure wateravailability during periods of maintenance. In order to reduce water con-sumption the stations will be equipped with cooling towers. The three sta-tions will be located close to major roads and railways, which willfacilitate transport of equipment and materials during construction andliquid fuels, if required, during operation. NTPC is establishing a newdivision responsible for the implementation of the proposed Project. However,design and procurement for the Project would be carried out by specializedgroups in the respective functional divisions of NTPC. Construction would besupervised and coordinated by resident engineers with the assistance ofconsultants as necessary. NTPC will arrange for the timely training ofoperations and maintenance staff either through the equipment contracts orwith utilities operating similar plants.

Project Preparation and Implementation Schedule

3.08 NTPC has completed the basic design for the proposed Project. Bidsfor the major equipment package (combustion turbogenerators, heat recoveryboilers, and steam turbogenerators) were invited in February 1986 and theaward is expected to be announced in December 1986. Land acquisition iscurrently proceeding. Project completion is expected in 1990. The detailedimplementation schedule for the proposed Project is shown in Annex 3.4.

Project Costs

3.09 The estimated cost of the proposed Project, including contingenciesbut excluding duties and taxes, is Rs 14,490 million (US$1,114.0 million).Taxes and duties would amount to about Rs 1,653 million (US$127.3 million).Interest during construction adds Rs 582 million (US$44.7 million) to thefinancing required. The direct and indirect foreign currency costs areestimated at about Rs 9,190 miLlion (US$706 million), equivalent to 55X ofthe total financing required. The estimated costs of the Project are set outin Annex 3.5 and suimmarized in Table 3.1.

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Table 3.1: Estimated Project Costs /a

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

Preliminary and Civil Works 779 57 836 59.9 4.4 64.3Main Electromechanical 2,066 5,346 7,412 158.9 411.2 570.1Equipment

Auxiliary Electromechanical 879 1,050 1,929 67.6 80.8 148.4Equipment

Fuel Supply Equipment 57 117 174 4.4 9.0 13.4Transmission System 1,431 196 1,627 110.1 15.1 125.2Consultancy and 73 68 141 5.6 5.2 10.8Technical Assistance

Engineering and 809 - 809 62.2 - 62.2Administration

Total Base Cost 6,094 6,834 12,928 468.7 525.7 994.4

Physical Contingencies 316 358 674 24.2 27.5 51.7Price Contingencies, 1,070 1,471 2,541 82.8 112.4 195.2Total Project Cost 7,480 8,663 16,143 575.7 665.6 1,241.3

Interest duringConstructionBank - 488 488 - 37.4 37.4Other 55 39 94 4.3 3.0 7.3

Total Financing Required 7,535 9,190 16,725 580.0 706.0 1,286.0

/a Figures may not add due to rounding.

For the combined cycle units, estimates are based on indicative proposalsmade by firms with extensive experience in combined cycle installation andare comparable with recent prices for similar works in other countries. Costestimates for other equipment and materials are based on the most recentquotations received for similar projects with prices updated to end-1985levels. The estimated cost of consulting services is based on currentexperience with other projects in India. The cost of the technical assis-tance for overseas training was determined on the basis of standard pricesprovided by internationally reputable firms. Physical contingencies of 10Zon civil works and 5% on equipment were assumed on the basis of experiencewith similar projects and are considered adequate. Price contingencies forlocal costs are assumed at 7.0% for FY86, 7.52 annually for FY87 to FY90, and5.0% per year thereafter. Price contingencies for foreign costs are assumed

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at 7.5X for FY86, 8Z annually from FY87 to FY90, and 5X per year thereafter.Interest during construction reflects the progressive comissioning of eachpower station.

Project Financing

3.10 The proposed Bank loan of US$485.0 million would provide 43Z of thetotal project cost net of duties and taxes, equivalent to 692 of theestimated foreign cost of the project. The balance of the foreign exchangefinancing requirement, amounting to about US$221.0 million is expected to bemet from external borrowing or COI foreign exchange reserves. The remainderwill be met by NTPC's internal cash generation plus equity and loans fromGOI. Table 3.2 shows the propos'ed financing plan.

TabLe 3.2: Project Financing Plan

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

IBRD Loan - 485.0 485.0GOI/External Borrowing 475.2 221.0 696.2NTPC 104.8 - 104.8

580.0 706.0 1,286.0

COI may also consider suppliers' or export credits for the major equipmentitems if a successful bidder or other agency provides an acceptable financingproposal for the lowest evaluated bid in cash terms. In this event, GOI'scontribution to project financing will be reduced accordingly, and the Bankwould seek to reallocate its contribution toward the financing of these itemsto other items in the project, as appropriate.

Procurement

3.11 Procurement arrangements for the proposed Project are summarized inTable 3.3. The major equipment and works for the combined cycle units, whichare estimated to cost US$893 million, of which US$645 million is expected tobe in foreign currency, would be grouped for each station in a singlesupply-and-erection contract subject to ICB in accordance with Bankguidelines. Auxiliary equipment for the power station and equipmentassociated with the transmission facilities, estimated cost US$265 million,would be grouped in different packages subject to LCB, these items will notbe financed by the Bank. As a result about 72Z of works, goods and servicesfor the proposed Project would be procured under ICB.

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Table 3.3: Procurement Arrangements(US$ Million /a

Project Element Procurement Method /b

I. Civil Works ICB LCB Other Total

Preliminary Works 4.3 4.3Plants Civil Works 23.7 23.7

( 5.5) ( 5.5)Other Civil Works 57.9 57.9

II. Power Plants

Main ElectromechanicalEquipment (Supply & Erection) 852.3 852.3

(463.0) (463.0)Other ElectromechanicalEquipment & Works 34.3 34.3

III. Fuel Supply Equipment 17.3 17.3( 11.3) ( 11.3)

IV. Transmission Lines and 172.9 172.9Substations

V. Consulting Services andTechnical Assistance 11.2 11.2

( 5.2) ( 5.2)

VI. Engineering and Administration 67.4 67.4

TOTAL 893.3 265.1 82.9 1,241.3(479.8) C 5.2) (485.0)

7a Figures in parenthesis indicate the amount to be financed by the Bank.

/b ICB: International Competitive BiddingLCB: Local Competitive BiddingOther: Direct negotiation or not subject to commercial procurement

(e.g. land acquisition, owner expenses)

Documents for individual contracts above US$3.5 million equivalent would besubject to prior review by the Bank. Suppliers competing for contracts forsupply and erection of goods under ICB will have a 15% preference or theapplicable duty, whichever is less on the locally manufactured goods andmaterials. Consultants for project employed in accordance with Bank

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guidelines. Expenditures covering consultancy services incurred sinceJuly 1, 1985, and prior to loan signing will be financed retroactively up toan amount of US$1 million.

Disbursement

3.12 Disbursement from the proposed loan would be made against 100% ofthe cif (ex-factory if manufactured in India) cost of equipment and materialsprocured under ICB, 40Z of the civil and erection works, and 100% of the costof consultancy. The estimated schedule of disbursements is provided in Annex3.6. The disbursement prcfile for the proposed Project is much faster thanthe Bank's standard profile for a power project in India, fishoralf years asopposed to ten, but this is reasonable given the weight of coal-fired powerstations in the latter. The Bank is satisfied that the proposed profilereflects worldwide experience in combined cycle construction, NTPC'simplementation capabilities, and the advanced stage of project preparation.

Ecology

3.13 The operation of the three stations at full capacity should presentno environmental problems. The available natural gas, after sweeteningconsists of almost pure methane with an insignificant sulphur content and noother harmful components. There would be neither atmospheric pollution norash disposal requirements. If liquid fuels are required, those which aremost likely to be supplied (NGL or naphtha) have a low sulphur content andshould not present an environmental problem. Satisfactory environmentalclearances have been obtained for the operation of each plant in the proposedProject covering the use of both gas and liquid fuel and, during nego-tiations, NTPC gave an undertaking to operate the plants included in theproposed Project in accordance with environmental standards prescribed by GOI(para 6.04ta)). Owing to the relatively small size of the steam units and theinstallation of cooling towers, the water requirement for each station caneasily be drawn from irrigation canals i-ithout reducing the quantity allo-cated to other consumers. Safety regulations for power stations will bestrictly enforced, as they are in existing NTPC stations which have a goodsafety record. The combustion turbines will be equipped with adequatesilencing equipment and the turbine halls of the steam turbo-generator com-ponents will have a sound pressure level of less than the maximum acceptablethreshold of 90 decibels. Transmission lines will be designed to keep radiointerference within acceptable limits.

Project Risks

3.14 No unusual risks are foreseen. Combined cycle units are a standardtype of installation which require limited civil works and relatively littleassembly on site. Risk of damage due to fire, explosion, etc. would becovered by the respective contractors during the construction phase, and,

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after commissioning, by NTPC, through its insurance policies which are satis-factory.

Project Monitoring

3.15 NTPC will submit quarterly reports covering the works of the consult-ants, physical progress, costs, disbursements and administrative aspects ofthe proposed Project. In addition, there will be annual financial andadministrative reports.

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IV. FINANCE

Accounting Organization and Systems

4.01 In 1979 NTPC,;assisted by A.F. Ferguson Co. (India), designed andsubsequently implemented well conceived systems for financial and costaccounting, contract accounting and management, inventory control, billing,fixed assets accounting, and payroll. The corporation has establisheddecentralized autonomous accounting organizations at the site of each plantin operation. A.F. Ferguson Co. has monitored the implementation of thesesystems and has assisted in the training of accounting staff. Well designedmanagement information and budgetary control systems were also introduced in1979 and these have been effective in providing the inputs needed for plan-ning and monitoring. An internal audit unit has been established with ade-quate systems and qualified staff. Training of accounting staff is wellorganized, and recruitment of qualified staff is adequate to meet forecastrequirements.

Past Financial Performance

4.02 NTPC initiated its investment program in FY'78 and commercial opera-tions in FY'83. Operations during FY'83 were minimal owing to stabilizationof the new generating units. Despite this, net earnings of Rs 46 million forFY'83 compared favorably with Rs 45 million previously forecast. NTPC'sfinancial performance for FY'84 is presented in Annex 4.3. Sales revenue forthat year was Rs 1,398 million, representing an increase of Rs 96 million(7Z) over previous projections. The higher revenue was due to increasedenergy sales, 3,835 CWh compared to 3,675 CWh previously forecast, and highertariffs, 36.45 compared to 35.45 paise per kWh projected. Total operatingexpenses of Rs 723 million were the same as previously projected, due tolower operations and maintenance costs and lower depreciation offsettingcompletely the increase in fuel costs of Rs 164 million over the previousforecast. The higher fuel bill was attributable to: increased generation;an unanticipated increase in the price of oal; and increased reliance on oilto compensate for shortages of coal during the monsoon period. NTPC istaking measures to stock-pile coal at each station to ensure an uninterruptedsupply and thereby reduce the consumption of oil. Operations and maintenancecosts and depreciation were lower than projected as a consequence of slippagein the initial commercial operation of newly commissioned power stations.NTPC capitalizes costs, other than fuel, during the period between commis-sioning and commercial operation. Similarly, depreciation is charged tooperations only for assets that are under commercial operation. As a resultof the above variances, operating income of Rs 675 million for FY'84 exceededthe previous forecast by Rs 96 million (17%), yielding a financial rate ofreturn on unrevalued assets of 11.3Z. The rate of return compares favorablywith the 7Z minimum required for FY'85-90 under Loans 2442-IN and 2555-IN andcorresponds to a rate of return on revalued assets of approximately 5.4Z for

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FY'84, which is satisfactory for a relatively young utility. Net profits ofRs 449 million exceeded the previous projections by Rs 253 miLlion, owing tothe favorable variance in operating income and a decrease in interest expenseon GOI loans.

4.03 Cash generation as a percentage of investment, was 5Z in FY'83 and 3%in FY'84 (Annex 4.2). The low contribution to investment was solely due tothe scale of existing operations compared to the very large investmentprogram. Capacity under operation is currently 27X of capacity under con-struction (para 2.02).

4.04 NTPC's collection of accounts receivable has been unsatisfactory.As of December 31, 1985, outstanding receivables represented about 3.8 monthssales. Under the bulk supply contracts governing the sale of NTPC's power,customers are required to open irrevocable revolving letters of credit for anamount equivalent to one month's power purchases and to remit payment forpower purchases not covered by letters of credit within 30 days of receivingbills from NTPC. At present, all of the customers in the Northern, Westernand Southern Regions have opened letters of credit except for the SEBs ofRajasthan and Haryana and the Electricity Department of the Union Territoryof Goa. NorT of NTPC's customers in the Eastern Region. has yet done so asbulk supply contracts for these were concluded only recently and the Farakkaplant is yet to be commissioned. It was agreed during negotiations thatletters of credit for the remaining customers would be opened within sixmonths (para 6.04(b)). In regard to the letters of credit already opened byNTPC customers, the amounts of these in most instances are less than theamounts required by the terms of the bulk supply agreements. NTPC agreedduring negotiations that all necessary steps would be taken to obtain fromits regular customers, to whom power has been allocated, revised letters ofcredit reflecting the equivalent monthly value of their power allocations(para 6.04(b)). With regard to the arrears arising from sales of electricityprior to the bulk supply agreements, when electricity was sold at interimrates subject to subsequent adjustment, NTPC has furnished to the Banktimetables providing for the repayment of these arrears by March 1987. Duringnegotiations NTPC agreed to take all steps necessary to maintain its accountsreceivable, arising from sales of electricity subsequent to the conclusion ofbulk supply agreements, at a level not exceeding an amount equivalent to theproceeds of its power sales for the two preceeding months (para 6.04(c)).

4.05 NTPC's fixed assets as of March 31, 1984 amounted to Rs 22,794 mil-lion, comprising work-in-progress of Rs 13,767 million and plant in operationof Rs 9,197 million (Annex 4.4). The debt to equity ratio of 26/74 is satis-factory. Net working capital at March 31, 1984 was negative (Rs 359 mil-lion), owing to a high level of current liabilities (Rs 2,142 million) at theyear-end. This is not typical of NTPC's net working capital position, whichis satisfactory, but represents a year-end phenomenon arising from a peak insupplier billings coupled with a lag in GOI's release of the corresponding

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funds. With the exception of accounts receivable, NTPC's financial perfor-mance during FY'83 and FY'84 was satisfactory.

Future Investment and Financing 1/

4.06 NTPC's capital expenditure for the period FY'77-'96 is expected toamount to Rs 405,000 million (US$31,145 million) (Annex 4.1). Its totalexternal financing requirements will be met by GOI's equity contribution ofRs 134,000 million, and by long-term loans of Rs 176,000 million. Foreignfinancing is expected to contribute approximately 30% of financing require-ments. Internal cash generation is also projected to contribute about 30%,increasing from about 3% in FY'84 to almost 40% in FY'92 (Annex 4.2). Thelower ratio of cash generation to capitaL investment during the earlierperiod is due to the high level of capital expenditure relative to the valueof assets in operation (para 4.03). Rapid changes in the levels of bothoperations and capital investment make cash generation a volatile and unreli-able measure of financial performance. However, as NTPC becomes a moremature utility cash generation will tend to stabilize. It is expected tolevel-off at about 40% in the mid-1990's. Dividends on equity are notanticipated and it has been assumed that surplus funds will be applied to theinvestment program. NTPC's financing plan (Annex 4.2) is satisfactory.

Future Financial Performance

4.07 Projected income statements for NTPC are presented in Annex 4.3 (withassumptions in Annex 4.8). Generation is projected to increase from4,267 GWh in FY'84, to 55,420 GWh in FY'91, and to 98,202 GWh in FY'96. Theaverage tariff is forecast to increase from 36.5 paise/kWh to 68.5 paise/kWhand to 93.5 paise/kWh for the same years, respectively. The increase in theaverage tariff represents annual growth of about 8.5% between FY'83 and FY'96(Annex 4.7), which exceeds the expected rate of inflation. This wouldincrease the average tariff from just below to just above the estimated LRMC(para 4.11). Revenue is projected to increase from Rs 1,398 million inFY'84, to Rs 35,036 million in FY'91, and to Rs 84,842 million in FY'96.

4.08 Operating expenses are projected to remain relatively constant as apercentage of revenue; 52% for FY'84, 59% for FY'91, and 53% fc.r FY'96.Operating income is projected to increase from Rs 675 million n FY'84, toRs 14,424 million in FY'91, and Rs 39,889 million in FY'96. This would yielda financial rate of return on unrevalued net assets in operation of about11.3Z in FY'84, 11.5% in FY'91, and 15.0% in FY'96. Between FY'84 and FY'91,the projected rates of return vary between 7.81 and 13.5% owing to the factthat common facilities, to serve all units at a station, are completed and

1/ All figures relating to projections are expressed in current prices.Refer to Annex 4.8 para 2(c), for the escalation factors used.

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transferred to assets in operation prior to the comnissioning of many of theunits to which they relate. Both the rate of return and internal cash gener-ation (Annex 4.2) would increase together to reach acceptable levels of about14Z and 42%, respectively, by FY'93. During negotiations? NTPC agreed toachieve annual rates of return on unrevalued net assets in operation of notless than 7S through FY'90, 9.5% in PY'91 - FY'95, and thereafter, rates ofreturn at levels satisfactory to ensure the financial viabilit of NTPC(para 6.04(d)). It was agreed, on the basis of current projections, that byFY 96 a rate of return of 14-15Z would be needed to ensure such financialviability. In each of the years FY'85 to FY'90, a rate of return of 7% onnet unrevalued assets would reflect positive net income after interestexpense, and cash generation after debt service. Even if ?TPC were toachieve only the minimum 7% rate of return during this period, it would notadversely affect the investment program, as GOI has undertaken to cover anyresulting deficiency in financing. The equivalent rates of return on netrevalued assets, based on a pro-forma revaluation (Annex 4.6), are about 5Xin FY'84, 7% in FY'91 and 8% in FY'96, which are satisfactory. GOI continuesto oppose the principle of revaluation of assets operated by public sectorundertakings. The Bank, however, will continue to covenant higher rates ofreturn on unrevaluated assets that would normally be sought on revaluatedassets in order to compensate for the lack of revaluation and to allow NTPCto provide adequately for the replacement of assets.

4.09 Net earnings, after interest expense, were Rs 449 million in FY'84,representing about 32% of sales revenue. They are projected to increase toRs 6,836 million in FY'91 and to Rs 24,257 million in FY'96 representingabout 20. and 29% of sales revenue respectively. The ratio of net earningsto sales improves in the later years owing to loan repayments and the result-ing reduction in interest. NTPC's projected financial performance and cashgeneration are satisfactory.

4.10 Forecast Balance Sheets for FY'85 - FY'96, are presented inAnnex 4.4. Statements of sources and application of funds are provided inAnnex 4.5. Table 4.1 summarizes NTPC's financial position at: March 31,1983, the year in which NTPC comenced commercial operations; March 31, 1991,the end of the fiscal year in which the proposed Project would be completed;and March 31, 1995, the first full year in which all generating units, of theprojects presently approved by OI, would be operating at full capacity.This Table shows that in FY'83 total capitalization was Rs 15,050 million(US$1,158 million), divided between GOI loans (including the onlending ofBank Group credits and loans) and equity in a ratio of 21/79. Eight yearslater (March 31, 1991), when the proposed Project will be completed, totalcapitalization is expected to rise to Rs 197,311 million (US$15,188 million),reflecting a debt/equity ratio of 44/56. The debt/equity ratio is expectedto drop to 39/61 by March 31, 1995, at which point capitalization would haveincreased to Rs 345,196 million (US$26,554 million). The lower debt/equityratio in FY'83 compared to FY'90 is attributable to the drawdown of projectequity financing prior to loan financing. For this reason, also, the debt

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service coverage (Annex 4.5) is projected to decrease from 3.5:1 in FY'84 to2.3:1 in FY'91. However, owing to reductions in principal outstanding itwill increase to 2.5:1 by FY'95. Projected debt/equity ratios and debt serv-ice coverage are satisfactory. Current liabilities are projected to include2.5 months capital expenditure to reflect NTPC's typical year-end position(para 4.05). Net working capital, consequently, is projected as negative atthe end, of years from FY'85 to FY'88. In the subsequents years, however,the projections reflect positive net working capital owing to growth inoperations.

Table 4.1: Financial Position of NTPC

At March 31st FY'83 FY'91 FY'95(Re Million)

Fixed Assets in Operation at Cost 3,036 149,309 287,560Less: Depreciation (68) (12,530) (38,805)

Net Fixed Assets in Service 2,968 136,779 248,755Work-in-Progress 12,758 58,207 83,379

Total Net Fixed Assets 15,726 194,986 332,134

Short-Term Deposits - - 9,094Working Capital (702) 2,325 3,968Deferred Preliminary Expenses 26 - -

Total Net Assets 15,050 197,311 345,196

Financed By:

Equity Share Capital 11,810 92,351 133,545Retained Earnings 46 18,796 76,657Total Equity 11,856 111,147 210,202

Long-Term Debt (including IDACredits/IBRD Loans) 3,194 86,164 134,994

Total Capitalization 15,050 197,311 345,196__== =__

Debt/Equity Ratio 21/79 44/56 39/61

Regional Tariffs

4.11 A detailed comparison of NTPC's projected regional tariffs with LRMCsfor FY'85 - FY'96, is provided in Annex 4.7. The LRMCs, in FY'85 prices,

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have been escalated to be comparable with the regional tariffs, which includea fuel price adjustment component, and have been expressed in current prices.NTPC's average tariff is expected to increase from 97% of LRMC in FY'85 to105% in FY'88. Thereafter, it averages a little over 100% of LRMC. AlthoughNTPC's regional tariffs as a proportion of LRMC encompass a slightly widerrange, the average for each of the regions is close to 1002. NTPC'sprojected regional tariffs are generally lower than the projected costs ofgeneration for the SEBs. However, there are likely to be times when someSEBs' short-run marginal costs would be lower than NTPC's full tariff. Thisissue is addressed in paragraph 4.13.

Comercial Arrangements for Sale of Power

4.12 Under previous loans and credits, GOI and NTPC agreed to sell powerfrom NTPC's power plants under contracts satisfactory to the Bank. Thesehave now been concluded with the Delhi Electricity Supply Undertaking, theDamodar Valley Corporation, the Electricity Department of the Union Territoryof Goa, and all SEBs designated to receive power from NTPC plants. TheElectricity Department of the Union Territory of Pondicherry is not expectedto receive power from NTPC until early 1988. A contract in respect of thisentity is therefore not yet required but will be concluded at the appropriatetime. GOI and NTPC agreed, under Loan 2555-IN, to revise bulk supply con-tracts to incorporate additional provisions regarding contract renewal,tariff revision, return on equity, and introduction of capacity charges at anappropriate time (Annex 4.9).

4.13 NTPC's role in the generation and transmission of electricity isforecast to increase substantially. This will impose new requirements onthe bulk supply tariff structure and, in this context, issues which need tobe addressed include: (a) the potential multiplicity of tariffs - the exist-ing regional bulk supply tariff is set on a station specific basis, reflect-ing the fact that NTPC is presently operating only one station in eachregion. This approach would result in a multiplicity of tariffs with thecommissioning of additional plants in each region; (b) recovery of transmis-sion costs - there is no provision in the existing tariffs for recoveringcosts of transmission facilities that are not associated with specific gener-ating stations; and (c) merit order operation - SEBs, which at times havesurplus generating capacity (e.g., at night during the monsoon), find itcheaper to incur their own short-run marginal costs and avoid the "full" NTPCtariff even though NTPC's short-run marginal costs are lower than those ofthe SEBs. This leads to operation of plant out of merit order, consequentlywasting resources. GOI has appointed a committee to address certain aspectsof NTPC's tariffs. During negotiations COI and NTPC agreed to submit a copyof the comittee's report to the Bank by March 25, 1986, and to carry out, inclose cooperation with the Bank, such additional studies as may be necessary,concerning the bulk supply tariff structure, addressing inter alia issuesarising from NTPC's expansion and in accordance with terms of reference andtimetables to be agreed by August 31, 1986 (para 6.03(b)).

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Taxation

4.14 NTPC is liable for income tax. However, in view of its large capitalexpenditure program, tax relief is provided well beyond the period of thefinancial projections. A tax equalization reserve is, therefore, not neces-sary.

Bank Loan for the Proposed Project

4.15 The Bank loan for the proposed Project would be onlent to NTPC by GOIin accordance with a Subsidiary Loan Agreement which will provide for amaturity of 20 years, including a grace period of 5 years, and repayment ofprincipal in equal semi-annual installments, with interest payable on out-standing balances at not less than 13% per year. This minimui onlending rateprovides sufficient margin over the current Bank rate of 8.5% to cover theforeign exchange and interest rate risks which are to be borne by GOI. Theconclusion of a Subsidiary Loan Agreement satisfactory to the Bank would be acondition of effectiveness of the proposed Bank loan (para 6.01(b)).

Audit

4.16 NTPC's auditors are appointed by the Company Law Board, on the recom-mendation of the Comptroller and Auditor General of India and are normallvmembers of the Indian Institute of Chartered Accountants. The auditors'report is subject to review and comment by the Auditor General. For FYs 83and 84 the appointed auditors were P.K. Naheshwari & Co. and Goel, Garg &Co., both firms of Chartered Accountants. The audited financial statementsand auditors' report for FY'83 and FY'84 were satisfactory to the Bank. Theauditors' reports contained no substantive recommendations or adverse com-ments. As with previous Bank Group credits and loans, NTPC's agreed duringnegotiations to provide the Bank with audited financial statements withinseven months of the end of the fiscal year to which they relate, togetherwith a certified report by the auditors, and comments of the Comptroller andAuditor General of India (para 6.04(e)). NTPC has complied with this under-taking for FY'84 and prior years.

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V. PROJECT JUSTIFICATION AND ECONOMIC ANALYSIS

Least Cost Analysis

5.01 Each of the Northern and Western Regions is large enough to accom-modate unit sizes based on the largest combustion turbo-generators availableand economies of scale dictate 'that these should be chosen. The range 95 KW- 115 MW (site rated) has been specified to ensure competitive bidding amongmanufacturers with different standard frame sizes. The size of the heatrecovery boilers and steam turbo-generators is governed by that of the comr-bustion turbo-generators.

5.02 With the aid of the optimization model WASP-II1, CEA has preparedleast-cost system expansion plans for the Western and Northern Regions, basedon the load forecasts kiven in Annexes 3.1 and 3.2 respectively. The assump-tions used, including the load forecasts, and the results of the optimizationmodelling have been reviewed by the Dank and found satisfactory. With anopportunity cost of gas based on fuel oil parity, the earliest feasibleimplementation of Kawas, in the Western Region, and of Anta and Auraiya, inthe Northern Region, form integral parts of the respective least-costdevelopment plans. Even if these plants were to burn NGL or naphtha ratherthan gas, the cost of electricity at the relevant load centers would becomparable with any other source of supply and the combined cycle plants havethe added advantages of short gestation, given the chronic power shortages,and low capital cost per kW, given the budgetary constraints facing COI andthe states.

Internal Economic Rate of Return

5.03 Benefits of the three stations included in the proposed Projectcannot readily be separated from those of other investments in generation,transmission and distribution in the Northern and Western Regions. There-fore, having established that the stations in the proposed Project form partsof the least-cost expansion plans for the Northern and Western Regions, it isappropriate to carry out a cost-benefit analysis on each of the plans inorder to ensure that the expansions envisaged are desirable. For this pur-pose, 'time-slices" of the Northern and Western Regions' investment programshave been analyzed. Capital costs of the investment programs (coveringgeneration, transmission and distribution) together with incremental operat-ing and fuel costs are given in Annes 5.1. The benefits of the investment

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programs relate mainly to the incremental consumption which they make pos-sible. 1/ A minimum measure of benefit, ignoring consumer surplus, can bederived from incremental sales revenue. 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 Northern Region program is 3Z and by theWest'-n Region program, 7%.

5.04 However, these estimates are more a reflection of the inadequacy oftariffs than of the economic merit of the investment programs. The estimatedminimum economic rates of return, 3% and 7Z, are less than the establishedopportunity cost of capital, and this is indicative of the fact that tariffsto consumers in both Regions are presently less than LRMC (para 1.08). Inreality the program will confer benefits in excess of those described above.There will be consumer surplus associated with the incremental consumption;consumer's reactions to the severe shortages of power experienced at present,and expected for the foreseeable future, suggest that willingness to paysubstantially exceeds present tariff levels. In addition there will typi-cally be other external benefits.

5.05 In order to derive more realistic internal economic rates of return,it is useful to estimate a measure of consumer surplus, at least forindustrial and agricultural consumers. Their willingness to pay will berelated to the costs of autogeneration and diesel pumping respectively. Manyconsumers are presently observed to find these options economic when publicsupply is not available. Annex 5.1 presents an estimate of dieselautogeneration costs at Rs. 1.12IkWh. It wouLd, however, be unreasonable toassume that all industrial consumers would be willing to pay this price forthe whole of their consumption from the public supply system. Therefore, asa conservative measure, it has been assumed that the consumer surplusattributable to incremental sales in each Region can be derived from anaverage of the cost of autogeneration and the prevailing tariff. Similarly,for agricultural consumers the equivalent cost of diesel pumping has beenestimated at Rs. 2.21/kWh and average willingness to pay has been estimatedat halfway between the average agricultural tariff in each Region and thisalternative cost. This more realistic measure of the benefit of consumptionresults in an internal economic rate of return of 12% for the Northern Regionand 13% for the Western Region. However, it must again be stressed that

1/ The programs may also lead to benefits in terms of a reduction in thecost of meeting existing demand, particularly through fuel savings.However, the energy deficit is such that by far the greater part of theoutput available from plants in these programs will lead to increasedsales. Fuel savings resulting from these programs are likely to be smalland this element of the benefits has therefore been ignored.

-32-

these represent lower bound estimates as domestic consumer surplus and otherexternal benefits, have still not been included.

Justification for Bank Involvement

5.06 The proposed Project represents the culmination of a dialogue withGOI in which the Bank has encouraged a more flexible policy on the use ofnatural gas for power generation (para 1.02). Through this Project the Bankwould be supporting GOI's objectives (para 3.02) of:

(a) alleviating acute power shortages in the Northern and WesternRegions;

(b) diversifying fuel supply to the power subsector;

(c) relieving pressures on the railway and coal sectors; and

(d) introducing into India the reliable, flexible and economic tech-nology of combined cycle plant.

In addition, through its involvement, the Bank would:

(a) ensure that the price paid for gas by NTPC, and therefore NTPC'stariffs, would adequately reflect the economic value of gas (para3.05);

(b) support the continued financial viability of NTPC by measuresto contain accounts receivable (para 4.04); and

(c) cause GOI and NTPC to address aspects of NTPC's tariffs that willrequire amendment as NTPC expands (para 4.13).

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VI. AGREEMENTS AND RECOMMENDATION

Agreements

6.01 The following would be conditions of effectiveness of the proposedloan:

(a) award of the contract for construction of the HBJ pipeline(para 3.04); and

(b) conclusion of a Subsidiary Loan Agreement between GOI and NTPC satis-factory to the Bank (para 4.15).

6.02 During negotiations, GOI:

(a) agreed that disbursement under the loan would be conditional onsignature of the contract for construction of the HBJ pipeline byOctober 31, 1986 (para 3.04);

(b) gave an assurance that 4 MMCMD of gas will be made available for theproposed Project and that, to the extent that a full 6 MMCMD of gasis not available, liquid fuels will be made available (para 3.04);and

(c) confirmed that the minimum price of gas supplied to the proposedproject would be based on fuel oil parity (para 3.05).

6.03 During negotiations, COI and NTPC:

(a) gave an undertaking that supply contracts between NTPC and theappropriate authorities for the supply of gas for the operation ofthe proposed Project will be concluded at least six months prior tothe commissioning of the first combustion turbine under the proposedProject. The supply contract will be furnished to the Bank for priorreview and comment (para 3.05); and

(b) agreed to carry out in close cooperation with the Bank studies asmay be necessary concerning the,bulk supply tariff structure,addressing inter alia issues arising from NTPC's expansion and inaccordance with terms of reference and timetables to be agreed byAugust 31, 1986 (para 4.13).

6.04 During negotiations, NTPC:

(a) gave an undertaking to operate the plants included in the proposedProject in accordance with environmental standards prescribed by GOI(para 3.13);

-34-

(b) agreed to obtain letters of credit from those customers which havenot yet opened them within six months, and for letters of creditalready opened, obtain revised letters of credit reflecting theequivalent monthly value of pawer allocations where existing lettersof credit are below these amounts (para 4.04);

(c) agreed to maintain its zccounts receivable, arising from sales ofelectricity subsequent to Whe conclusion of bulk supply agreements,at a level equivalent to nat more than two months' sales of power(para 4.04);

(d) agreed to achieve annual rates of return on unrevalued net assets inoperation of not less than 7% through FY'90, 9.52 in FY'91 throughFY'95, and thereafter annual rates of return at levels satisfactoryto ensure the financial viability of NTPC (para 4.08); and

(e) agreed to submit to the Bank audited financial statements withinseven months of the end of the financial year to which they relate,together with a certified report by the auditors and comments of theComptroller and Auditor General of India (para 4.16).

Recommendation

6.05 Subject to the above conditions, the proposed Project is suitable fora Bank loan of US$485 million.

INIA

CQ SD :l1J ._t110f JECT

D t =.'5t EX 26 "^61 "'t6 ='62 tY'7Y FY'79 FYELM FV81 n'82 n'83 FY'84 a'8(Prow.) (Tenta- (Tents-

xi Zs Zs tive) tihe)

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 42,440(Utilities)

Electricity Generated 5,858 9,662 16,937 32,990 47,433 66,689 k02,523 104,627 110,821 122,010 130,211 139,896 156,633(GClb)

Electricity Consumption 4,793 7,959 13,953 26,735 37,352 50,246 77,293 78,124 82,473 90,237 95,917 102,684 A(Cwh)(Utilities only)

Per Capita Generation 20.80 30.90 43.90 73.81 97.82 126.26 159.60 160.00 166.20 182.00 183.00 192.70 211.38(kwh)

Per Capita Consumption 12.30 20.70 31.90 53.70 70.80 87.15 120.48 119.40 123.70 132.00 135.00 141.48 NA(Wh)(Utilities only) w

Consuuption Patternj().

Domestic Light & 12.40 11.70 10.70 8.80 8.50 9.20 9.80 10.76 11.28 11.50 12.48 12.88 NASmall Pover

Coercial Light b 6.90 6.80 6.10 6.20 5.70 6.00 5.60 5.96 5.95 5.98 6.29 5.89 NASmall Pover

Industrial Power 63.70 66.90 69.40 70.60 69.30 64.60 61.35 58.86 58.75 58.75 55.80 56.68 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 3.86 NA

Agriculture Pu'eps 4.30 4.00 9.30 7.10 9.30 12.60 15.56 17.23 17.48 16.71 18.55 17.72 NA

Public Water Works,Sewage Pumping, PublicLighting & Others 5.80 5.50 3.90 3.30 3.90 4.60 4.86 4.24 4.28 4.28 4.10 2.97 IA

QLQ.Q,QQ 1Q.LQQ LQQLQ !IQ_QQ 00.00 LQo,Q lQ,..Q 1000 0LQ.00 1o.Q0 100.00 100.00 NA

_ - -_ --_- -________________________

NA - Not Available

source: C8A, June 1985

INDIA

!!I6 n187 'E[8 ttS8q FO nslk n:22 UY'3 n'

Inem

Northern 54, 549 61, 375 67, 538 74,073 81, 086 89, 218 98, 178 108, 055 118, 945 130, 953Weatern 53, 097 59, 084 64, 538 70, 416 76, 678 83, 744 91, 467 99, 913 109, 148 119, 245soutbern 47,188 53,681 58,817 63,943 69,296 75,920 83,188 91,160 99,907 109,505Eeatern 25, 869 29, 525 32, 440 35, 650 38, 889 42, 831 47, 194 52, 021 57, 366 63, 287Worth-Estern 1,991 2,407 2,712 3,038 3,389 3,744 4,135 4,563 5,035 5,550Andatan and 23 26 30 33 37 41 46 52 58 65

licobar IslandsLaksbadveep 3 _3 _3 4 4 .6 7 8

All Indla (TOTAL) 182,720 206,101 226,078 247,157 269,379 295,503 324,214 355,770 390,466 428,613

(NW)

Northern 10,643 11,975 13, 179 14,455 15,825 17,415 19, 167 21,098 23,227 25,576Veatern 9,184 10,220 11,245 12,273 13,459 14,701 16,058 17,542 19,165 20,938Soutbern 8,558 9,707 10,620 11,534 12,485 13,675 14,982 16,414 17,986 19,711Eastern 4,505 5,134 5,640 6,196 6,757 7,442 8,202 9,043 9,974 11,006Nortb-Eastern 432 536 599 667 740 814 895 983 1,080 1,185Andan and 7 8 8 9 10 11 12 14 16 18

NLebar IllandsLakabadveep 2 2 2 2 -2 -1 3 34All IndLa (TOTAL) 33,330 37,582 41,293 45, 136 49,278 54,060 59,319 65.097 71,451 78,438

source: CIA

INDIA

- C_ 5=UCT. GKEPWC

Previaus Loana and Credits to Indian Pover Seetor (June 30. 1985)

Approval Closing Loan Amcnt

_____ttUC '- t D ur-'UL Dale Dete Status

India First DWC - Sokro - Fonar 23 4150 2156 18.50 16.72 CompleteIndia Second WC - Haithon - Panchot 72 1/53 6/58 19.50 10.50 CompleteTate Trombay Power 106 11/54 9166 16.20 13.85 CompleteTate Secoad Trembay 164 5/57 9166 9.80 9.66 CompleteIndia Third DWC - Durgapur 203 7/58 6/65 25.00 22.00 CompleteIndia Koyas Power 223 4/59 4/65 25.00 18.70 CompleteIndia Power Tranamission 416 6/65 12/70 70.00 50.00 CompleteIndia Second Kotbagudm Power 417 6/65 12/70 14.00 13.97 CompleteIndia Third Trombay Thermal Pover 1549 4/78 12/84 105.00 42.04 CompleteIndie RaXagundm Thermal Power C') 1648 1/79 12/85 50.00 6.05India Farehka Thermal Power C') 1887 6/80 3/87 25.00 0.00India Second Raesmandam Thermal Pover (*) 2076 12/81 6/88 300.00 37.59IndLa Third Rural Electrifieation 2165 6/82 6/86 304.50 65.99India Upper Indrovati Hydro 2278 5/83 6/91 156.40 .39India Central Pover Transu ioLan C') 2283 5/83 3/89 250.70 .63India ldira Sarovar 2416 5/84 6/92 157.40 0.00IndLa Second Farskkh Therml Power C') 2442 6/84 12/91 300.80 . 0.00Tate Fourtb Trombay Thermal Power 2452 6/84 6/90 135.40 0.00India Chandrapur Thermal Power 2544 5/85 12192 300.00 0.00 1.Indio Rihand Power Treaneaiaion (') 2555 5/85 12/89 250.00 0.00 aIndia Kerala State Power 2582 6/85 9/91 1. 6..0 -

Total 2 709.20(Total Loans for NTPC Projects) (1,226.50)

IDA Credit.

India Fourth W C - Durlapur 19 2/62 12/69 18.50 19.88 Complet*India Secoud Koyna Power 24 8/62 9/70 17.50 21.10 CompleteIndia Kotbagudea lower 34 5/63 12/68 20.00 24.13 CompleteIndia Sees Equipment 89 6166 6/74 23.00 26.32 CompleteIndis SeCond Power Traemrisajon 242 4/71 3/77 75.00 72.93 CompleteIndia Third Power Traniajslion 377 3/73 9/78 JS.OO 85.00 CompleteIndia Rural Electrification 572 7/75 12180 57.00 57.00 Coeplet-India Fourth lower Transmission 604 1/76 6/83 150.00 149.87 CempleteIndia Singrauli Thermal Power C') 685 3/77 12/83 150.00 150.00 CoepleteZudia Korba Thermal Power (*) 793 4/78 3/85 200.00 182.32India 2aegund*a Thermal Power (*) 874 1/79 12/85 200.00 200.00India Second Rural Electrification 911 5/79 3/84 175.00 171.75India Second Singrauli Thermal Power t*) !027 S/8W 3/88 300.00 178.87India Farakka Thermal Power Ca) 1053 6/S0 3/57 225.00 150.06India Second Korb& Therml Power (a) 1172 7/81 12/89 400.00 88.11India Upper IndraWati Hydro 1356 5/83 6/91 170.00 12.91India Idits Saroevar SFO10 5/64 6/92 122.00 -India lndira Sarovar 1613 5/85 6/92 13 20

Total 4622(Total Credits for hTPC Projects) (1,475.00)

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U7MuDSW FMN P L TOINE LINITOJ

SCNEJ OF CUUIU3IEI U PMt PUITS

MUg SY FICM. uRn

coUIUlIU2W InCIEOULICAA. WmI DATE S IM1 1913 19164 IMU 1934 1917 1906 1911 199 1991 119 191 1996 199 1991 199 391 2 230

IMIN~ INAt.CAP.RE6.1 Apr-9l '.30 210FAIMUK If Jul-91 100 500mAKIM. J.-91 210 210NUAMIMIM (NAT.CW.REI.3 Oct-93 210 233KANMIM Dec-92 220 210fALOE Jo-92 100 500

FARM II 2 Jul-92 5so 50iiauwO Jia-93 500 100

INOtIFIED EONWP00T 64 J.n-94 500 500IETIPIFI3U KNPOW' 66 Nar-94 100 so_ _ 0

KIIIiF2EiENUPOO'T 19 Apr-94 500 0IKUTIFIED EU PWIOT it Okt-94 5005)lIUflEin Ku PO 66'35 Oct-94 500 500IKNHPFIE3 NEU P03'1 64 Jia-95 500 500IDINTIFIED EU P003'T N Nar-95 S00 500

3D1112P313EU P403'! 5-005IKITIFIB NEU PWIOT 01 ct:9 S00 506IKNTIFIES KM P003'! 34 Oct-95 500 5IKNUTIFIED EU HRW'T 32 Jia-96 100 5

I3III2FIE EU 6W'?320 pr-96 500- ------ 1---------------00-----------2KUT!VIES EU P1'? 63 Jul-Yb 500 50023ENTIF2EI NEV POJ'T 16 kct-96 500 100EINT3FIBD KU P103'T 2 he,-97 500 so0

iKUlIFiED EU POW"'! 620 Apr-17 500 02IKT2F2ED EW POOP? 63 Jul-97 500 503

IEUIIPIID Km p2wOJ'137 Apr-91 500 0IKUTIFIB WV PIOJ'T III Oct-91 500 __ _ 00

IKENTIFIED NEW P103'T @7 A-19 500 500IKNT2FIED NEW P003'?0 63 ct-99 500 s

TOTAL IDENTIFIED I AIPIOED 34,670 200 600 3,000 400 400 200 1,920 3,520 1,720 2,070 1,140 3,000 0 0 0 0 0 0 63311.NEUPIW'S-Ml YET SDIAPP'D 32,000 0 0 0 0 0 0 0 0 . 0 0 0 0 3,500 2,500 2,000 2,000 1,000 2,000 1,000

TOTAL CAPACITY A0010 IN) 25,370 200 600 2,000 400 400 200 1,920 3,520 1,720 2,070 1,340 3,000 3,500 2,500 2,000 2,000 2,000 3,000 3,000

TTLCMNATIVE CAPACITY (NVI) 200 3( 30 20 60 90 42 20 160 12030 13070 14070 11370 180 200 227 230 250 230

AT FtLLY STAUILIZED LEVEL 142,295 3,300 4, 400 9,900 12,200 24,300 15,400 25,910 45,320 54,730 i1, 115 71,215 32,131 90.035 103,7K3 114,78KAS PER POOJECI3ONS 0 1,101 4,267 9,232 31,972 14,033 23,219 30,334 43,013 55,420 15,912 74,000 79,701 *,139 93,202

UNDER FILLL CAPACITY (BUl) (2,3003(3,291) 15,6333 12,3432 12,3232 12,369) (7,792) 115,3181 '11,7172 110,7453 (10,333) 17,735) (10,334) 115,1113 121,563)

-200.01 -74.31 -56.91 -23.71 -16.31 -3.92 -30.02 -33.52 -22.41 -16.22 -13.51 -9.51 -32.52 -35.22 -14.421,

INDIACOMIUNED CYCtE POWER PROJECTNfon Iwn?m Pooq CoMw~

OM-gwiond Unctw.

-4 ~ ~ ~ ~ ~ ~

EII

ii _~~O_

.1~~~~1

m m m | | t m t

v~t mm lUllo vll

1153303 P1*30 Is istiSVc CIPICIVI Oil gYfLl3IAY30 DiIM3Uf FM iicitm

"tat Hs as mmCm 21,3,6, 1 FT 615 M015 is or KicK 23.0114 Is Fl 1162 011110 II

or II15361111 111ioAlAl I tIUl M0A1 111116 FICYOI FA"ICIUEuIM Ms rcu,m eIt313? c0351. sivieC 30136* 1f1H1393l 30v31 (II lb () I ll 653 3031) 0111) *5 it) 3 6*LII 3Dkl M i colt FM3

331461513 I 011912 2.0 205.5 200.01 01203 01161 15.0 l0t5 110 2145.0 I3H0I off 11311. 6521 -.. .. ... --- 1--.0 242 3115611 12 2001.6 1001.0 I323I? 1ill 194 illy 54.1 11131. 025.1 951.1 113)11 00.3 - --- -- --- 325. 3.32 113962 3.9 260.0 24e06 142 32914 41.4I 2l6s 5?$ 1311.6 121.2 I22 3114.5 1.4 -.-- *.---1130 4.24 113000 3.4 fill H120.01 ills 0710 I1l 7146 3 iI fo003 0 114.0 04 4 1310.6 12.5 *... ... --- 3272.6 24.2I 611314 3.6 2Me I01.0.0 5112 5111 05.9 $1?3 is 9 039l.0 635s 0 7.9 1111.11 lot -... ... .-- -- 22.0 24.3

55111*1 009 l 3000l1 141 5140.0 M1280IitiUoI I 1614 00 0343 10.3 l 369 507.0 31.3 36576I i I0 g06 3114 3170 S1.5s 249404.1 3

1051* 3 1139133 I 20. 250 314 s05l 60.0 fil0 44.1 3606.01 10111.11 oill20 3o52 0..6- 2590.1 2332 313004 3.4 2051 1420.01 W21 103116 0.0 7236 62.6 3465 1 19321 00.3 3300 0 61i I -- ... listil211 312.52 013004 I. 200 9 200 0 1367 3261 316I 2207 37.0 204.0 26.1 10 5 64 0 109 I - ... -- -- -- 2166.6 13.0

SiiSoliU 0 Its1 lso.s 2045.6 11iYiEiSi 4690 13.6 sill 55.1 3233.1 800 A 01.6 I0.6 f0 I If 401 2420 s 2 s2l2036 23.6

31 I931 3 104 32 200 3001.51 1q32 4163 347 s3112 10 66901 II I o 096I2 062.0 533 I ... -- - .. 4206.1 314-

19610111 460 6 409 0 324 1 0 347.16l311141 44316 16 3001 4113 612.1 71913 151 60121 541I H5 203 2243 26.6 252164 3 20

M01I IIIC 26140.61 l660.01 3476.1 9316.6kiting6 132.1. 10.1 $342.3 62.3- 341.6 1605.6 55.17 123.0 023 7..1 24545 il 24.1 22.17. 12.4 1311111 Sloin (Its. 1 13.

If ol beat 1as1,140n1 mllietIiii) aIeulmIlzlg 2onls3113.*33w, CspeeIt,25

INDIA

COMBINED-CYCLE POWER PROJECT

Electricity Generation and Consumption of Western Renion(GWh)

Average AnnualGrowth Rate

Electricity Generated FY'79 FY'8 EY'1 FY'82 FY'83 FY'84 zY'79- FY'4 (XZ

Gujarat 7,991 8,852 9,363 10,207 10,775 11,995 8.5Madhya Pradesh 5,243 5,722 5,952 6,620 7,681 8,133 9.2Maharashtra 15,491 15,504 17,664 18,682 20,138 21,912 7.2Goa, Daman & Diu - - - - - - -Dadra & Nagar Haveli -__ -__

Subtotal 28,725 30,078 32,979 35,509 38,594 42,043 7.9

Central Sector LIM5 19 L.7 L2.140 LMii 3J.32 LA.

Total Region 31.243 32 077 34.953 37.649 40.185 45.385 L7

Blectricity Consumption

Gujarat 6,852 7,306 7,566 8,106 8,428 9,288 6.3Kadbya Pradesh 4,282 4,347 4,567 5,014 5,865 6,897 10.0abharaubtra 12,894 12,920 14,037 14,933 15,442 16,934 5.6Goa, Daman & Diu 1/7 257 253 199 222 262 8.2Dadra & Nagar Haveli 5 5 6 8 9 10 14.9

Total Region 24.210 24.835 26.429 28.260 29.966 33.391 6.6

Source: CEA, June 1985

INDIA

COMBINED-CYCLE POWER PROJECT

Power SuRply Position of Western Retion (On-Goinu/ianctioned Schemes Only)


FY'85 [Y'86 FY'87 [Y'88 FY'89 FY'90 FY'91 FY'2 [Y'9 F'4 FY[95 FY'85-FYl95 (Z)

Installed Capacity (NW)

Hydro 1,822 1,372 2,144 2,299 2,552 2,732 3,038 3,443 3,568 3,568 3,568 6.9Thermal 10,695 11,967 12,177 13,517 15,187 16,317 17,097 17,667 18,167 18,167 18,167 5.4Nuclear 420 420 420 655 655 _f890 _890 890 9X.Total 12.937 14,319 .14.741 16.236 17.739 19.469 20.790 22.000 22.625 22.625 22.625 5.7

Peak Availability (MW) 7,317 8,035 8,463 9,136 18,049 10,946 11,817 12,584 13,178 13,376 13,376 6.2Peak Doeand (WM) 5652 9.640 10.220 11S245 12[273 13459 14.701 16.058 17.544 19.165 20.935 ll.0Supply/(Deficit) (3M) 1.335) (1.605) (1.757) (2.109) (1.2A4) (2,5l3) (2.884) 3474) (4.366) (5.789) (7.562) -Energy Availability (CWh) 47,820 52,887 57,795 62,538 (68,247) 73,757 80,529 86,498 91,684 94,988 96,431 7.3Energy Requirement (GMO) 50.225 55.50Q 59.084 64.538 L7.16 7661§ 83.744 91.467 99.913 109.14 119.245 9.Surplum/(Deficit) (GiIh) (2.405) (2.613L (1.289) (2.000) L2.169) (2.861) (31.U5) LAA9691 (8.229) (14.160) (22.814)

Source: CIA, June 1985 (12th Electric Power Survey of Ind'a)

I"1SW

INDU

COHBINED CYCLE P(OER PROJECT

Electricitv Generation and Consumotion of Northern Reaion

(Gvh)


FY'79 FY'80 FY'81 YX82 FY'83 FY'84 FY'79 - FY-84(Tentative) (Z)

ELECTRICtTY GENERATED

Haryana 3,855 3,968 4,289 4,818 4,911 4,914 5.5Himachal .radesh 398 355 245 432 540 587 8.1Jamu and Kashmir 533 690 768 785 936 892 10.8Punjab 6,013 6,235 6,483 7,010 7,777 8,383 6.6Rajasthan 3,597 3,725 3,393 3,561 3,604 4,343 3.8Uttar Pradesh 10,139 10,124 10,190 11,348 12,585 12,154 3.7Chandigarh - - - - -

Deau 1.413 1.467 1.313 1,113 1.077 1.040 (6.3)

Sub-total 26,008 26,562 26,681 29,072 31,430 32, 313 4.4

Central Sector 1.541 2.665 3.317 3.552 5.648 7.876 38.6

TOTAL REGION 27.549 MM.22 29.998 32.624 37.078 40.189 7i

ELECTRICITY CONSUMPTION

Haryana 2,415 2,366 2,556 2,999 3,326 2,235 6.0Himachal Pradesh 207 233 280 387 330 401 14.1Jammu and Kashmir 400 421 440 493 651 659 10.5Punjab 4,656 4,915 4,997 5,046 5,843 6,296 6.2Rajasthan 2,604 2,974 2,935 3,130 3, 265 4, 214 10.1Uttar Pradesh 7,688 7,611 7,846 8,494 9,843 10,216 5.9Chandigarh 154 152 170 181 181 208 6.2Desu 1.823 2.083 2.308 2. 2 2.941 9.2 all

TOTAL REGION 20.018 20.744 21.531 23.132 26. 223 28.170 L. '

Source; CHA, June 1985

*INDIA

COBINED-CYCLE POWER PROJECT

Power SupplV Position of Northern Reuion (On-Goine Sanctioned Scheme. Only)

Average AnnualGrovth Rate

FY'85 FY'86 FY'87 FIY' FY'89 FY'90 FY'91 FrY92 FY'93 FY94 FY.95 FY85 - FY95 (Z)

Installed Capacity

Hydro 4,867 5,067 5,451 5,560 5,812 6,493 6,993 7,123 7,855 8,845 9,955 7.4Thermal 6,487 6,808 8,271 9,911 10,621 11,040 11,961 12,671 12,671 12,671 12,671 6.9Nuclear 440 440 440 440 675 910 910 910 910 91 910 7.5Total 11.794 12.31S 14.162 16.146 17.343 18.443 19.864 20.704 21.436 22.426 23.536 7.1

Peak Availability (DW) 6,959 7,600 8,678 9,508 10,481 11,333 12,179 12,913 13,538 14,184 14,918 7.9Peak Demand ( W) 8.790 9.210 11.975 13.179 14.455 15I825 7,415 19.167 21.098 23.227 25.576 11.3Supply/(Deficit) (W) tl.831) (1,610) (3.397) 671) 13.974) (4492 (5.236) (6.254) (7.560) (903 (10,658) -

Energy Availability (GWh) 38,816 46,429 53,623 59,218 66,137 63,842 80,159 85,310 90,433 94,823 98,363 9.7Energy Requirement (CWh) 46.905 51.740 61.375 67.538 74.273 81.086 89. 218 98.175 108.055 118.945 130.953 10.8Surplus/(Deficit) (CWh) (8.09) (5.311) (7.752) (8.320) (7.,936) (7.244) t9.059) (12.868) (17.622) (24.122) (32.590)

Source: CEA, June 1985 (12th Electric Power Survey of India)

0.,., w .

-46-

ANNEX 3.3

INDIA

NATIONAL THERMAL POWER CORPORATION


Detailed Project Description

1.0 The project consists of three combined cycle power stations to beinstalled at Kawas (Gujarat), Anta (Rajasthan) and Auraiya (Uttar Pradesh)and the associated transmission system. The Auraiya and Kawas plants willhave installed capacity of approximately 640 MW each (ISO rated) and Antaapproximately 380 MW (ISO rated). The equivalent site ratings would beapproximately 565 MW at Kawas and 380 MW at Anta. However, as the Combustionturbo-generators (CTGs) are manufactured in standard sizes, the eventualcapacities will be dependent upon the CTGs selected.

2.0 Each CTG will be a 50 Hz, heavy duty industrial single shaft machinewith inline compressor, directly coupled with matching generator. Thecapacity of each CTG will be in the range 95 MW-115 MW (site rated) TheCTCs which will normally operate on lean natural gas (8,700 kcal/Nm3) wouldbe capable of continuous operation on heavy fuel oil, LSHS, naphtha ornatural gas liquids. CTGs will be provided with a gas bypass stack to enableopen cycle operation. The heat recovery boilers (HRBs) will be unfired, dualpressure steam boilers designed to accept the maximum exhaust temperatureand gas flow of the connected CTG. Each steam turbine (STC) will be designedto match the maximum heat input from the connected HRBs. STGs and HRBs willbe designed for sliding pressure operation over a wide range to respond toCTG load variation. The generators will be either air or hydrogen cooledwith an output voltage of about 11 kV.

3.0 Standard ele:crical, control and auxiliary equipment together withthe associated instailations will be provided for each plant. In addition,each plant will be provided with a lean gas-fired quick start CTG of about4 MW for black starts.

4.0 The associated transmission system comprises lines between the plantsand concomitant grid substations. These will be constructed in accordancewith NTPC standards and practices.l/

5.0 Salient features of the power stations and transmission lines thatcomprise the proposed Project are described in Attachment 1 and a plantconfiguration is shown in Attachment 2.

I/ The salient features of the NTPC 400-kV transmission lines and associated400/220-kV substation have been described in the Central Power Transmis-sion Project SAR (Report No. 4293-IN) in Annex 13, Attachment 1.

S&IAIIPARALQFA4fAUMNQII

PXerZit.stL4tLIA l:IVitA .uJuLmL An_tj.i1ujUShktu Auraiva (Uttar PradgJI

site Adjacent to IRIBHCO fertilizer N-V of Kachri village Went of Debiapur villageplant

Access road Existing from Surat (12 km) 1.3 km from lota-Baran along road Phapand-Auraiya(l km)state highway

Railway Spur line under construction Adjacent to Kota-Dins 6 km from Phaphund stationfrom Surat to IRIBHCO plant railway at 2 km from on Kanpur-Agra railroad

Ants stationArea (hectargs) 360 250 250Land Acquisition Under acquisition Under acquisition Under acquisition

2. (90Z gvt., IDZ private) (1002 private) (open land)

Main source Hazira Branch Canal Right Main Canal of Kota Lover-Cauga Canal (Etarvok Branch)(close during 15 days) Barrage (limited closure and distribution canal

per year) (limited closure per year)Flow (W3/sec) 40 200 100

Alternative Poudage (1.4 million W3) Section of canal used as Pondage (1.5 million *3)no pondage;

Compensation not required not required Provision for compensation to

3. LILAM.uaL!. irrigation witb deep well from

Delivery Station ONCC/CAIL station Spur connecting pipe (16 kh) GAIL station on DIJ pipeline atto main DIJ pipe line the brancbing of the pipeline

division into two separate linee.Auerage Supply (IWCND) 2.25 1.5 2.25(total - 6 IDm)Pressure (kg/cm2) 80 45 45Alternate fuel NCL/Naphta (2000 T/day average)

Capacity; ISO rating (1W) 640 460 640site ratinj(Level(i);C)-(W) (6 m, 35 oC) 565 (250 m, 40 oC) 380 (140 a, 40 oC) 556

Plant configuration 2 x [2(CTG + WID) + STGI 3(CTG + WHlD) + I STC 2 X 12(CTG + WEB) * STCI

Cooling system 2 Cooling towers - Direct circulation for 2 cooling towers(natural draft) 250 days (3 pumps: (induced draft)(make-up: 3 pumps 0.3 *3/cec) (3 pumps: m3/sec) (make-up: 2 pumps 0.45 mc3)

- One cooling towerfor 15 days, induced draft

5. ~ (make-up: 3 pumps: 0.17 .3/sec)

Voltage (kV) 220 D/C 220 D/C 220 D/C9/C: single circuit Kavas-Havcari (45 km) Anta-Bhilvara (RSa) (200 ko) Auraiya-Agra (UPSE) (180 ha) nD/C: double circuit Iawas-Valthan (45 kh) 220 D/C 400 DICDistances (km) laas-Sbharucb (90 ha) Anta-Dauss (SUE) (390 kh) Auraiya-Agra (IITPC) (2D h0 ) "km

400 S/C -

Agra-Ballabbgarb (178 kh)

INDIACOMIINED CYCE POWER PROJCINalkmdhW PowCxon

PinW C otg~

HEAT RHCOUY ILERS (H)

CMOUSGIOE AOR (SIG)

DES IICAIR( IUC S

~~~~~~~~~~~~~~~~~~L KP

~~~~~~~HP5 PeSsC

x~~~~~~~~~~~~~~~~~~~

-49-

ANNEX 3.4

INDIA



Implementation Schedule

The proposed Project consists o7f a number of components (e.g., CTG, STG,transmission lines, and substations) located at different sites (e.g. Kawas,Anta, and Auraiya), and to be implemented in parallel. The construction of theHBJ gas pipeline would also be undertaken quasi simultaneously in order tosupply on time the gas required for the power stations and other plannedfacilities (e.g. fertilizer plants). Attachment 1 indicates the forecast datesof commissioning of the different facilities included in the proposed Project,together with completion dates for the HBJ pipeline. Attachment 2 shows thedetailed implementation schedule of the Kawas power stations. Schedules for thetwo other power stations, Anta and Auraiya, will be similar.

INDIA

NATIONAL THERHML POWER CORPORATION

COMBINED CICLE POWER PROJECT

Co_issioninp Dates of Pro;ect ConoDentes

Combined Cycle Unite TrensuissionYeer Ouarter Gas Facilities lava Anta Auraiva Lines

1986 1

2 Work starts on RBJ

3 Gas available at lavas

4 Contracts avarded Contracts awarded(12/86)

1987 1

2

3

4

1988 1

2 Gas available at Auraiya(4/88)

3 Gas available at Ants(10/88)

4 CGTI 12/88 lawes-Nav*ari (220-kV) 10/88Kevas-Valtban (220-kV) 1V/88Auraiya-Agra (220-kV) 12/88

1989 1 CGT2 2/89CGTI 3/89

2 CGT3 5/89 CTGI 4/89 CGT2 5/89CTG2 6/89

3 HDJ completed CGT4 7/89 CTG3 7/89 Ante-Bbilvara (220-kV) 7189CTG3 8/89 CTG4 9/89 Auraiya-Agra (440-kV) 7/89

Ante-Deaue t220-kV) 8/89

4 Kawas-Dharuch (220-kV) 10/89

1990 1 4Agra-allabbgarb (440-kV) 12/89

2 STCI 4/90

3 BTG2 8/90 STGI 9/90STCI 10/90

4 STC2 12/90

INDIACOMBINED CYCLE POWER PROJECTNotkonl Theimnal Power Coipomation

Impementation Schedule fx the Kawos Powe Station

i9s* 19O Igo 99 1999

1 2 3 a 2 3 a 2 3 1 2 3 4 I 2 2 4 I 2 3

PPOAC1 PRPARATIWNI

CCNSaLX.AN SEMCES

ST LEMdIWG I

SP.cCOMBS"D CYCLE LWIS

CT - - - - U~~~~~~~~~~~~~~~~T YCYc

H9/STG - - - 8ri

- -~~~~~~~

MANGSNISON SYSTM

GENERAL SERVICES ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ mjt Ecta

vilmak-3171

-52-ANNEX 3.5

INDIA



Project Cost Summary

------Rupees MiLlion----- ------US$ Million-------Description Local Foreign Total Local Foreign Total

Preliminary Works 45.5 - 45.5 3.5 3.5

Civil WorksFoundations 76.7 - 76.7 5.9 - 5.9Structural Steel 39.0 57.2 96.2 3.0 4.4 7.5Plant Civil Works 55.9 55.9 4.3 - 4.3Other Civil Works 561.9 - 561.9 43.1 - 43.1Sub-Total 733.5 57.2 790.7 56.4 4.4 60.8

Mechanical WorksMain Plant Equipment(CTC, HRB, STC) 2,068.1 5,342.0 7,410.1 159.1 410.9 570.0Black Start CTC 18.3 48.0 66.3 1.4 3.7 5.1Fuel Gas Handling 32.3 31.4 63.7 2.5 2.4 4.9Air Compressor 5.8 4.6 10.4 0.4 0.4 0.8Fire Protection 30.6 29.2 59.8 2.3 2.3 4.6Air Conditioning and 8.0 7.6 15.6 0.6 0.6 1.2VentilationStation Piping 53.7 51.6 105.3 4.1 4.0 8.1STC Oil Purification 4.4 4.7 9.1 0.3 0.3 0.6Control & Instrumentation 55.5 53.7 109.2 4.3 4.1 8.4Crane 7.5 6.8 14.3 0.6 0.5 1.1Other Mechanical Works 284.1 42.2 326.3 21.8 3.3 25.1Sub-Total 2,568.3 5,621.8 8,190.1 197.4 432.5 629.9

Electrical Works 377.8 773.5 1,151.3 29.1 59.5 88.6

Fuel Connection Facilities 57.0 117.0 174.0 4.4 9.0 13.4

Transmission System 1,430.8 196.9 1,627.7 110.1 15.1 125.2

Consultancy 72.6 67.6 140.2 5.6 5.2 10.8

Engineering & Administration 808.5 - 808.5 62.2 - 62.2

TOTAL BASE COST 6,094.0 6,834.0 12,928.0 468.7 525.7 994.4

Physical Contingencies 316.0 358.0 674.0 24.2 27.5 51.7

Price Contingencies 1,070.0 1,471.0 2,541.0 S2.8 112.4 195.2

TOTAL POJECT COST 7,480.0 8,663.0 16,143.0 575.7 665.6 1,241.3

-53-

ANNEX 3.6

INDIA


Estimated Schedule of Disbursement

IBRD Fiscal Year -------------------Disbursements---------------------and Half-Year Cumulative US$ Million Equivalent Z Undisbursed

1987

December 1986 1.0 98.0June 1987 36.0 92.6

1988

December 1987 110.0 77.3June 1988 170.0 65.0

1989

December 1988 250.0 48.5June 1989 320.0 34.0

1990

December 1989 370.0 23.7June 1990 410.0 15.5

1991

December 1990 440.0 9.3June 1991 460.0 5.2

1992

December 1991 485.0

1612000. 1063100. 90611o CPU101 LIIII,E)cml:uo P,auraool oaci

2010. CWORATIIE.... t,..w.°"..°.iNIIWIIDII P0ill

C0I2 0611A416 912963 INNOM F9I"9

I1UKE1S IILLIEI

CAPItAL EP17 iUE U i1-;;96 191; i;;1 i;i9 i;10 III 1912 1913 i 914 1915 1916 1911 1918 219" lm 2" 2 :92 2993 19 199 1996TO.1011i1ERN 111INI:SIIIIIUIO -30IM120 0 25,614 7 III 296 146 834 1M 521 516 345 303 I,9m 3,110 5,249 5,370 4,029 670 0 4 0 01161111 500 16,099 0 0 0 0 0 454 1,2106 2,895 2,317 5,467 4327 3,125 2,1741 159 2,534 1,034 6. 42 7 2,36 22,61? 7,1T9dIUIE 31,221 0 12 a II5 Il7 42 23 510 562 I422n 3903 4,416 2,946 1,124 2594 1.621 2.42 2,11 210 2.31III 6,911 0 0 0 0 2 1 50 33 is 55 294 124 900 494 264 424 * 25 0 31322,22 I1510.lr I 25ll9,15 1 2"0 3 I6 9 1,341 1,194 2,139 3,339 1,506 10,9°2 12,211 11,436 1,3 1 ,12 9, Ilk 1,154 24,602 2 ,

TOtA t 13 ;g40 ° °.0 11 |5 ' 20 0NU 745 00 5l X 0 n

TOT.Eh11M IM 011:1AT10116 160,M00&220 19,236 0 II 8 ° 303 635 III4 1ON 640 104 146 2 M3 3173 3221 0S 155 0 0 0 1 01T 011EI 50060394 0 0 0 0 0 2 xi III II 303 3036 1900 1634 222 3697 7 1076 1 132 21230 7165t461100 2499" * 0 0 0 32 17 III 121 10 386 1219 224 1124 1112 11355 114 21114 33 302 261 21I C 3.634 0 0 0 0 0 34 is 46 0 I 212 64s 545 I9" 0 0 0 145 120 2002tOTAL 116,264 0 1 211 335 792 1325 251 1 1411 269 62 1303 1942 1020 5646 6326 1060 244 2121 233s 1 319

IOT.SDUtFA 3fl11121011:1ATOS 200 5,360 0 0 50 363 345 200 1129 635 419 274 261 0 0 I 0 B 0 0 $5 11613 500 29,1 71 0 0 0 0 0 0 0 137 156 1261 3013 2631 2543 21N]2 2445 3623 3111 2954 s1T1121n1nn 13,094 0 0 0 3 39 255 16e 1 I 56 1392 2269 1511 1103 513 1261 1145 1504 I21 215 Iitc 2,129 0 0 0 0 0 0 23 62 30 5 24 2M $40 225 9 35 319 742 59 ItoTAL. 50,351 0 0 so 366 384 1263 1919 1615 1643 2932 5473 4424 4456 2929 3154 62375511 4146 2525 15

201.1611Um KSIU2T1A2IOII 2001220 20 410 0 0 4 94 363 496 619 121 1144 259 240 3195 2924 23 2326 1562 000011611101 500 ":'m 0 0 0 0 0 0 0 2 30 426 3069 SW4 241 0621 MOO 593 PM6 639 995 132li~iuiI2 11,1"1 0 0 0 0 I 6 15 III 96 253 1129 1671 sit 1012 695 IU 1112 2431 223 26??1K 4,016 0 0 0 0 0 0 0 0 4 41 27 0 1 652 I? I299 oil 0 0 96TOTAL 101,16A 0 0 4 94 364 502 104 936 IM1 2212 A92 140 9932 13214 l211l INVl 923 VW 1120 2123

TOTAL 3IPK CIDAIIM:IIATII 100-210 10,621 1 213 632 2,506 2,111 3,413 ,1IN 2,320 3,312 3,636 1,152 10,130 11,392 20,346 71,20 2,31I 0 0 0 SIlilIMl 500 232,113 0 0 0 0 0 454 2,149 2,552 4,39 10,17 IS.M6 11,196 23,012 13,916 25,544 25,114 31,391 34,440 53,111 23,64IOAIIISSIUI 04,105 0 12 be 250 334 410 607 115 1,604 4,116 it0,02 9,221 6,412 4,114 5,424 7,022 L 3,39 om ,921 1,22iCe 11,345 0 0 0 0 21 14 141 125 91 341 ,971 12 2s1t I, 2,390 IS" ln 1.39 30 254 2,341 3,216ANUI11N1 TO 1971-04 ACl00 9 22 29 II 32 25 1I9 11,0371 11641 12641 12642 I2la) 1164) 93 0 0') I I0VW TEAL 404,144 7 234 721 16WI 2 543 4 463 62141 7210I 1 425 If176 324535 321III 32221 29942 50696 ; S . 5 75 3692" 45, ,916m 339 inCLIJUAIIW TOTL. VO PAIii 404,114 1 241 962 h41 II90 ~653 1d194 M&I6 31., Edii 11620 114433 147119 11i122 205ll 24103 X312 326972 31194 Ui W

-55-

Ah= 4.1Page 2 of 5

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COWINS 401A1IO2 FIIWS 1JUl5 FtLE9C~~~~~~8*8~~~~~~~~~~~~~~~~~~"Sx~~~~~~...... ............. __.._.

IlUEtS 222LL2E)

W Wo .IlL IfilTf U 11716 1977 1971 1979 19 1 1952 195 195 195 195 1D 1t5 11 INO 19I 1992 199 199 199 199

KM142 I3CTAIII 200 3,014 0 II 211 303 635 1114 l3 357 44 11TENSINiE 522 0 0 0 32 157 177 121 35 0 0

IC 165 0 0 0 0 0 34 35 40 0 0TOTAL 4,302 0 16 212 335 72 1325 2059 433 44 It

SfI1 452 A1S11335 500 12;5153 0 0 0 0 8 0 334 7177 22 3 3*05 1 2900 126 309Twain ac1 ,9k 0 0 0 0 0 0 0 17 31o 351 405 426 IU 0

11 1:1 0 1 ~ ~~~~~ 0 0 0 0 0 0 0 0 196 413 346 143

AIC 211 0 0 0 0 0 0 0 0 0 0 0 150 1072 5O

IKC 42 0 0 0 0 0 0 0 0 0 0 0 29 12 0TOTAL 2,522 0 0 0 0 0 0 0 O 2IJ 294 4U7 4322 25 209

L3211T'0 OECTII3TASIUI 500 50,141 0 0 0 0 0 0 0 0 0 0 0 0 200C 2300 SU97 730 20702 12362 I01J0 76C TAN131111RA 1,439 0 0 0 0 0 0 0 0 0 0 0 k3 142 212 1274 2114 S33 3441 23 2

IOIIL 75,347 0 O 0 0 0 0 0 0 0 0 0 63 2t25 2317 5511 20690 24097 27272 2353 107119

30041 346400021T41O C 200 K4702 0 0 0 0 0 0 0 0 23 719 1273 2239 50 22A111U 572 0 0 0 0 0 0 0 0 0 0 22t 232 224 0 0

1K 1214 0 0 0 0 0 0 0 0 0 1 16 k 74 20 0TOTAL 15,454 0 0 0 0 0 60 .0 0 0 24 2052 2 17 2544 2177 2291 10" 1M 77 01

3AA31S 0W1TA0IO 500 68,394 0 0 0 0 0 0 33 75 222 343 3034 2900 12134 222 2197 30 512 2 k 003747231 3 54702 0 0 0 0 0 0 ~ 0 0 0 23 279 2702 2249 1 2 0 0 000112121 2 74,9 0 0 0 32 25 7 22 70 30 222 1 2624 262 223 234 25 30 30 63 26

IOI.IIECEIII IE TOl:lTALS OU0 1 5,5n O lt 2S 50J tJ 11 14 1001 U n u 20 77Il w 14 U 7b SJ21 OO

ITATIM 5 is , $,34 0 0 0 0 0 31 ?Z 71 1211 J*0X 3OS ItOO li34 2229 36t7 71 10761 11626 10130 7JwS$TAT,= IAs 4, INs ° o o o o O 0 o O o 3 719 m lZ 12U9 U 211 t O O OO

tv1alX 24" m O O O 2 Is? 1517 121 70 SU 1219 U 24 1624 1612 11S5 1174 2M4 33, 3401 unm 2w4 ° IO 3,634 0 0 0 0 0 34 s 46 0 I 222 645 545 I2 0 0 45 720 l22

TOTAL 2l26,26 0 26 212 335 792 2325 159 1241 26 620 30 1942 7020 5U4 6326 20690 2IO47 I7n 12533 2072

a1.1 s ^: 5- rgwZ Sm s sOO

* *-3s> -- -0O °--.1 s-

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IUIA

hAtI t.niw.K PUN M£WU*120 LINITII

CI7Ei CYCLE PON P0IC7

CWvU1I OPRATINS FI"$ IIS1 FPI"

IIfIJES 1W1W1ON

RT1WItA. EIKIE URE a 1111Im^-9 1,7 1911 2979 19o 293 l2 19113 1914 13 194 I"3 19M 1919 1i9o 1992 1992 1993 1994 1995 I19~~~~~~~~~~~~~~~~~~~n..... .. , ,, ... .. .. _.. .. s . as_..._.

FAIA3 AT*IONS 200 1,344 0 0 4 e 4 33 494 1 6I 02 1310 1200 1195 191 0 ° 0 0 0 0 00TIIMIIIIIIE 131 0 0 0 0 2 I 35 113 92 122 712 0 0 0 0 0 0 3 0

IK 62 0 0 0 0 o 0 0 0 4 41 17 0 0 0 0 0 0 e o1041L ,031 0 0 4 94 364 142 704 911 1471 133 1424 1tll 0 0 0 0 0 0 0

Fi1A ll:TATI 500 10hI 0 0 0 0 0 0 0 2 33 362 1114 1127 2351 2514 1935 9b] 311 3 0 9T0UNI1IUIO I1741 0 0 0 0 0 0 0 0 4 10 404 124 476 213 so 0 * 3 0 0

1K 455 0 0 0 0 0 0 0 0 0 0 0 0 12 132 315 144 0 3 S 0TOTAL 13,240 0 0 0 0 o 0 0 2 42 372 1S 1153 2n4t 29t9 2300 1I0 3II 0 * 3

F A 111:11412U3 100 5,013 0 0 0 0 t 0 0 0 0 44 206 9S 34 142 1014 922 372 o I Ifit III 0 0 0 0 0 0 0 0 0 0 0 0 3 40 249 K 2I" 0 0 3

TOTAL ,460 0 0 0 0 0 0 0 0 0 144 2"° 943 343 14 1163 1210 542 0 8 I

IANLW:rTATIOne 210 13,04 0 0 0 0 0 0 0., 19 4 392 n 33 2004 291n 2M 2324 1541 0 e * 0ItK2UIK 2,359 0 0 0 0 4 0 0 0 0 22 1113 1144 29? 34 0 0 0 0 0 3

2I6 i,1 0 0 0 0 0 0 2 0 0 0 o 0 49 244 35 130 0 0 I 0T104L 11,719 0 0 0 0 0 0 0 19 4 413 2no 314 3240 3423 243 IH9 3 0 O

I11,003TATIN11 500 1353 0 0 0 0 0 0 0 0 0 0 1497 I450 244 305 232 1140 242 A 3 I2K 14627 0 0 0 0 0 0 0 0 0 0 0 0 1 4 547 I35 241 0 0 0

TOTAL :5,560 0 0 0 0 0 0 0 0 0 0 1497 2450 294 3339 339 IlS 453 3 3 3

lKll US IETU11TAI0U1 50035,43 0 0 0 0 0 0 O 0 0 0 0 0 0 mo 631 2912 093 H 957 MTRlA111 101 2215"4 0 0 0 0 0 0 0 0 0 0 0 0 39 451 145 I 112 2431 225 21n

266 34 0 0 0 0 0 0 0 0 0 0 * 0 0 0 0 0 3 3 3 234lIi 47,793 0 0 0 0 0 0 0 0 0 0 0 0 3V 1475 1432 4267 105 32 1221 I1111U

TOl.14i7AII 31t 1Tllin 200/210 20 4l0 0 0 4 94 34 494 429 321 1444 2592 2C 3195 2914 39 2324 1561 * 0 0 0110120K 5044'6,573 0 0 0 0 0 0 0 2 33 424 439 3540 6141 Ml? 6409 5931 7667 49 9957 3OM

TIKit 24,19 0 0 0 0 2 o o5 223 9* 153 172 21410 3U0 102 A95 2355 1712 2431 223 2477 '1K 4,~~~01074 0 0 0 0 0 3 0 0 4 4II 1 42 13 19 3 3 I

01AL I01,3 0 0 4 94 3°4 502 704 93 1512 2212 4923 645 9932 13114 11017 1302 923 9329 122l11 II7 SI.A

NATIONAL THERlAL P0iR CORWORATION LIRITED

COHINED CICLE POWER PROJECT............. _......

FIRANCING PLM

CEWRINS FISCAZL TEARS FYi;i7 THRO Fl ISSbIRLPEES NILLION)

7OTAL 1977-96 ACTUAL ACTUAL --------------------------------------…PRWECTED- … --------------------- -FISCAL YEAR ENDING MARCH 31ST US I Ml'. RS.R1L 1977-83 I994 ISO5 196 1937 1919 1919 If 1912 1992 9 2994 195 2I99

SOURCE OF FUNDS:

INTERML CASH 6SNERATION 17,913 231,J 39 bJ 777 1,744 3,079 3,7t9 5,397 0,147 11,119 12,442 24,217 21,259 34,227 41,042 49,752

NORKINS CAPITAL-DECREASE/l2NCREASE) 11,105) 114,3141 702 1343) 5s 1,t92 2.tl2 120) 11,937) 12,440) 12,099) 323 1432) 423 (2,907) 110,39b)

LESS: DEBT SERVIC. (7,50t) (97,594) 1t5 12212 1575) 1775) 11,1553 2,907) (4,022) (I,319) 1(,020) 110,174) (2,112 9) 114,3371) (2,6t1) 120,611)PRELININART DEFERRED EIPENGES (3) 135) (35) (0) (0) 101 (01 10) (0) (0) t01 (01 (0) c0) 10) t0)

--------- -------- -------- ...... ........ ........ ........ ......... ._ ........... ... .... __ ._

CONTRIBUTION TO INESIMENT 9,204 1129,65 790 213 1,247 3,9 9 5,291 2,31O 2,189 2,911 0,323 11,36 15,939 20,323 22,474 11,16. . _~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~U

EXIERIPAL FIINIACI1G

SHARE CPITl. 10,273 233,545 11,910 4,204 5,551 7,519 14 739 15,214 17,946 7 559 7,479 25,432 15,171 20,390 0 0L01B-TEAN LOS II 3,294 2,753 2,627 o,292 22,429 24,704 12,1225 29,32 24,394 4,512 ,532 24,544 30,519 30,932MY-RTEIRN LOWN 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

LESS:SHORT-TENR DEPOSITS (I2S,9) (24,769) 0 0 0 0 0 0 0 0 0 0 0 0 19,094) (15,4742.. ........ __..... .... _ ....... __. ........... ........ . . .. . . ........ ... .... .... _. . _ ....... ...... - - - -__-

TOTAL SOURCE OF FUNDS 312145 404,14 15,794 7,170 3,425 19,776 31,455 32,319 32,261 29,902 30,394 36.515 37,491 45,249 43,970 33,945

IWESINENT REIUIRMTS:

TOTAL INVEsTIENT REUIREMNITS

CAPITAL INWESfl(T P10WAMlincludinq intfest during construction) 31,145 404,594 15,794 7,170 9,425 12,774 31,455 32,323 32,211 29,902 30,984 34,515 37,t91 45,249 43,970 33,J45

*.oggin swl ...sess$ ulo ...ggs .ssuggen assugasss $*Bootle.......... osesso. sastos ssagas swssome ............... ,sama ... -s ssauxu asas-sUZ 22................|....0218

I CONTlRIHIPTIO 10 INVESINENTIltontribution to invustaont di tho tof avirwq 3 vear capital lipmnditura) 29.62 5.0l 3.01 14.92 21.32 11.91 9.71 b.O1 9.72 24.9n 39.31 42.42 44.92 521.1 55.12

1/ Includge onlmnding of IDA Credits/lIl0 Loans, Fediral Raoublic of kruny,OFEC. U.K., U.S.5.R. loans anothkr sources of co-financing,

MATIONA INIUM POWR COWUATION LINIHEI

CORI WD CYCLE "KWR PIOJECT

COYIARE OPRIATIN F792933 THROWI FiYqb

IRSJEES NILLION)

ACIUAL RTACLW---- ----- ------ ------- TE ----- -------------- -- TOTAL

........... s.n..mmm...mm...mmm..m. .... .m m... ........... m.......m..mm .... mmn..,S m m3SflS3s U3335 SiS*n.fin fWPOWER EWERATION 1,209 4,247 9,232 1I,912 14,032 23,I49 30,134 43,063 55,420 45,9$2 74,00 79,705 53.539 91,20 593,392LENS:M22ILLIARV CONUITION i5 432 929 1,197 11,403 5,791 2,573 3,350 4,251 5,099 5,747 6,143 4, 759 7.445 47,250

TOTAL POWER SAKES IMW) 1,034 3,835 8,303 20,775 12,428 14,371 27,554 39,713 51,149 40,f54 48,253 73,533 11,330 90,737 544,5141

315LK 65192. TARIFF IPAISE PER EEl) 32 34 42 43 52 57 45 44 b3 74 IS 33 33 94OPERATIE SALS RE4IIME 334 1, 39 3,433 5,210 .4440 9.294 14,474 25,349 35,036 44,114 52,997 40, 751 71,544 34,342 411,593

---- - ------------ 8.9miUs, Seamus.. 95*g*U*8 **ssUUI Semus- *** ..S.. ........ ... *mm*sa Sealmus" SmosIses a*ssamm .*S3a3m .muuum *aSmm,m ammIsS,

PERtATINI EOPENUE3S. GENERATION

7211.: NOR~~~~~THERN REGION 145 345 744 751 305 1,044 2,925 5,735 4,424 7,943 9,014 9,749 10,451 51,424 43,020WESTERN REGION 0 523 297 344 390 419 2,336 3,762 4,384 4,983 5,274 5,613 4,390 7,560 42,1222SOUTHERN RE61ON 0 12 214 456 573 454 350 1,304 1,932 21,493 2,310 3,0611 3,559 4,221 22,594EASTERN REBION 0 0 0 42 242 420 473 514 323 2561 2,404 3,453 4,350 5,191 19,443

TOTAL FUEL 245 505 1,257 1,453 2,050 2,719 4,589 11,347 13,549 17,005 19,744 21,923 24,910 23,425 152,001

OPERATIONS I NAINTINNE1EE NORTHERN RESIDN 44 II7 205 109 112 307 440 h39 954 1,090 1,091 1,244 2,443 1,430 9,499WESTERN REGION 0 27 1224 93 93 279 527 732 750 750 750 904 1,266 1,443 7,944SOUTHER REIlON 0 2 70 539 134 134 237 310 1 311 332 33 547 757 759 4234EAStERN REGION 0 0 0 503 155 235 235 235 437 907 2,263 1,590 5,351 1,553 7,:439

TOTAL 041 A 44 244 409 434 494 907 1,539 1,915 2,572 3,1223 3,410 3,N119 4,817 5,590 29,348

DEPIECSASION: NOTHER RESION 2 42 2IS 550 253 236 501 2,047 2,24 2,434 5,474 5,474 5,948 2,293 22,344WESTERN REGION 0 23 97 130 230 232 420 795 5,152 2,239 51,53 21,533 1,422 2,042 9,693SOUTHERN RfEGIN 0 22 70 272 235 292 195 347 494 420 429 429 90 2,77 5724

EASTERN lESION ~ ~0 0 0 0 145 2217 259 251 259 717 2,402 5,39 2,394 ,7 ,2

TOTAL KPREC'N 2 47 235 452 409 497 1,372 2,443 2,983 3,962 4,834 5,324 4,145 7,790 37,006

TOAL. GENERATION OPERATING EIPENSS 223 723 5,952 2,499 3,225 4,323 9,549 15,745 19,124 24,095 21,003 31,13!1 35,392 42,005 223,375

TRAMINISSION. OPERATING ESPKNSES

OPERAIOSi7NSTi MNCE I 3 3 34 135 232 349 393 453 524 454 712 797 375 5,234OEPRECIAIION ~ ~ ~ ~~~~~~~~~0 2 54 209 219 432 731 903 5,035 2,273 5,345 5,597 1.352 2,073 52,543

TOTAL IRASN2ISSION OPERATING EIPENSES I 5 24 293 404 743 1,010 2, 304 1,463 1,702 1,975 2,309 2,449 2,943 24,347

TOTlk OPERAIINO EIPENSES 214 723 1,975 2,492 3,519 5,034 10,429 57,052 20,412 25,797 29,933 33,447 33,541 44,953 235,M2

OPERATINS IHEONE 31F0RE INTEREST) 1230 475 2,443 2,531 2,941 4,203 4,045 3,323 24,424 19,077 22,944 27,304 33,025 39,119 112,971

LES' INERS O LAS 1 459 730 5,214 2,202 3,419 5,292 7,309 9,473 50,354 15,557 122,430 53,244 13,30 99,481OEOUCT SITEREST CAPITALISED ~~J89 233 255 32 977 2,527 2,52 0 1 2,50 2,9 IN3 350 I2,24 2,342 3,174 17,459

MET INTEREST CARRIE TO OPERATIONS 45 221 575 775 2,125 2,732 3,735 5,959 7,518 9,427 20,747 52,412 12,923 15,432 32,122OEFRED ESPENSEWISTTEN OFF 9 5 0 5 5 5 5 5 0 0 0 0 0 0 35

NET EARN2N 4 449 NI 273 ,322 2,452 2,259 2,351 ,1334 9,450 22,257 15,39 20,502 24,257 500,924.......... as"zmmm.m m.... .. m..mm... .mim mm.mmmmm ins,..... mmResume .mm.... asmm... mu,..W, mm..... wase'lee smmalse.

AVENU4E WET FIXED ASSETS 23 JME- AT 2IS3TONSCAL COST 2,305 5,993 22,775 53,432 24,435 38,545 74,877 207,253 125,39M 549,532 547,630 134,424 223,444 Z44,304-AT REVALUED COST 2,733 7,064 24,355 22,495 30,233 48,702 94,117 542,725 274,238 225,345 250,033 237,614 352,405 432,373

1A*75K9W OERATIN PERFO!NANEE

OPERATIEO RATIO IOP!.E2PS. 3 I0 OPWEN. REV.) 44.2 5i.7n 57.42 52.7 54.52 54.12 43.72 67.21 51.31 57.51 54.42 55.52 53.91 . 53.01 sRATE OF RETLIN: ON HI3IONSCAL COST OF MT ASSEIS 4.42 22.31 51.52 13.51 22.01 10,92 3.51 7.32 52.52 12.3n153.71 14.42 20.32 55.02

OUIVALII COST OF NET ASSEIS 0.23 5.41 3.02 9.41 3.3 4I .71 4.2t 4.41 4.32 7.42 3.52 3.31 3.02 7.92

INDIA

NATIONAL THERMAL PWER CORPORATION LINITED

CONIllD CYCLE POWER PROJECT

UhANdC SNEE1S

COVERMIK FISCAL YEAR FYl93 1HH FY 196

IRIPEES NILLION)

ACTUAL ACUAL------------- PROJECTED-- ---------------------------------------------FISCAL YEAR ENIIKS MARCH 3291 1993 1914 2995 2996 1917 919S 2999 1990 1991 IW92 1993 ISS4 1995 1996

ASSETS

SROSS FIIED ASSETS IN OPERATION 3,036 9,197 15,419 23,349 2,U406 53,576 104,357 123,523 149,309 179,154 193,110 229,360 297,560 333,520lESS:DEPRECIATON 66 170 471 1,032 1,U0 3,039 5,141 9,512 12,530 127,670 23,965 30,70 39,105 43,661

NET FIIED ASSETS IN OPERATION 2,961 9,027 14,949 22,316 26,546 50,537 ",211 115,011 136,779 111,414 174,275 129,572 246,755 214,552NOK-IN-PROIRESS 12,759 13,167 15,970 26,617 53,214 60,361 42,362 53,097 53,207 64,376 93,592 97,109 83,319 71,364

TOTAL FIED ASSETS 15,726 22,794 30,919 49,133 79,760 111,399 141,577 111,2t0 194,99b 226,360 257,S57 296,181 332,134 356,216

W~RRENT ASETS:CASH 90 231 46 5S 74 107 234 375 455 5b6 652 727 936 961RECEIVAItES 218 642 1,146 1,303 1,077 1,549 2,779 4,229 5,639 7,47 9,625 10,125 I1,929 24,240IIVENIORIES 155 424 315 393 512 U6 1,493 1,952 2,492 3,038 3,396 3,551 4,612 5,306LOANS I ADVYCES 263 229 52 71 l6 226 192 231 379 460 562 643 753 37SMOR-TERM DPU9SITS/ILOANS) 0 202 20) 20) 20) 20) 20) 20) 202 20) 202 20) 9,094 24,766OTHER CURRENT ASSETS S 3 4 4 4 4 4 4 4 4 4 4 4 4

T~.... .......... . . ..... ........ ...... ..... ....... _..TOTAL CIRENT ASSETS 739 1,183 1,562 1,929 1,753 2,632 4,707 6,140 9,169 11,567 13,439 15,350 27,227 46,061

KEFEMEO EIPENSES '6 21 21 16 11 6 I 0 0 0 0 0 0 0

TOTAL ASSETS 16,491 24,593 32,501 50,979 62,524 114,036 146,255 174,949 204,155 237,927 271,296 311,531 359,361 402,29433333es3a3es 323S3339 333S3S23 323W3Z3Z 33===3 322:3:: :33333ga :33- 3 3ss : 3 3333333ssessed33 3w3s333 3 3:3: 2 333 3333333ss 3 33 3w333

EQUIIT I LIABILITIES3 :h: ::3:3:::3:333

EQUITY:

SHMRE CAPITAL ISSUED 11,365 15,669 21,565 29,154 43,992 59,145 77,114 54,672 92,351 107,994 123,155 133,545 133,545 133,545SHARE KDEPSITS 445 341RETAINED EARNINGS 46 495 1,313 3,121 4,932 7,343 9,602 12,960 16,796 28,446 40,663 56,555 76,657 100,914

~~....... .............. ..... .... ...... .... ..... _ ... ___

IOlAL EQUITY 11,956 16,509 22,943 32,275 41,924 66,499 36,716 9S,632 112,147 136,430 263,911 190,100 210,202 234,459

LOANS 3,194 5,947 7,574 14,765 26,156 40,745 52,629 71,702 96,164 91,933 96,523 101,142 134,994 260,39CUIRRENtT LIADILITIE9 2,442 2,242 1,979 3,938 6,544 6,603 6,942 6,614 1,844 9,565 10,955 13,299 14,165 6,936

TOTAL LIABILITIES 4,635 9,039 9,553 12,703 32,700 47,546 59,570 73,316 93,009 202,493 107,473 121,431 249,159 167,325_.._ ....... ... .. .. . . ......... -__ . _....... ................................ ____._____

TOTAL EQUITY I LIASILITIES 16,491 24,593 32,501 50,971 91,524 224,036 146,28 174,941 204,155 237,927 271,296 311,531 359,361 402,284RATIO OF DEDI TO KIT PLUS.s u EQUITY. 217 264sss.. 2...... 32/ a35a/65 3162ts a33s6 3/57 44/5sa6s 40160 7wsIS3 3sas s39s/6 42159

ATIlO OF DEPT lO SEST PLUS EQUITY 21179 26/74 25175 31/69 35/45 38162 38/62 43/57 44156 tOlt,O 37/t,3 3t,10, 39161 41159

ISIA

NIONAL TOL PWER C OPATI LINITED

COINED CYCLE PFO PONECT

UTATENEUT OF SURME AND APPLICATION OF FIND~~~~.... .... _. _. _._._......... _..__

COVERING WERATIONS FYI913 THREO FY2I9........... . ...... .. ........ _. _. _......

IRUPEES NILLIONI

fSTA4 ACTUAL ACTUAL -- - -- - -- - - - - ----------- E E ----------FISCmALk,12A EaR EsNoIN MAC 111977-96 1977-B3 1914 1985 1914 1997 19M 1939 199 1991 I992 1993 I994 I9M 1994

SOURCE OF FUNDS:

OPERATING INCOME IEDEFE INT) 12,971 120 75 1,463 2,519 2,942 4,20 6,045 9,313 14,424 19,077 22.,94 27,304 33,025 39,389

DEPRECIATON 43,644 be 102 301 561 929 1,179 2,102 3,371 4,019 5,140 *,195 6,923 3,017 9,133

TOTAL INTERNAL CASH 6ENERATION 231,639 IU3 777 1,764 3,079 3,749 5,387 3,147 1,689 19 ,442 24,217 29,159 34,227 41,042 49,752

LOANS 176,451 3.194 2.753 1,627 7.191 11,419 14,704 12,125 :9,132 14,894 1,51 6,532 14,544 30,589 30,931

EQUITY SHARE CAPITAL 133,545 11,910 4,204 5.551 7,589 14,730 15,254 17,968 7,559 7,479 15,432 15,171 10, 30 0 0-- --- .- - - -- .. - .-

IOTAL SOURCE OF FUNDS 541,435 15,192 7,734 3,942 17,559 29,926 35,345 33,240 38,480 41,015 46,365 50,362 59,141 71,431 30,43*..assummows: sseazzm azzals *ssasass s"2.f ssssss as :8sx X-j--Z 2222022 222222 _:sZ22 *=lZX*W _"w8lSM 2"2= zz::::r- ss3M8 =vss _

APPLICATIN Of FUNDS

CAPITAL EIPENOITURE IINCLUDINS IDC) 404,984 15,794 ,.170 9,425 29,774 31.455 32,929 32,231 29,902 30,996 36,515 3),691 45,243 43,970 33,945

LOAN INTEREST-CHARSEA3LE TO REVENUE 92,022 65 221 575 775 2,225 1,792 3,791 5.959 7,593 9,427 10,747 11,412 12,923 15,t32

LDN ARNNRIIATION 15,542 0 0 0 0 29 125 241 359 432 747 1,942 2,925 3,733 5,034

TOTAL DEPT SERVICE 97,5-4 t5 221 575 775 1,153 1,907 4.022 ,3129 9,020 10,174 12,U61 14,337 21,442 20,1me

PPELININAR DEFERRED EIPENSE 35 i5 0 0 0 0 0 0 0 0 0 0 0 0 0

SHORT-TERM PEPOSITSI(LOANS) 24,749 0 0 0 0 0 0 0 0 0 0 0 0 9,094 15,674

OTHER WORkINS CPITAL-INCHRASEIIDECREASE) 141344 t702 343 1SS (I,692) 12,4921 420 1,937 2,4a0 2,099 1323) 43Z (423) 1,907 10,394

IOTAL APPLICATION OF FUNDS 541,b3! 15,192 7.734 9.942 17,059 29,924 35,345 33,240 38,430 41,015 46,365 50,342 59,141 71,631 30,43Wssssssss:::::: :ssasssss *-st-nsuc .9999S * "%%RSS * .sults *:::sssssss: S2222 *ss-s-sw **Ttsswuxxx x::Lsma :: S8893 3222cm =::::szm #zSz xsasa

CElt SERVICE COYERAeE 2.4 2.9 3.5 3.1 4.0 3.3 2.3 2.0 2.9 2.3 2.4 2.3 2.4 7.I 2.4

Mimi TNE cn OO cmn. wa1 NE^ lUIl CYCL 683300636!Ul

ON1131 SlNM U ul NTl913A12S

IVuE111 WwTIn "111913 1119n m

_Sn .m nn bl.f b i.... _s s

hUlL K13 I977 1Oll 99 17 10 IM 91N 19012 196 50614 am11 I lop4 9 11 96 199 59 19999" I" 599 199 19914 am9 5199

33110191 F0691 611 Film VIM)2 9.5 i 51 m.0 14i.5 50.9 10. 4.41 4.91 7.01 7.01 7.51 7.51 7.5217.51 5.01 5.01 5.01 5.51 L.01 5.61

WI957L 0969f1a2 7 113 a31 9,511 2,1II 3,944 5,619 1,271 4,103 16,514 29,351 23,234I 25,443 25,022 25,440 29,451 3.611 35,446 354114 24,104C.*iviW 7 no0 of 2.57 4,15 V,41 14,164.1 A59 V7,199 41,746 43,097 11,3 11,719 131.155 112,221 195,171 122,115 21,736 291.214 112,3111

0511.L 119911 Sa 1S11lv - MASS1 7 Z2 057 2,077 5,522 9,92 51,4 23,592 32,15 49,291 74,995 5044,729 536,"9 I1751 237.592 53,3156 29M5 34.452 409.14 441,9727 20 ma1 2357 US Ml a1su anu11 13291 2509 4166 1339 39077 46774 490311 135 ON MM9 79M9 1 3 65111

I I CM.CW.I1919. 2ot.01 244.0 24.0 240.0 94.n 1.2 62.91 0.71 52.4 36.311 64.51 12.51 .L1 35.41 JI.2 V.91 10.61 31.11 23.11 17.711

llIlSUl-51-131I191.El ~ ~ ~ ~ ~~0 0 0 0 0 1,141 2,969 9,272 15,353 22,543 75,21 49.744 901,347 212,94 140,354 112,170 201,wr 23.M7I46 36, 11 47,1151

f-ilu'wall.L 1a2131T46l 0 22 n5 ISO 334 417 25 69 2,122 4,229 so,ao4 9,5164 1,11 4,310 5,4901 7,044 9171 9.6111 1,14 7.7TM

:.*ISYE 0 ~~~~~ ~~~12 0 3 564 5,051 1,174 1,5 4,190 6,459 11,1 23 ,167 34,9 39,64 41.29 52,350 42437 11,239 79.13 67,16419251. 6I9621 UV:U61.TI51-Kfk 0 12 44 262 b24 1,217 2,947 2,916 4,794 9,5169 20.669 32,143 41,619 4,61 6,2 4"o ' 1 ,733 65.127 9545 269.132 122.561

OUU*41maUl6Li.m I 12 g0 230 564 993 1192 1 361 1917 3 346 I 5345 55122 3,26 4 321 9949 11514 21 4" 90 664 54747 1 .991 OF CM.CW.912 . 560." 01 4.01 2440 11 200.01 94.51 1Ja.it Eft3 42.45 9.1 11.6It-I E.2 9.41 10.9 En.2 fII li.n I ni 16.51 17.I

7IUE iUII-I6u1M11191.EI 0 0 0 0 0 44 163 1,343 2,523 1,772 7,916 14,4019 37.134 44,404 41.772 13,124 66,9112 72,451 10,942 511.253

PUCIAIII

S1TAI 3L.n I n 0 0 0 0 43 104 35 544 74 U 741 3,5e2 3.5 5,192 ,3913 ' 143 1,35 56.?4 12.125l102utU 2.41 0 0 0 0 0 2 95 35 54 ISO 207 37 6 "I 25 9224 2.602 2,164 I,'M 2,352 2,432lfor.0 0 0 0 6 7 99 30 45 0 ,9 2.1 ,14 5101 1.446 7,M91 ,6729 16,213 11.611 15,517

493t I11t1l3 0 I-10-MII011 0 0 0 0 0 95a 2,721 7,064 14,35 22,4911 14,M 40,702 %4,I17 542,115 130 21 21.1 5 250,13S 37,14 M2,405 3,1-3

FIXlM 914 19113 1964 29 11 9116 9I"7 991 11 199 19'l1 19 19`93 19`94 59 5994

MM KE WAVED6 OUI-I*VMTIU 2.723 7,44 14,3 22,415 30.33 46,702 91,157 142,715 976,23 255,665 26,33 20.616 2.44 432,ff673

1 IH*10E s8 E.i m MIS IN 475 24 219 5 2,949 4,206 4,045 3,32 54.424 19,017 27,944 27,3614 33,025 39,119M65I AE TI*NlU9l421EC I S 2 i9 302 501 0 1,179 2,102 3,371 4, 116 5,144 I 1195 4,923 6,617 9,173L11 1 PCIAtII-V1.0111 Mul 51e 39 12 14 l0e 5941 11,925 12,111 14,143) 25,105 14,61 57,M5 51,7295 610,2135 113,1125 115,175I

101AI1110 11141141111 NI$051 3 30 .55 2,175 2,577 3,279 4,604 4,5162 12,034 1b4,22 20,430 20.014 23.630 34,241

lt! P REI 59 Muwl l 01 1 .9.41 s m 6.61 4.71 4.23 4.41 L.% 7.41 6.11 11.31 6.01 7.91

f6ll 60l1i. Mul 5.41 92.31 19.51 113.1 52.01 10.95 6.91 7.13 99.51 12.161 93.71 4.5 11 95.LK

'lAl

MTIIL TEM PfWE CORPRATI LIENITED

CWICI CYCLE PRO PROJECT

PROJECTED RE311K IMIFFS VERUS LERU W IAL COSTS LRAN)........ _.. _ _ _ __ _ _ _ _ _

COVER1116 FISM VEAS FPlSM Tflh FT 1S4

IPISE PER M

FISCAL YEAR 1983 1594 1935 111 59197 19K 1919 1990 1995 im I93 I94 295 I5n

MORTHERN REGION:

OULt S4PPLY TAIRIP 32.30 36.09 33.95 44.4! 41.06 58.90 42.20 85.30 70.50 73.00 32.10 37.20 92.30 97.70LRNC-ESCALATED FRO Fy1935 4- 40 43.17 52.28 56.70 61.52 88.75 72.42 78.77 51.38 36.26 91.44 94.3TARIFF AS OF LRKC 37.81 92.61 33.22 100.42 101.11 97.1 97.31 101.t1 100.91 101.11 500.91 100.12

WESTERN REuisi:

3LILK SUPPLY TARRIF 38.27 40.00 44.70 44.30 52.50 57.10 61.30 84.30 71.00 75.00 79.40 84.30 39.40LRNC-ESCAIAIED FRDN FYI1S9 39.20 42.53 4b.15 50.07 54.33 53.95 83.9. 47.30 71.37 76.53 60.75 15.STARIFF AS I OF LIMC 102.02 105.11 101.41 104.91 105.lt MM.32 103.7n 104.72 104.41 104.21 104.41 204.42

SOUTHERN RESIGN:

31k SUPPLI TAR1IF 50.00 54.25 53.36 80.23 61.37 84.54 67.03 t9.17 70.41 73.50 79.30 36.50 93.9LRNC-ESCALATED FROM FYlSfJ 42.40 48.22 50.15 54.41 59.03 64.05 49.49 73.14 71.06 32.7b 37.73 92."TARIFF AS I OF LRKN 127.31 127.31 120.11 112.11 109.31 104.72 99.51 95.91 94.15 96.42 9.41 105.01

EASIEIRESION:

k- SULRPPLY 149RJF 54.75 57.54 53.45 59.42 59.97 ".74 71.90 76.30 31.40 37.00 92.60LRNC-ESCALAIED FROM F11955 42.00 45.57 49.44 53.64 58.20 6.15 63.52 72.43 74.99 11.65 34.52 91.70IARIFF AS 2 OF LRM 124.51 524.41 109.02 102.11 95.01 97.41 9.01 99.5 n9.72 200.62 101.01

TOTAL NTPC

WL4I SWL IARRIF 32.30 36.45 41.41 45.35 52.1l 56.77 60.51 63.93 61.47 73.74 77.57 32.62 37.94 93.50LAME-ESCALATED FROM FYilS! 42.44 46.07 49.94 53.97 53.39 43.30 63.62 72.30 77.23 32.111 34.74 95.33IARIFF AS 2 OF LRNC 97.12 104.91 102.42 105.21 103.41 100.91 99.32 101.32 200.4 1200.91 101.42 10*.1j

PROIECTEI TARIFFS: I COMU AVERNE ANA IKREASE. ........ ............ _...................... ... ......

NORTHERN RE61S: FP1193-94 6.92...........

WESTERN RESIN: FY1914-96 1.32

SOITHERN REsowq: FY1954-96 5.41

EASIERN RESIN0: Fv1I9b-9a 5.02.......

WIPC AVERAE FY193-96 3.5. .--------

-65-

ANNEX 4.8Page 1 of 7

INDIA



Assumptions for NTPC Financial Projections

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

(a) income statement (Annex 4.3) with supporting statements andschedules of tariffs compared to Long-Run Marginal Costs (Annex4.7), rates of return on net revalued assets, (Annex 4.6), andscheduled 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) summarized balance sheets as at March 31st of each year (Annex4.4).

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 Ceneration:

Operating CVhs/Mw CHhs/UnitHours/year per year per year

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

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

500 KW Units: - First unit comissioned 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 KW Units: - Subsequent units of each station

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

CTG 100 MW - From commissioning 5500 5.5 550

Combined Cycle(CTG+STG) - First Year : 4000 4.0 400300 KW - Second Year : 5500 5.5 550

-67-


(b) Fuel Costs:

Northern RegionSingrauli Rihand Muradnagar

Coal: 200 & 210 MW Units- Calorific Value (Kcal/Kg) 4900 N/A 3200- Heat Rate (Kcal/KWh) 2131 N/A 2043- Boiler Efficienty Z 87.49Z N/A 87.52%- Kgs per KWh 0.4971 N/A 0.7295- Price per ton-Rs 231.40 N/A 312.15- Cost per GWh: Base Cost 1985 0.1150 N/A 0.2277

Coal: 500 MW Units- Calorific Value (Kcal/Kg) 4900 4000 N/A- Heat Rate tKcal/KWh) 2016 2027 N/A- Boiler Efficienty Z 86.63% 87.00% N/A- Kgs per KWh 0.4749 0.5825 N/A- Price per ton-Rs 231.40 147.78 N/A- Cost per GWh: Base Cost 1984 0.1099 0.0861 N/A

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

SouthernWestern Region Region

Korba Vindhyach Ramagundam

Coal: 200 & 210 MW Units- Calorific Value (Kcal/Kg) 3200 4350 4500- Heat Rate (Kcal/KWh) 2043 2150 2014- Boiler Efficienty Z 87.52% 86.49% 88.60%- Kgs per KWh 0.7295 0.5715 0.5051- Price per ton-Rs 112.84 147.78 258.07- Cost per GWh: Base Cost 1985 0.0823 0.0844 0.1304

Coal: 500 MW Units- Calorific Value (Kcal/Kg) 3200 N/A 4500- Heat Rate (Kcal/KWh) 2016 N/A 2033- Boiler Efficienty Z 86.692 N/A 87.28Z- Kgs per KWh 0.7267 N/A 0.5176- Price per ton-Rs 112.84 N/A 258.07- Cost per GUh: Base Cost 1985 0.0820 N/A 0.1336

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

-68-


Eastern RegionFarakka Kahalgaon Talcher

Coal: 200 & 210 NW Units- Calorific Value (kcal/kg) 3200 3200 N/A- Heat Rate (kcal/kWh) 2020 2150 N/A- Boiler Efficienty % 87.16% 86.49% N/A- kgs per kWh 0.7242 0.7768 N/A- Price per ton-Rs 120.05 120.50 N/A- Cost per GWh: Base Cost 1984 0.0869 0.0933 N/A

Coal: 500 NW Units- Calorific Value (kcal/kg) 3200 N/A 2800- Heat Rate (kcal/kWh) 2027 N/A 2060- Boiler Efficienty Z 86.69% N/A 87.00Z- kgs per kWh 0.7307 N/A 0.8456- Price per ton-Rs 120.05 N/A 78.00- Cost per GWh: Base Cost 1984 0.0877 N/A 0.0660

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

Northern & Western RegionsGas Based Stations All Regions

Combined Cycle Coal FiredCTC (CTG+STG) New Projects

Coal: 200 NW and 210 MW UnitsCombined Cycle Units

- Calorific Value (kcal/kg & - - 3800kcal/Nm ) 8800 8800 -

- Heat Rate (kcal/kWh) 920 920 2043- Boiler Efficienty Z 33.40% 46.53Z 86.69Z- kgs per kWh 0.3130 0.2247 0.6202- Price per ton Rs &

1000 Nm-Rs 1800.00 1800.00 201.86- Cost per GWh: Base Cost 1985 0.5634 0.404 0.1252

Coal: 500 MN Units- Calorific Value (kcal/kg) - - 4520- Heat Rate (kcal/kWh) - - 2027- Boiler Efficienty Z - - 87.00%- kgs per kWh - - 0.5155- Price per ton-Rs - - 201.86- Cost per GWh: Base Cost 1985 - - 0.1041

Fuel Cost Factor to include Oil - - 130.0O

-69-


The escalation rates applied to the above base 1985 fuel costs forcalculating cost increases and tariff fuel surcharges were are set out in(c) below.

(c) Escalation Factors

The financial projections and project costs are based on 1985 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'86 5.0Z 7.0ZFY'87 7.5Z 7.5ZFY'88 8.0% 7.5%FY'89 8.0% 7.5%FY'90 8.0X 7.5ZFY'91 8.0X 5.0%FY'92 and thereafter 5.0% 5.0%

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

Singrauli 200 MS units - 25%Korba, Ramagundam, Farakka, and other 200/210 MW units - 20Z(In the case of Vindhyachal (210 NW units) fixed-price contractsapply)500 MW units for all projects - 15Z Turbo - generators

- 20% Steam - generators

Physical contingencies

Civil works - 10% of construction costsEquipment - 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 - 1.0% on original cost

(e) Depreciation

Power stations - 3.5Z on original cost of plantTransmission - 2.6% on original cost

-70-


(f) Auxilliary Consumption

Auxilliary power consumption for station use has been assumed at 10%for 200/210 MW units and combined cycle gas!steam units and 7% for 500 MWunits.

(g) Tariffs

Tariffs have been based on the formulae of the Regional bulk supplycontracts which provide for:

(i) fuel costs with an automatic fuel price adjustment clause;

(ii) depreciation applied to capital costs escalated to the time ofexpenditure;

(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 (currently13.5Z) on estimated balance of loan principal outstanding; and

Cv) return on equity at 107.

(h) Capital Requirements

Ci) Other capital requirements would be 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 sphare capital and retainedearnings. Equity capital advances would preceed GOI loanfunding except for Bank Loan 2555-IN and the Bank loan for theproposed Project.

(ii) GOI loans (including the onlending of the proposed Bank loanand previously approved credits and loans) are assumed tofinance projects included in NTPC's investment program.Interest on loans up to the date of comfissioning of each unitwould be capitalized, while subsequent interest would be chargedto Revenue. Repayment of principal is assuwied in 30 semi-annualinstallments commencing on the first anniversary following theend of the five-year grace period. The total loan drawdown foreach year, and for each project, is assumed as a separate GOIloan for purposes of loan repayments.

-71-


(i) Balance Sheet

(i) Cash is assumed at 10 days operating expenses less depreciation.

(ii) Accounts receivable are assumed at a level equivalent to fourmonths total operating revenue for FY'85, 3 months for FY'86,and 2 months for FY'87 and for each year thereafter.

(iii) Inventories are assumed at a level equivalent to 15 days coalcosts (including fuel surcharge), 60 days oil costs, 1.5 yearscost of spares requirements, and 6 month's cost of chemicalsand lubricants.

(iv) Loans and advances are assumed at 1Z of annual revenue, Rs 15million, an added Rs 2 million per year to provide for loans toofficers.

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

(vi) Current 'Liabilities are assumed at 1Z of annual fuel costs, 15days of salaries, 2Z of annual operations and maintenance costs,loan principal repayments projected for the subsequent year, and2.5 months' average yearly capital e*penditure.

-72-

ANNEX 4.9Page I of 2

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, the Western (Korba) Region, the Southern(Ramagundam) Regions, and the Eastern (Farakka) Region, represent interimagreements between NTPC and the relevant SEBs for the sale of power, andwill remain in effect until replaced by revised bulk supply contracts.Although the MOUs defined most of the factors, terms and conditions con-sidered necessary by the Bank, clarifications were sought, during nego-tiations for Loan 2442-IN, concerning the validity of the contracts aftertheir expiration dates, provision for a capacity charge, provision forNTPC profits, and the calculation of the flat tariff rates. During thesenegotiations GOI and NTPC provided satisfactory clarification on thesepoints. The Indian delegation provided a copy of a legal opinion that theMOUs will remain legally valid after their expiration date and untilreplaced be revised contracts. They also provided details of the calcula-tion of the interim flat rate tariffs, clarifying that the rates includedcorrectly, all factors which were of concern to the Bank, which includeda NTPC profit component of 10% on GOI equity, and loan interest at theGOI onlending rate (currently 13.5%). It was also clarified that the MOUscontracts include provision for a commitment (capacity) charge, which isnot at present recovered as a separate element in the tariff, but iscovered by the overall variable tariff rate. The Indian delegationexplained that at the present stage of development, the inter-state trans-mission systems had not advanced to the point where NTPC could ensuresupply of the SEBs' agreed power allocations. Owing to the contractualfinancial penalities of non-supply of allocated power, which are a part ofthe commitment charge provision, it was considered premature at that stagefor NTPC to bill SEBs for power sales on the basis of a two-tier tariff(fixed commitment charge plus variable energy charge).

1.02 Contracts have not yet been received for the Bihar and West BengalSEBs of the Eastern Region which were due in July 1984. Submission to theBank of signed contracts for the States of the Eastern and SouthernRegions was made a condition of effectiveness for Loan 2442-IN. At therequest of GOI, the Bank has recently extended the date of loan effective-ness to August 30, 1985, pending receipt of satisfactory bulk supplycontacts for the two outstanding Eastern Region SEBs. During negotiationsfor Loan 2442-IN, GOI and NTPC agreed to provide to the Bank revised bulk

-73-


supply contracts for all four Regions, by March 31, 1986, incorporatingthe following:

(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 for a commitment (capacity) charge be introducedat a time considered appropriate by NTPC; and

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

-74-ANNEX 5.1Page 1 of 5

INDIA



Internal Economic Rate of Return

As described in Chapter 5, the proposed Project forms an integralpart of the expansion programs for the Northern and Western Regions and,therefore, cost-benefit analysis needs to be carried out on each program as awhole rather than on elements of the Project in isolation. A time-slice ofeach Region's investment program has, therefore, been analyzed.l/ Capitalcost, incremental operation and maintenance, incremental fuel cost andbenefit streams for the Northern and Western Regions are shown in Tables 1and 2 respectively. Assumptions underlying these figures are detailed 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 capiftal value: thermal generatingplant 2.5Z, hydroelectric 1.13% (Northern), 22 (western), and transmissionand distribution 1.0%.

1/ The programs analysed predate the Seventh Plan but include the combinedcycle stations which from the proposed Project. Not all of the otherstations included in these programs will necessarily be included in theSeventh Plan, but this will not materially affect the rates of returncalculated.

-75-


Fuel Costs

Average fuel consumption of new coal-fired plant has been estimatedat 0.61 kg in the Northern Region and 0.7 kg in the Western Regiona. Theeconomic cost of coal at the pit head has been estimated at Rs 164/ton. Ithas been estimated that in each Region approximately 65% of incrementalthermal generation will be in minemouth stations and 35Z will be in loadcenter stations. The average economic cost of delivering coal to load centerstations has been estimated at Rs 310/ton. The opportunity cost of gas hasbeen estimated, by reference to fuel oil parity, at Rs 1,800/ MCM. The heatrate of the combined cycle stations is estimated to be 1955 Kcal/kWh and thecalorific value of the gas is estimated to be 8,700 Kcal/normal cubic metre.

Case 1. Benefits

Case 1. benefits are based solely on incremental revenue at existingtariff levels. These allow for system losses which are assumed to remainconstant at 20% of net generation in the Northern Region and 16.5Z in theWestern Region. The average financial tariffs as of January 1, 1985, areestimated to be Rs. 0.49/kWh in the Northern Region and Rs. 0.63/kWh in theWestern. After allowing for (a) an increase in DESU's tariff of just over50% in April, 1985; (b) general inflation of approximately 8% during thecourse of 1985; and (c) a standard conversion factor of 0.8, the correspond-ing average economic tariffs at current prices are Rs. 0.45/kWh in the North-ern Region and Rs. 0.55/kWh in the Western Region.

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 che average tarifffor each category in each Region, and the alternative costs of autogenerationfor industrial consumers and diesel pumping for agricultural.

The cost of industrial autogeneration has been estimated as follows:

Purch be 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. 2500Electricity/diesel(800 hrs/year)Electricity costingX /kWh Rs. 2984 X Rs. 3853

Toeal 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 as ofJanuary 1, 1985, in the Northern Region are estimated at Rs. 0.61/kWh andRs. 0.29/kWh respectively. After allowing for inflation of approximately 8Xduring 1985, estimated willingness to pay, converted into economic terms at astandard conversion factor of 0.8, is Rs. 0.75/kWh for industrial andRs. 1.08/kWh for agricultural. Combining these with revenue estimates of thbbenefits to other consumers gives an averaze benefit of Rs. 0.82/kWh ineconomic terms.

Similar calculations lead to an average benefit of Rs. 0.78/kWh inthe Western Region.

-77- ANNEX 5.1

Page 4 of 5

INDIACOMBINED CYCLE POWER PROJECT

Table 1: Northern Region Investment ProgramEconomic Rate of Return

(Rs million)

Fin. Capital Total Incr. Net Net

Year Exp. O&M Fuel Cost Sales Benefitl Benefit2(Gwh.)

1985 1556 0 0 1556 0 -1556 -1556

1986 4545 13 0 4556 0 -4558 -4558

1987 12562 699 0 13261 0 -13261 -13261

1988 18062 1687 0 19749 0 -19749 -19749

1989 24929 1819 722 27470 1501 -26796 -26232

1990 25870 1309 2221 29399 5794 -26797 -24620

1991 20996 1294 3071 25361 9378 -21149 -17626

1992 17697 1788 4749 24234 15886 -17099 -11130

1993 14916 2130 6313 23359 23522 -12794 -3955

1994 13425 2495 7598 23518 34182 -8165 4678

1995 11525 2316 8910 22752 42878 -3492 12618

1996 787 2316 9377 12479 46303 8318 25716

1997 787 2316 9746 12848 49069 9192 27629

1998 787 2316 10052 13154 51394 9930 29240

1999 787 2316 10319 13421 53446 10585 30666

2000 787 2316 10319 13421 53446 10585 30666

2001 787 2316 10319 13421 53446 10585 30666

2002 787 2316 10319 13421 53446 10585 30666

2003 787 2316 10319 13421 53446 10585 30666

2004 787 2316 10319 13421 53446 10585 30666

2005 787 2316 10319 13421 53446 10585 30666

2006 787 2316 10319 iT421 53446 10585 30666

2007 787 2316 10319 13421 53446 105B5 30666

2008 787 2316 10319 13421 53446 10585 30666

2009 787 2316 10319 13421 53446 10585 30666

2010 787 2316 10319 13421 53446 10585 30666

2011 787 2316 10319 13421 53446 10585 30666

2012 787 2316 10319 13421 53446 10585 30666

2013 787 2316 10319 13421 53446 10585 30666

2014 787 2316 10319 13421 53446 10585 30666

2015 787 2316 10319 13421 53446 10585 30666

2016 787 2316 10319 13421 53446 10585 30666

2017 787 2316 10319 13421 53446 10585 30666

2018 787 2316 10319 13421 53446 10585 30666

2019 787 2316 10319 13421 53446 10585 30666

2020 787 2316 10319 13421 53446 10585 30666

ERR ERR3 12

-78-ANNX $. 1

Page 5 of 5

INDIACOMBINED CYCLE POWER PROJECT

Table 2: Western Region Investment ProgramEconomic Rate of Return

(Rs million)

Fin. Capital Fuel Total Incr. Net NetYear Exp. D&M Cost Cost Sales Benefitl Benefit2

(Swh)

1985 6898 689B -6698 -66961986 10193 10193 -10193 -101931967 16727 7 55 16769 203 -16686 -166431966 22961 174 86 23223 725 -22857 -227011989 20033 287 793 21113 3226 -19484 -167901990 14755 739 2000 17494 7266 -13824 -122621991 11595 965 3383 15944 12545 -9608 -69111992 7517 1636 5495 14647 23182 -2941 20441993 4218 2046 7372 13636 34199 3635 109871994 2408 2107 8438 12952 40595 7549 162761995 812 2124 6927 11863 45360 11054 208111996 2124 9034 11158 45775 11959 218001997 2124 9034 11158 45775 11959 216001998 2124 9034 11158 45775 11959 218001999 2124 9034 11158 45775 11959 218002000 2124 9034 11158 45775 11959 218002001 2124 9034 11158 45775 11959 218002002 2124 9034 11158 45775 11959 218002003 2124 9034 11158 45775 11959 218002004 2124 9034 11158 45775 11959 218002005 2124 9034 11158 45775 11959 216002006 2124 9034 11158 45775 11959 218002007 2124 9034 11158 45775 11959 218002008 2124 9034 11158 45775 11959 218002009 2124 9034 11158 45775 11959 218002010 2124 9034 11158 45775 11959 218002011 2124 9034 11158 45775 11959 218002012 2124 9034 11158 45775 11959 218002013 2124 9034 11158 45775 11959 218002014 2124 9034 11158 45775 11959 218002015 2124 9034 11158 45775 11959 2180020%.6 2124 9034 11158 45775 11959 21800201.7 2124 9034 11158 45775 11959 21800O2018 2124 9034 11158 45775 11959 218002019 2124 9034 11158 45775 f1959 216002020 2124 9034 11158 45775 11959 21800

ERR ERR7 13

-79-ANNEX 6.1

INDIA


Relate.d Documents in the Project File

1. Feasibility Report for Gas Based Combined Cycle Power Project atKawas, Gujarat, Development Consultant Private Limited, Calcutta(India), April 1985

2. Feasibility Report for Gas Based Combined Cycle Power Project atAnta, Rajasthan, Development Consultant Private Limited,May, 1985

3. Feasibility Report for Gas Based Combined Cycle Power Project atAuraiya, Uttar Pradesh, Development Consultant Private Limited,May, 1985

4. Sectoral Data for World Bank Appraisal, CEA, Delhi, June, 1985

5. Project Detailed Cost Estimate - COMPASS, October 22, 1985

6. NTPC, 9th Annual Report, 1984-85

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vPUNJAB.^ i gt COMBINED CYCLE POWER PROJECT

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