Document of The World Bank FOR OFFICIAL USE ONLY

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1 Public Disclosure Authorized Document of The World Bank FOR OFFICIAL USE ONLY Report No IN Public Disclosure Authorized STAFF APPRAISAL REPORT Public Disclosure Authorized INDIA CENTRAL POWER TRANSMISSION PROJECT Public Disclosure Authorized Regional Projects Department South Asia Regional Office April 26, 1983 This document has a restricted distribution and may be used by recipients only in the performance of their official duties. Its contents may not otherwise be disclosed without World Bank authorization.

2 CURRENCY EQUIVALENTS. Currency Unit = Rupee (Rs) Rs 1 Paise 100 US$1 = Rs 9.5 1/ Rs 1 Rs 1 million = US$ / US$105,267 1/ MEASURES AND EQUIVALENTS 1 Kilometer (km) = 1,000 meters (m) = miles (mi) 1 Meter (m) inches (in) 1 Cubic Meter (m ) = 1.31 cubic yard (cu yd) = cubic feet (ft) 1 Hectare (ha) = 10,000 m = acres (ac) 1 Kilogram (kg) = pounds (lb) 1 Ton (t) = 1 meteric ton = 2,200 lbs 1 Kilocalorie (kcal) = British Thermal unit (Btu) 1 Kilovolt (kv) = 1,000 volts (V) 1 Kilovolt ampere (kva) = 1,000 volt-amperes (VA) 1 Megawatt (MW) = 1,000 kilowatts (kw) = 1 million watts 1 Kilowatt hour (kwh) = 1,000,000 watt hours 1 Megawatt hour (MWh) = 1,000 kilowatt hours I Gigawatt hour (GWh) = 1,000 kilowatt hours I Mega volt ampere (MVA) = 1,000 kilovolt ampere (kva) 1 Mega volt ampere reactive (MVar) = 1,000 kilovolt ampere reactive (kvar) I Mega volt ampere reactive hour (MVarh) = 1,000 kilovolt ampere reactive hour (kvarh) ABBREVIATIONS AND ACRONYMS AC - Alternating Current AIC - Average Incremental Cost APSEB - Andhra Pradesh State Electricity Board CIF - Cost Insurance Freight CEA - Central Electricity Authority DC - Direct Current HT - High tension HVDC - High Voltage Direct Current GOI - Government of India IDA - International Development Association KfW - Kreditanstalt fuer Wiederaufbau LOLP - Loss of Load Probability LT - Low Tension MPC - Mysore Power Corporation NHPC - National Hydro Power Corporation NTPC - National Thermal Power Corporation OPEC - Organization of Petroleum Exporting Countries PERT - Program Evaluation and Review Technique PLCC - Power Line Carrier Communication REB - Regional Electricity Board SEB - State Electricity Board NTPC's FISCAL YEAR (FY) April i - March 31 l/ The US$/Rs exchange rate is subject to change. Conversions in this report have been made at US$l to Rs 9.5, which represents the projected exchange rate over the disbursement period.

3 -1i- FOR OFFICIAL USE ONLY INDIA CENTRAL POWER TRANSMISSION PROJECT STAFF APPAISAL REPORT Table of Contents Page No. I. THE POWER SECTOR Background... Past Bank Group Involvement in the Sector... 2 Bank Group's Strategy... 3 Southern Region Demand and Supply... 6 II. THE BENEFICIARY - NATIONAL THERMAL POWER CORPORATION LIMITED. 8 Legal Status and Authorities *... 8 Organization and Management Recruitmnt and Training Accounting Organization and Systems Audit... * III. THE PROGRAM AND THE PROJECT The Program The Project Estimated Cost Project Financing Engineering Construction and Procurement.. 18 Disbursemernt Ecology... o o. 19 Project Risks IV. FINANCIAL ANALYSIS A. NATIONAL THERMAL POWER CORPORATION LIMITED (NTPC) Investment Program Future Earnings NTPC Consolidated Operations NTPC Regional Operations 23 - Taxation This project was appraised by Messrs. Victor Antonescu (Power Engineer), John Creasor (Financial Analyst), Karl Jechoutek (Economist) and Yves Albouy (Economist), based on information obtained during a mission in September/ October This document has a restricted distribution and may be used by recipients only in the performance of their official duties. Its contents may not otherwise be disclosed without World Bank authorization.

4 Page No. - Internal Cash Generation FY1977-FY NTPC's Financing Plan FY1983-FY Onlendiing Agreement Future Finances Borrowing Powers Commercial Arrangements for Sale of NTPC Energy..27 B. ANDHRA PRADESH STATE ELECTRICITY BOARD (APSEB) Investment Program Future Earnings Internal Cash Generation. 29 V. JUSTIFICATION AND ECONOMIC ANALYSIS.. 30 General.. 30 Method of Analysis.. 30 Intra-Regional Lines Southern/Western Region Intertie...32 Northern/Western Region HVDC Intertie.. 33 Tariffs and Cost of Supply...33 VI. SUMMARY OF AGREEMENTS AND RECOMMENDATION ANNEXES 1. Power Sector Loans and Credits Electricity (Supply) Act Proposed Ammendments, October Rates of Return of SEBs (FY FY1982) All-India Sales and Energy Data 1974/75 to 1981/ Long-term System Expansion Plan Southern Region Sales and Energy Data 1979/ / Southern Region: Installed Capacity, Peak Load and Energy Requirement 1977/ / Southern Region Power Supply Restrictions NTPC - Organizational Structure (Revised) NTPC - Manpower as of September 30, NTPC - Recruitment of Trainees NTPC - Organizational Structure Corporate Finance Project Description Project Cost Estimates Implementation Schedule Estimated Schedule of Disbursements Schedule of Commissioning of Power Plants and Power Generation Versus Schedule at Time of Second Ramagundam Appraisal.88

5 -iii- Page No. 18. Investment Program for the Period FY1977 through FY Comparison of Current Cost Estimates with Previous Appraisals Statement of Plant Capacity, Generation and Sales of Energy NTPC - Income Statement Covering Operations FY1983 through FY NTPC - Sources and Application of Funds for the Period FY1977 through FY NTPC - Balance Sheets FY1977 through FY NTPC - Assumptions for Financial Projections NTPC - Income Statement Covering Operations FY1983 through FY Northern Region NTPC - Income Statement Covering Operations FY1983 through FY Western Region NTPC - Income Statement Covering Operations FY1983 through FY Southern Region NTPC - Income Statement Covering Operations FY1983 through FY Eastern Region APSEB - Income Statement Covering Operations FY1980 through FY APSEB - Net Internal Cash Generation FY1980 through FY APSEB - Balance Sheet as at end of FY1980 through FY Southern Region - Additional Transmission Requirements Costs and Benefits of Intra-Regional Transmission Southern/Western Transmission Link: Least-Cost Solution I 35. Northern/Western D.C. Link: Least-Cost Solution APSEB Tariffs Marginal Cost of Electricity Supply in Andhra Pradesh Documents Available in the Project File MAP IBRD R

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7 INDIA CENTRAL POWER TRANSMISSION PROJECT Background I. THE POWER SECTOR 1.01 The development of India's economy and the improvement of its people's standard of living depend to a large degree on the development of the power sector. Over the last two decades, power demand has grown twice as fast as the economy, and the power sector now takes the largest share of public investment (12% of the Sixth Five-Year Plan outlay). This was due to the rapid development of power-intensive industry and the expansion of rural electrification tor irrigation In spite of an increase in generating capacity from 5,600 MW in 1960 to about 32,000 MW in 1982, power shortages have been experienced in various -arts of the country for a number of years, and gaps between supply and demand will impose major constraints for some years to come Before 1975, power facilities were planned, constructed and operated by each State to meet its own needs. Because of the rapid growth of thle power sector, the Government of India (GOI) decided to create new institutional structures in the sector, and to emphasize central planning of generation and high voltage transmission with the ultimate objective of central control through a national grid. The Central Electricity Authority {CFA) performed studies of a national power system, and GOI decidegvto proceed with the construction of four large centrally-owned thermal power stations located at coal fields, supplying bulk power to the States through an interconnected 400 kv transmission system. The construction of these power stations (2,000 MW at Singrauli, 2,100 MW at Korba, 2,100 MW at Ramagundam, and 600 MW at Farakka) was begun with Bank Group financial assistance. The first phase of the program comprised the first stage of 600 MW at each plant, and its associated transmission. In addition, IDA Credits for the second stage of Singrauli (1,400 MW) and the second stage of Korba (1,500 MW), and a Bank loan for the second stage of Ramagundam (1,500 MW), have been approved. A proposal for the second stage of Farakka (1,500 MW) has been submitted recently for consideration by the Bank Group. The subject of this report is the extension of NTPC t s 400 kv transmission system to increase the capacity of power transmission from Ramagundam to the Southern part of the country and to interconnect the Northern, Western and Southern Regional grids. A Bank loan of US$250.7 million is proposed The energy and power sectors and the problems associated with the latter have been fully described in the Staff Appraisal Report No. 3608b-IN

8 -2- dated November 30, 1981 for the Second Ramagundam Thermal Power Project.1/ The following paragraphs deal only with the changes that have occurred since or with sector aspects directly related to the proposed project. Updated information in regard to the Indian power sector is provided in Annexes 2 to 5. Past Bank Group Involvement in the Sector 1.05 The Bank has made thirteen loans for Indian power projects amounting to US$982.5 million, and fifteen IDA credits totalling US$2,096.0 million (Annex 1). Fifteen projects financed under the following loans and credits have been completed: ten generating projects, the Beas Project (Credit 89-IN), the first three transmission projects (Loan 416-IN, Credits 242-IN and 377-IN) and the First Rural Electrification Project (Credit 572-IN). The Fourth Transmission Project (Credit 604-IN) is expected to be completed in the first half of The Third Trombay Thermal Power Project (Loan 1549-IN), Singrauli (Credit 685-IN), Korba (Credit 793-IN), and Ramagundam (Credit 874-IN and Loan 1648-IN) Thermal Power Projects, and the Second Rural Electrification Project (Credit 911-IN) are in an advanced stage of implementation. The credit for the Second Singrauli Thermal Project (Credit 1027-IN) and the credit/loan for the first stage of the Farakka Thermal Power Project (Credit 1053-IN and Loan 1887-IN) were approved in May and June Korba II (Credit 1172-IN) was approved in July 1981, Ramagundam II (Loan 2076-IN) in December 1981 and the Third Rural Electrification Project (Loan 2165-IN) in June The Trombay and Second Rural Electrification Projects are on schedule. The three 200 MW units of the Singrauli Project and the first 200 MW unit of the Korba Project were commissioned on schedule. The Farakka and Ramagundam Projects are proceeding satisfactorily after initial delays A Project Performance Audit Report on the Second Power Transmission Project (Credit 242-IN), issued on June 3, 1980, stated that the project had been successful in assisting nine State Electricity Boards in extending their transmission systems to help meet their growing requirements. Utilization of generating capacity in the nine SEBs exceeded the appraisal forecast. Institutional objectives mainly concerned the rehabilitation of the finances of the SEBs, and while the results achieved by project completion were modest, improvement was continued by the Third and Fourth Power Transmission Projects (Credits 377-IN and 604-IN). In FY 1980, seven of the nine participating SEBs reached their target rate of return of 9.5%. The conclusions of the Report pointed to: (a) the difficulty for the Bank Group in adequately supervising work other than procurement on the project, since 1/ Second Ramagundam Thermal Power Project Staff Appraisal Report (Report No. 3608b-IN) paragraphs 1.04 to 1.12 and 1.17 to 1.35.

9 -3- it consisted of many sub-projects scattered all over India, and (b) the absence of a close working relationship between the Bank Group and the beneficiary SEBs, which made efforts for institutional improvements difficult. The Report suggested that more direct involvement with the SEBs in projects of this nature, where an efficient intermediary is not available, would be beneficial. Bank Group's Strategy 1.07 The Bank Group's strategy in the Indian power sector has been to cooperate with GOI in finding solutions to the many difficult and politically sensitive problems confronting the Indian electricity supply industry. The Bank's main objectives in the sector are: (a) to eliminate power shortages by the installation of generation and transmis3ion capacity, and the promotion of measures to improve the operation and maintenance of existing plant; (b) to introduce long-range system planning on a nationwide basis so as to assure implementation of a -' least-cost power development program; (c) to promote improvements in sector organization and training; and (d) to strengthen the finances of the institutions in the sector, particularly the State Electricity Boards The States, through their Electricity Boards, develop and operate most power facilities. Under the Constitution, power supply is a concurrent subject, which means that responsibility is shared between the Central Government and the State Governments, requiring full agreement between them before action can be taken. Despite many difficulties, improvements achieved so far have been encouraging. With the establishment of Regional Electricity Boards (REBs), the National Thermal Power Corporation (NTPC) and the National Hydro Power Corporation (NHPC), important steps towards an improved organizational structuy'e of the power sector have been made. CEA was reorganized and its powers enlarged; amendments in the financial provisions of the Electricity (Supply) Act clarified the requirements to be followed in tariff setting, the financial performance of SEBs improved, the majority of SEBs have completed tariff studies based on marginal cost pricing principles, CEA has prepared a national long-term power development plan, and the implementation of increased investments in the sector will help eliminate the power deficit Because of the rapid expansion of the power industry, all aspects of the sector needed to be reviewed and solutions found for its various problems. GOI established in 1978 the Committee on Power, which submitted

10 -4- its conclusions to GOI in September They refer to all major aspects of the power sector including planning, project formulation and implementation; operation and maintenance; organization and management; finance, financial management and tariffs; rural electrification; and research and development. The recommendations of the Committee on Power, most of which are satisfactory in light of the Bank Group's strategy, form a basis for improvement of all those aspects of the power sector. Implementation of the Committee's recommendations has already started with those aspects that do not require GOI's formal approval, such as better planning procedures and improved operating and maintenance management In accordance with undertakings agreed during negotiations for the Second Korba Thermal Power Project, GOI submitted, in May 1982, a program for the implementation of five categories of power sector improvements which the Bank Group considered areas of high priority. Satisfactory progress has been made in these five areas for which some of the more recent activities and achievements are as follows: (a) Performance of Thermal Power Plants The Department of Power in GOI has established teams of specialists, including representatives from CEA, SEBs and manufacturers, to visit all thermal power plants with 100/120 MW and 200/210 MW generating units in the country to diagnose technical and operational problems, propose solutions, and assign responsibilities for their implementation. Repeat visits are planned to assess progress. (b) Coordination of Power Development and Growth in Other Sectors The Bank Group received the draft national long-range plan for power development in September This plan provides forecasts of power demand through the year 2000 and projects the generating capacity and equipment that will be required to meet this demand. The draft plan, which is expected to be finally adopted by the Government, will provide the basis for both five-year plans andl annual investment programs. (c) Intensification of Hydro-Electric Power Development GOI is progressing with plans for a number of hydro projects, some of which will be proposed for Bank Group financing and others for bilateral assistance. Several projects -- among them Vishnu Prayag (UP), Lohari Nag (UP), Naptha Zhakri (HP), Puyan Kutti (Kerala), and Lower Periyar (Kerala) -- have reached advanced stages of project preparation. The Upper Indravati project, the first hydro-power project in India to be proposed for Bank Group financing, is presently being appraised. In addition, GOI is planning to begin investigations on what is expected to be the largest hydro-power project in the world -- the 15,000 MW Dihang project in north-eastern India, where a number of other projects are also under consideration.

11 -5- (d) Strengthening the Role of the Central Sector in Power Generation and Inter-state High-Voltage Transmission (i) GOI, through NTPC, has under construction and partly in operation over 9,000 MW of power generating capacity. In addition to the four ongoing Bank-Group financed super-thermal plants (Singrauli, Korba, Ramagundam and Farakka), which (except for Farakka) are now in their second phases of construction, two large thermal power plants -- the 1000 MW plant at Rihand (UP) and the 1260 MW plant at Vindhyachal (MP) -- are also being undertaken by NTPC. Agreements with the UK and USSR, respectively, for the financing of these plants were signed in 1982 (para 4.10). (ii) The proposed project is designed to reinforce the Centrallyowned NTPC power transmission grid, and provides the first stage of integration of the Northern, Western, and Southern regional grids, taking into account compatability for eventual energy pooling. (e) Establishment of Financial Objectives and Policies for their Implementation, Principles for Evolving Rational Tariff Policies and Improvements in Management Information and Accounting Systems for State Electricity Boards. (i) Draft legislation for amendment of the financial provisions of the Electricity (Supply) Act, 1948 has been prepared by GOI for submission to Cabinet at the next session of Parliament, early in These amendments will remove some of the anomalies in the Act which have been in the past the source of a number of problems relating to the financial performance of the SEBs (Annex 2). (ii) Management consultants have started the review of present accounting practices in two of the SEBs with the ultimate objective of developing a uniform system of commercial accounting for adoption by all of the SEBs. Their review will be followed by preparation of a draft accounting manual by September 1983 which will form the basis of the new accounting system scheduled for introduction in An accounting unit is at present being established within CEA to monitor the development of the new accounting system and the financial performance of the SEBs. (iii) With the Third Rural Electrification Project, approved in June 1982, new financial performance criteria for the SEBs were introduced. These are designed to provide for reasonable

12 -6- contributions by the SEBs to power investment, and to gradually reduce State Government subsidies for rural electrifica;4ion losses. Southern Region Demand and Supply 1.11 Data concerning the all-india power demand and supply situation and outlook are provided in Annex 4. The following paragraphs of this chapter deal with the demand and supply situation of the Southern Region where the proposed project is located. The major authorities supplying the Southern Region are the Tamil Nadu, Andhra Pradesh, Karnataka and Kerala State Electricity Boards, and the Mysore Power Corporation (MPC). In addition, a number of small municipalities are engaged in power supply. All entities, except MPC, supply electricity to final consumers, but only the four SEBs and MPC own generation facilities. MPC supplies about 85% of the power made available to consumers by the Karnataka SEB The Southern Region is the only fully integrated electricity supply region in India, controlled by a Regional Load Dispatch Center at Bangalore. Load frequency control equipment at Bangalore is now operational. The large hydro component in the system allows energy to be transferred during the monsoon from SEBs with a reservoir-spilling surplus to others in the Region, while in the early summer months thermal generation is maximized to husband scarce water. In addition to its internal integration, the Region often operates in parallel with the Western Region, particularly the States of Maharashtra and Gujarat, and with Orissa in the Eastern Region In line with the national pattern, Regional consumption is heavily oriented towards industry: about 61% of total consumption in the Region is attributable to industrial consumers, and about 18% to agricultural consumers. This pattern masks significant differences among States. The share of agricultural consumption in Tamil Nadu is about 27%, while 70-75% of Karnataka's and Kerala's supplies go to industry and only 5-8% to agriculture. Tamil Nadu is the dominant State in the Region with about 40% of the total consumption of electricity. Sales in the Region have been growing at a steady rate of about 7% p.a. between 1970 and 1980, most of this in periods of supply restrictions. Generation and sales growth in 1979/80 was a minimal 2% largely due to widespread supply difficulties and low reservoir levels, followed by a return to normal growth in 1980/81 (Annex 6) Andhra Pradesh is the only State in the Region that has more than 50% thermal capacity; Kerala and Karnataka are solely hydro. While installed capacity has grown at about 7% p.a. between 1970 and 1980, actually available capacity at peak showed a growth rate of about 7.5%, resulting in a significant improvement in availability from about 65% to more than 70%. As energy consumption has been increasing at an annual rate of 7% the system load factor decreased to about 57% in 1980, from more than 60% in the early

13 s, making the system peak more pronounced. In recent years, development has been erratic. Installed capacity has been increasing at about 7% p.a., but peak availability declined to just slightly above 60% of installed capacity. Forced outages have suppressed the growth of peak demand, increasing the system load factor to more than 70% (Annex 7). As in previous years, severe supply restrictions were imposed mainly in Karnataka and Kerala, especially on industrial consumers in 1981/82, ranging from 10% to 50% of potential demand or connected load (Annex 8) Potential unconstrained peak capacity demand in the Region is expected to grow at about 9% p.a. until 1995, energy demand at about 8%. Large capacity additions due to come on stream during 1982/83 and in subsequent years are expected to increase supply reliability almost immediately. The expected loss of load probability during the 1980s is reasonably low, even with high forced outage rates. Much depends on timely approval and implementation of generation projects, and the provision of appropriate transmission capacity (Annex 5).

14 -8- II. THE BENEFICIARY - NATIONAL THERMAL POWER CORPORATION LIMITED Legal Status and Authorities 2.01 NTPC, the beneficiary of the proposed credit, was established in 1975 and is registered under the Companies Act, It is a company wholly owned by GOI and functions under the general supervision cf the Ministry of Energy. Its initial authorized share capital of Rs 1,250 million (US$132 million) was increased to Rs 8,000 million (US$842 million) in June 1980 and Rs 15,000 million (US$1,579 million) in September The paid-up capital of the Corporation on Septeber 30, 1982 was Rs 10,047 million. The Corporation has a Board of ten Directors including the Chairman and Managing Director Under its Memorandum and Articles of Association, NTPC has broad powers to carry out its work. However, the tariffs to be applied as well as any changes in such tariffs, its investment plans and annual capital budgets, have to be approved by the Government. NTPC is also subject to periodic examination by the Committee on Public Undertakings--a body established by GOI to monitor the performance of public sector enterprises The main objectives for which the Corporation was established are: (i) to design, construct, and operate large central thermal power stations and transmission systems; and (ii) to transmit anid sell the power generated. With the approval of the proposed project, NTPC will be constructing most of the EHV (extra high voltage) transmission system being established by the Central Government to develop effective interconnected regional systems for ultimate integration into a national grid. NTPC will own and operate this 400 kv transmission system, over which power will be distributed from each plant and sold in bulk to SEBs, as well as the inter and intra-regional links being established under this project. Later these systems will be part of the 400 kv interconnected regional systems which, subsequently, is intended to be integrated into the national grid NTPC's present program provides for the construction of six thermal power stations (Singrauli, Korba, Ramagundam, Farakka, Rihand and Vindhyachal). It is also possible that NTPC might ultimately take over ownership of the 720 MW Badarpur station near Delhi, which is at present being managed by NTPC on a management-fee basis. NTPC has also undertaken investigations for identifying additional sites for thermal power stations in the Central sector. Based on these studies, feasibility reports submitted by NTPC for pithead developments at Kahalgaon (Bihar), Talcher (Orissa) and Pench (Madhya Pradesh) are under consideration by COI. Feasibility studies for other sites, i.e., a Capital Region project near Delhi, Birbhum (West Bengal) and Mangur (Andhra Pradesh) are under formulation. The total combined capacity to be installed at these sites in the first instance is

15 -9- likely to be about 4,000 MW while the ultimate potential is estimated to be nearly 10,000 MW. Organization and Management 2.05 NTPC has entered the operational phase of its development with the commissioning of the first three generating units constructed by NTPC. The most recently installed 210 MW unit at the Badarpur Thermal Power Station near Delhi was synchronized in December 1981 while the first two 200 MW units at Singrauli were commissioned in February 1982 and November 1982 respectively JIi7PC's organization has so far been construction oriented to cater to the predominant activity of construction work on the large power plants. A revised corporate organization structure (Annex 9) has now been designed keeping in view the beginning of the operations phase of the power plants and the growth and expansion, in both power generation and transmission, envisaged for the Corporation in the years to come. 2X07 Earlier, NTPC had adopted a three-tier organization structure. The first tier consisted of the corporate functions of Planning and Marketing, Personnel and Finance which were entrusted with normal corporate level responsibilities. The second tier consisting of other services relevant to the construction phase of the projects such as Technical Services, Contract and Procurement Services, Quality Control, Expediting and Project Management Services were centralized as service functions and located at headquarters. The third tier, which embraced direct project activities, consisted of a project organization for each of the four power plants which were under construction. Each project organization was headed by a General Manager entrusted with total responsibility for implementation of all aspects of the project's construction program. Under this structure, the heads of the corporate and service functions departments, as well as heads of project organizations, reported to the Chairman and Managing Director. This, with accent on centralization at the corporate level, had some major advantages which undoubtedly served the organization well during the formative years However, with the recent addition of the Rihand and Vindhyachal projects and the advent of the operational phase of both generation and transmission, there has been a significant increase in the task before NTPC in terms of volume, dimension and complexity. The increased scale of activities, as well as the geographically dispersed nature of operations, brought into focus the need for greater decentralization. In consultation with the Central Electricity Generating Board of U.K., an organizational study was undertaken. As a result of this study, and in-house efforts, a revised organization structure was developed. The proposals formulated in this regard have now been considered and approved by the Board of Directors of the Corporation.

16 Under the new organizational structure (Annex 9), regional groups headed by Executive Directors have been formed with total responsibility for planning, design, procurement, construction, commissioning, operations and maintenance for thermal power stations and associated transmission facilities in each region. These activities will be carried out within the framework of overall guidelines laid down by the corporate headquarters. Teams for each project have also been constituted at the regional level consisting of groups for planning, engineering, contracts and expediting and will be headed by senior level officers. This will enable greater accountability of the technical support functions to the project organizations. At present the regional headquarters are functioning from Delhi. However, at an appropriate time they will be shifted to suitable locations within the boundaries of the respective regions. The organizational set-up at project sites remains the same as before Under the new set-up the role of the corporate center will be one of policy making and providing functional guidance to the regional and project organizations. In addition to the corporate functions of Finance, Personnel and Planning and Monitoring, a core engineering group responsible to Director (Technical) and a techno-commercial group responsible to Executive Director (Commercial) are proposed to be created. In order to ensure uniform implementation of policies and corporate guidelines, various groups and departments at the regional and project levels will be functionally responsible to the corresponding staff departments at the Corporate Center The decentralized organizational structure should contribute significantly to the effective management of the expanding Corporation through providing for a greater delegation of responsibility and authority and through establishing accountability and measurement of performance on regional and sub-regional levels. Recruitment and Training 2.12 NTPC is a young organization which is growing rapidly to meet the demands of its large construction program. The next phase of expansion wil1 involve the need to recruit and train operating staff. When all current developments have been completed and commissioned, NTPC will have a staff of about 21,000. The importance, therefore, of implementing training programs for the various skills required during the construction and operational phases cannot be too highly stressed. Manpower by category of staff at September 30, 1982 and additional recruitment required to meet projected requirements by FY1990 are provided in Annex 10. NTPC's present manpower represents 43% of its FY1990 requirement (48% for executives, 50% for Supervisors, and 37% for skilled and unskilled staff). These figures show that recruitment is progressing at a sufficiently satisfactory level to meet operational needs as plant completions progress and commercial operations expand.

17 NTPC has placed special emphasis on the importance of training in its organizational development, and programs are being developed by the Corporation which will be backed by 200 MW and 500 MW simulators, financed from the proceeds of Credits 793-IN and 1053-IN, as well as other modern facilities for instructing and training the operating staff. Well planned and well structured training programs have been developed for all categories of staff. The program is being effectively executed and is modified and improved on a continuing basis in light of actual experience. Trainee recruitment, by category of staff, to date and projected requirements to FY1990 are set forth in Annex 11. Actual trainee recruitment to date as a percentage of projected requirements by FY1990 is 19% (executives 34%, Supervisors 18%, and skilled workers 9%) Training programs which previously have concentrated on pre-operational activities such as Planning, Design and Construction Management, are now aimed more at operations. Some of the current major activities are: (a) Training in professional engineering for executive trainees. (b) Training in professional engineering for supervisory trainees. (c) Accounting training for accounting and managerial staff. (d) Management development programs. (e) Seminars and lectures on selected topics. (f) Familiarization courses for both accounting and managerial staff on the accounting systems and procedures being implemented. Mainly engineering graduates (mechanical, electrical, civil) are being recruited and inducted into a one-year training program. The first group of 35 young executive trainees was recruited in February Since then six more groups consisting of 831 trainees have been recruited, the last of which (150 trainees) was recruited in September The training programs have been well designed to provide exposure to construction and operation, equipment manufacturing plants, engineering and project management services. For these purposes, assistance is taken from a large faculty of experienced engineers and managers selected throughout the country. NTPC is also utilizing the facilities of the Central Electricity Generating Board (U.K.) for training of operation and maintenance staff The first two 200 MW generating unit (at Singrauli), which commenced operation in February and November, 1982 respectively, have been adequately

18 -12- staffed. Advance action has been taken for the requirement of subsequent units for which 146 executives and 119 supervisors are in postion. NTPC has finalized comprehensive plans for training operational staff, particularly the non-supervisory staff in the various technical and non-technical trades, and to provide foremen for the 200 MW units at Singrauli and Korba. The manpower for these is being drawn from experienced staff as well as from fresh recruitment. The personnel required for the first 200 MW unit at Korba are already in position. Recruitment of operational manpower has also commenced for the subsequent units at Korba and Ramagundam. Key personnel required for the associated transmission systems, together with adequate support staff, are in position On-the-job training has high priority. The methodology includes classroom lectures, participation in group exercises and discussions supported by direct reading, audio-visual presentations and plant visits. Overall training plans and arrangements at this time are satisfactory. Accounting Organization and Systems 2.17 NTPC continues to report good progress in the planning and implementation of its finance and accounting organization (Annex 12) and in the design and implementation of accounting systems and procedures. The design of accounting systems for both the construction and operational phases of NTPC's activities has been completed. Implementation of systems for the construction phase has been completed both at the corporate center at headquarters, and also at the sites, while systems for the operational phase have been designed and are being implemented at Singrauli. Consultants are being utilized for the on-going implementation of systems. To familiarize staff with the systems and procedures, training courses are being conducted by the consultants in conjuction with staff members from NTPC's Corporate Center. Audit 2.18 The audit of NTPC's accounts and records is undertaken by a professional auditor appointed by the Company Law Audit Board, on the recommendation of the Comptroller and Auditor General of India. The auditor is normally a member of the Indian Institute of Chartered Accountants, and his audit report on NTPC's financial statements is subject to comment by the Auditor General. For the audit of the accounts for FYs 1980, 1981 and 1982 two auditors were appointed, Messrs.Raghu Nath Rai and Company and Messrs. Prasad Azad and Company, both firms of Indian Chartered Accountants. There were no adverse comments from the auditors on the accounts of each respective year and the audits were satisfactory to the Bank. It should be borne in mind that NTPC's activities covered only project construction until FY 1982 when power was sold for the first time. NTPC has already undertaken in connection with previous credits and loans to furnish to the Bank Group audited financial statements within seven months of the end of the fiscal

19 -13- year to which they relate, together with a certified report by the auditors, and a review of the accounts by the Director of Commercial Audits. This undertaking has been reconfirmed during negotiations for the proposed Loan.

20 -14- III. THE PROGRAM AND THE PROJECT The Program 3.01 NTPC's development program, previously consisting of four central power stations with associated 400 kv transmission (Singrauli, Korba, Ramagundam and Farakka), has recently been expanded to include two additional power stations, Vindhyachal and Rihand, as well as the proposed Fifth Power Transmission Project. All power plants are situated at coal fields as the resulting reduced coal transport costs far outweigh the increased costs of power transmission. The Vindhyachal Project will be located near Waidhan in Madhya Pradesh with an initial capacity of 1,260 MW and ultimate envisaged capacity of 2,260 MW, while the Rihand Project will be located near Bijpur in Uttar Pradesh with an initial capacity of 1,000 MW and an ultimate capacity of 3,000 MW. With the addition of these two new projects NTPC's approved current development program, which is compatible with the India Long Term Power Plan, will provide a total capacity of 9,060 MW. The Project 3.02 The Project would provide for: (i) an increased capacity of power transmission from the Ramagundam thermal power plant (2,100 MW final capacity) to the southern part of the country; (ii) a strong power transmission tie between the predominantly hydro-based Southern Regional grid and the predominantly thermal-based Western Regional grid; and (iii) an asychronous inter-tie between the Northern and the Western Regional grids which would permit larger power transfers to meet the growing system needs in the context of the present stage of system operation, control and communication facilities while also ensuring the stability of the systems. K 3.03 The Project would include: about 550 km of 400 kv double-circuit lines, and 560 km of 400 kv single-circuit lines; the construction or extension of a number of related 400/220 kv substations; a back-to-back high voltage direct current (HVDC) substation at the future Vindhyachal thermal power plant as part of the 400 kv asynchronous link between the Singrauli and Korba thermal power stations; technical services for the carrying out of detailed equipment and system engineering and supervision during construction, for the HVDC back-to-back line at Vindhyachal; and, metering, instrumentation and communication facilities. The proposed project also provides power line carrier communication (PLCC) equipment for speech transmission, line protection and data transmission on each 400 kv line The Central Power Transmission Project, which is described in detail in Annex 13, provides for the construction of the following 400 kv lines and 400/220 kv substations (see attached map):

21 -15- (a) Lines Approximate length Ramagundam - Mangur, double circuit line 230 km Mangur - Vijayawada, double circuit line 160 km Vijayawada - Nellore, single circuit line 305 km Nellore - Red Hills, single circuit line 245 km Singrauli - Vindhyachal, single circuit line 14 km Ramagundam - Chandrapur, double circuit line 158 km (b) Substations Estimated Cost Ramagundam - extension for the 400 kv Ramagundam - Chandrapur line and for the second 400 kv Ramagundam - Mangur circuit (the equipment for the first circuit is provided under the Second Ramagundam Thermal Power Project) Mangur - new (Ix315 MVA) Vijayawada - new (1x315 MVA) Nellore - new (lx315 MVA) Red Hills - extension for the 400 kv Nellore - Red Hills line Chandrapur - extension for the 400 kv Ramagundam - Chandrapur line Singrauli - extension for the 400 kv Singrauli - Vindhyachal line Vindhyachal- extension for the 400 kv Singrauli - Vindhyachal line and a 500 MW twin modula (two 250 MW) HVDC back-to-back inter-tie linking the Singrauli and Korba thermal power plants The estimated cost of the Project, excluding interest during construction, duties and taxes, and front-end fee is Rs 4,750 million US$500 million) Based on the experience with similar projects in India, the direct and indirect foreign currency costs are estimated at about Rs 1,864 million (US$193 million) and the local currency cost at Rs 2,916 million (US$307 million). The estimated costs of the Project are set out in Annex 14 and summarized in Table 3.1 below:

22 -16- Table 3.1: ESTIMATED COST Local Foreign Total Local Foreign Total Rs Million US$ Million kv lines 1, , kv substations Back-to-back HVDC substation Metering and Instrumentation PLCC Communications Sub-total 1, , , Physical Contingencies Price Contingencies Total 2, , , Consultancy Engineering and Administration Total Project Cost 2, , , (before duties and taxes) Duties and Taxes Total Project Cost 3, , , Interest during Construction Front-End Fee Total Financing Required 4, , , The estimates for the main items of equipment and materials are based on the quotations received since 1980 for similar projects, such as the 400 kv links and substations associated with the Singrauli, Korba, Ramagundam and Farakka power plants, with prices updated to mid-1982 levels. It has been assumed that the foreign cost would represent the following percentages of

23 -17- the total cost: 100% of the cost of equipment for the HIIVDC substation, the metering and instrumentation and the communication equipment; 80% of the cost of steel in the towers for 400 kv lines; 50% of the cost of insulators and hardware; 36% of the cost of conductors and 20% of the cost of 400/220 kv transformers. The rest of the substation equipment is assumed to contain no significant foreign components with the exception of the 50 MVar shunt reactors for which the estimated cif price has been considered as foreign cost. Inland freight and insurance is calculated at 4% of ex-works price plus excise duty (8% of ex-factory component) for local supply, and 4% of cif cost plus custom duty plus landing charges on imported equipment. Customs duties and landing charges for imported equipment have been assumed as 50% and 2% of the cif cost. Excise and sales tax is charged at 4% each on the ex-works cost. Erection is estimated at 8% of the electrical equipment cost Physical contingencies of 10% on construction costs and 5% on the equipment costs have been allowed to provide for unforseen factors. In assessing price contingencies, it has been assumed that contracts will either be on a fixed price basis or with ceiling on price inflation as was the case in the past with some of NTPC's contracts. Costs for equipment and erection have been escalated at 8.5% for FY1983, 8% for FY1984, 7.5% for FY1985, 7% for FY1986 and 6% yearly after FY1986 to allow for estimated price increases. Project Financing 3.08 The proposed loan of US$250.7 million, representing about 50% of the project cost (excluding duties and taxes and interest during construction and including the capitalized front-end fee), would be applied to the cif and/or ex-factory prices of equipment and materials, and to the cost of consultants' services. The credit would cover all the foreign exchange costs and about 18% of the local costs. GOI would provide the balance of the funds required in the form of loan and equity share capital. Engineering 3.09 The 400 kv transmission system, being implemented by NTPC under their thermal power projects and by the SEBs under the power transmission projects, has been based on the recommendation of CEA, and has been included in the Long Term Power Plan as part of the least-cost transmission component of that plan. CEA had employed under the Fourth Power Transmission Project (Credit 604-IN) consultants (Teshmont of Canada) for system planning. Their recommendations in 1977 have been continuously updated by CEA based on in-house studies to reflect changing system conditions. The major elements of the 400 kv transmission design and construction have been standardized for all India and form the basis for detailed design of the lines NTPC has also carried out comprehensive engineering studies on over-voltage and stability problems to establish equipment parameters for the systems implemented by them. As the digital model used in the studies is

24 -18- limited in the representation of various non-linearities, over-voltage studies are being taken up through the transient network analyzer technique also. These studies are being financed under the Second Korba Thermal Power Project (Credit 1172-IN) The proposed project consists of inter-regional links using both HVDC and 400 kv AC, as well as 400 kv AC intra-regional links. These have been established by CEA on the basis of system studies aiming at evolving a power transmission system based on requirements to the end of the decade. CEA, with the assistance of consultants, is extending these studies to The broad scope of these studies (not part of the project) includes: - expansion of the 400 kv system with an overlay of higher AC voltage (e.g. 765 kv); - introduction of HVDC transmission of suitable voltage; - staging of system development for the intermediate period; and - economic evaluation and optimization of various alternatives As part of the proposed project, NITPC will undertake, with the assistance of consultants, detailed equipment and system engineering and supervision during construction for the back-to-back HVDC link at Vindhyachal. These technical services would require an input of about 190 man-months of consultancy at an average rate of about US$13,000 per man-month including salary, fees, international travel and subsistence. Construction and Procurement 3.13 The Project involves construction of 400 kv transmission lines and erection of substations and high voltage D.C. terminal equipment for the back-to-back link. NTPC has been constructing through contractors 400 kv lines and substations effectively over the last few years under each of its thermal power projects financed by the Bank Group. The same arrangement for construction of the lines and substations is proposed to be followed for this project too. W4hile NTPC would procure through international competitive bidding the conductors, line material such as insulators and hardware and the electrical equipment including metering and instrumentation, for a total amount of about US$145 million, separate contracts for supply and erection of towers, stringing of conductors, design of structures, civil works and commissioning of lines and substations, totalling about US$140 million, would be entrusted to contractors based on local competitive bidding. The high voltage DC back-to-back link, estimated at about US$118.5 million is a technology being introduced for the first time in the Indian power sector and therefore, the contract for the supply of equipment, would include adequate provision for supervision of erection and commissioning. The engineering of the link would be handled by competent consultants (see para. 3.12).

25 The project construction implementation schedule is shown in Annex 15. Project completion is expected by March Procurement of equipment and materials in an amount of about US$240 million to be financed from the proposed credit would be on the basis of international competitive bidding in accordance with the Association's guidelines. Documents for individual contracts above US$2,500,000 equivalent would be subject to prior review by the Association. Bidding documents for such equipment, and tender analyses and recommendations for award of contracts, would be prepared by NTPC, where necessary with the assistance of its consultants, and approved by the Bank Group. The contracts could include civil works in certain cases where these cannot be disassociated from the equipment contract, as for instance, the substation structure. Local manufacturers would be expected to bid for almost all categories of equipment and materials. A domestic preference of 15% or the import duty, whichever is less, would be applied in bid comparison for equipment and material contracts. To prevent administrative procurement delays, in cases where the lowest evaluated bidder is a foreign manufacturer, GOI agreed during negotiations to promptly grant import permission for such items. Disbursement 3.16 Disbursements from the proposed credit would be made against 100% of the cost of consultants retained for the equipment and system engineering and supervision during construction for the HVDC back-to-back substation at Vindhyachal (para. 3.12) and against the cost of equipment and materials to be financed from the proposed credit, on the following basis: (a) 100% of the ex-factory cost of equipment and materials procured in India subject to international competitive bidding; and (b) 100% of the foreign cost of equipment and materials procured abroad. Estimated disbursements as provided in Annex 16, have been determined by NTPd and relate to the project implementation schedule (Annex 15). Although the period of disbursements (5-1/2 years) corresponds to that of the Bank disbursements profile, the proportionate disbursements by semester differ somewhat to reflect NTPC's experience in implementation of transmission components of other projects for which their disbursement estimates have proven reasonably accurate. Ecology 3.17 No ecological problems are expected. Conductor sizes and spacing will be designed to keep energy losses and radio interference within acceptable limits. Since one 400 kv circuit is equivalent to approximately

26 -20- three and a half 220 kv circuits, the amount of right of way is greatly reduced and the appearance improved. The substations will be provided with a fire fighting system which will conform to fire insurance regulations of India and will be equipped with both AC and Diesel-driven pumps. An automatic heat-actuated emulsifying system is proposed for transformers. Project Risks 3.18 The principal risk is the possibility of slippage which could give rise to delayed commissioning of the power transmission facilities. Such possible slippage would normally have no negative impact on the continuity of electricity supply, but would result in delay of the economic benefits of system interconnection. To ensure effective coordination of the different activities during project implementation, NTPC will use PERT charts, which not only schedule the various physical activities but also indicate the phasing and quantum of inputs such as financial resources, manpower of different types, scarce materials, etc. In view of NTPC's previous experience with transmission construction, it is expected that the risk of slippage will be kept to a minimum through careful coordination and supervision during construction, careful attention when placing contracts, and to the capability of manufacturers to meet the delivery schedule Other risk areas are in engineering design, equipment quality and cost overruns. These risks have been carefully assessed and the following safeguards taken: (a) NTPC will be assisted by consultants in those areas where it has not sufficient experience, which should minimize problems due to error at the engineering and design stages; and (b) project costs are based on similar works currently in progress in India; provision has been made for cost escalation and there should be little risk of any substantial cost overrun There is also risk of damage due to fire, explosion, etc, which is covered by insurance provided by the respective contractors during the construction stage and by GOI through its self-insurance policy after commissioning.

27 -21- IV, FINANCIAL ANALYSIS A. NATIONAUL THEWMAL POWER CORPORATIGN LIMITED (NTPC) Investment Program 4.01 NTPC is currently in the seventh year of an investment program which originally provided for the constrtuction of four large thermal power stations with an aggregsate capacity of 7,300 P. together with about 6,000 circuit kilometers of associated 400 kv transmission lines, estimated to cost about Rs 4l1,i00 million (US84,767 million), However, because of rescheduling and expansio;,i of the construction program, the investment program has been subjeet ro conitinuous review over the past six years, with appropriate revisions being made during appraisal of the previous projects. Revisions were made during appraisal of the proposed project to reflect (i) increase in the expected base costs of equipment; (ii) increase in price contingency factors attributable to higher projected inflation rates; (iii) rescheduling of generating plant commissioning dates; (iv) provision for projects not yet identified (3,000 MW), extending the investment program from FY1991 to FY1996; and (v) inclusion of the proposed project NTPC's currently revised investment program is set out in Annexes 18 and 19 and indicates capital expenditure of Rs 159,162 million (US$16,754 aill-on) over the twenty-year period FY 1977 to FY 1996, reflecting an increase of 138% (Rs 92,295 million, US$9,715 million) over the investment program as previous"ly revised during the Second Ramagundam appraisal (FY 1977 to FY 1991). The increase in generating capacity and transmission facilities accounts for about Rs 79,500 million (US$8,370 million) or 86% of the cost increase. The remaining 14% of the increase in the investment program is due to increased costs for station and transmission facilities at Singrauli, Korba, Ramagundam and Farakka (Annex 19), largely attributable to (a) price escalation resulting from slippage in commissioning of power units, (b) revision of construction and main plant equipment base costs to 1982 prices, (c) increase in foreign costs in terms of local currency resulting from changes in the exchange rate applied, and (d) increase in price contingencies resulting from application of revised inflation factors. Financial statements showing both past performance and future forecasts of NTPC's consolidated operations are provided in Annexes 21 through 23. Assumptions upon which the forecasts are based are provided in Annex 24. Future Earnings 4.03 NTPC commenced commercial operations in February 1982 when its first 200 MW generating unit at Singrauli was commissioned. The growth of power generation and unit sales resulting from plant commissioning (Annex 17), and the subsequent stabilization of generation, for the ensuing thirteen- year period to FY 1995, is set forth in Annex 20. NTPC's projected earnings are based on the assumption that NTPC will supply bulk power at 400 kv to State Electricity Boards at regional tariff levels sufficient to enable it to earn

28 -22- a 9.5% return on the historic value 1/ of average net fixed assets in operation from FY199l when NTPC's sales volume is estimated to reach about 83% of the maximum output of the four power projects Singrauli, Korba, Ramagundam and Farakka. Between FYs1984 and FY1990 NTPC should achieve a minimum rate of return of 8%. This return is heavily influenced by the point in time within any given year of commissioning of assets and the assumption of stabilization periods of generation plant. Consequently, during FY the revenues, investment costs and operating expenditures should be adjusted to reflect the hypothetical situation of fully operative and stabilized generation plant (for detailed explanation see Annex 21). During negotiations an assurance was obtained that NTPC will achieve in FY17917,and maintain thereafter, a rate of return of not less than 9.5% on the net average fixed assets in operation. Between FYs1984 and 1990 a minimum rate of return of 8% per year will be achieved using the adjusted assets, operating expenditures and revenues as explained above. NTPC Consolidated Operations 4.04 The Income Statement set out in Annex 21 shows the projected consolidated operating results of NTPC from FY1983 through FY1995. The forecast earnings performance of NTPC is satisfactory. On the basis of the projections the average bulk supply price in FY1991 will be 43.9 paise (USc4.6) per kwh which represents an increase of 12.1 paise over the 31.8 paise per kwh projected during the Second Ramagundam appraisal. The increase of 12.1 paise is comprised of: (a) Base fuel costs 2.8 paise per kwh (b) Operations and Maintenance costs 1.1 paise per kwh (c) Depreciation (d) Return at 9.5% on average net fixed assets in operation Total 2.0 paise per kwh 6.2 paise per kwh 12.1 paise per kwh - of which 1.6 paise per kwh is attributable to the proposed transmission project which is not directly revenue producing. 1/ Fixed assets are recorded at historical cost as the Government does not permit NTPC to revalue to current price levels.

29 -23- For the years FY1983 to FY1991 regional bulk supply tariffs have been projected to progressively increase from 32.2 paise per kwh in FY1983 to the 43.9 paise per kwh (excluding fuel surcharge) required to achieve the covenanted rate of return of 9.5% in FY 1991 (para. 4.03) NTPC will become profitable in FY1983 and, as a consequence of the rapid commissioning of plant from FY 1984, earnings will rise rapidly thereafter. The rate of return will continue to increase to 12.3% in FY1994 when all generating units in each of the stations will be operating at full capacity. NTPC Regional Operations 4.06 Regional income statements for the Northern, Western, Southern and Eastern Regions set out in Annexes 25 to 28 showing the projected operating results for each region from FY1983-FY1995 are satisfactory. All four Regions are projected to achieve a 9.5% rate of return in FY1991, the qualifying year (para. 4.03) for NTPC consolidated operations. Minor losses occur in FYs1984, 1985 and 1989 for the Southern Region, and in FYs1985 and 1986 for the Eastern Region, which are acceptable at that stage in NTPC's development program. Power sales from the generating stations in each region will be priced at a uniform regional bulk supply tariff (para. 4.17). Operating costs of the transmission facilities provided by the proposed project will be recovered through the regional tariffs. Taxation 4.07 NTPC is liable for income tax under the Income Tax Acts. However, because of the large capital expenditure program between FY 1979 and FY 1995, an income tax liability will not arise in the foreseeable future. Accordingly, a tax equalization reserve is not necessary. Internal Cash Generation FY FY A Statement of Sources and Applications of Funds covering NTPC's K current investment program is provided in Annex 22. Internally generated funds are expected to contribute 12% to NTPC's investment program between FY1983 and FY1992 (Table 4.1), the year in which the last of the Bank Group financed power units (Farakka) will be commissioned. Internal cash generation rises rapidly from FY1989 and is projected to provide 100% of the investment funds required by the investment program from FY 1993 to FY 1995 (Rs 11,924 million, US$1,255 million). This latter three year period of the investment program covers only the provision for projects not yet identified as all defined and approved projects are projected as completed by FY Dividends on equity share capital are not included in the forecasts on the assumption that surplus funds would be applied to the expansion of NTPC's activities beyond its current investment program. From the Eirst year of

30 -24- operations onward, debt service coverage is satisfactory at 1.3 times and above. NTPC's Financing Plan FY FY The financing plan for the ten year period FY is set out in Table 4.1 and is satisfactory. The investment cost of the proposed project represents about 4% of the construction expenditures in the financing plan In addition to the proposed project and a provision for projects not yet identified, two new projects (Rihand and Vindhyachal) have been added to the investment program and financing plan since approval of the Second Ramagundam project. The Rihand project (2 units of 500 MW) is being implemented by a consortium of British companies led by Northern Engineering Industries Limited and is being financed by the U.K. Government. The loan of p344 million bears interest of 7.75% per annum with principal repayable in semi-annual installments over ten years, excluding a five-year grace period. Equipment and materials, supplied by the U.S.S.R., for the Vindhyachal project (six units of 210 MW and associated transmission facilities) are being financed by a credit of about U.S.S.R. roubles 317 million from the U.S.S.R. Government. The credit bears interest at 2-1/2% per annum with principal repayable in equal annual installments within a period of 17 years and with the first installment being payable in the third year after the first drawing from the credit. Interest and principal payments will be made in Indian currency Bank financing of the proposed project, US$250.7 million, together with Bank Group financing of NTPC's investment program to date, in total US$2,101 million, represents about 17% of the total investment involved (excluding the provision for projects not yet identified).

31 -25- Table 4.1 NTPC's FINANCING PLAN FY 1983-FY 1992 US$ Million Rs Million Equivalent % Source of Funds. Internal Cash Generation 57,511 6, Less: Debt Service (37,533) (3,951) (28) Working Capital Increase (2,950) (310) 2) Contribution to Investment 17,028 1, Capital Raised GOI Equity Capital 56,145 5, GOI Loans 1/ 63,933 6, Total Sources 137,106 14, Requirements: Construction Program (including interest during construction) 137,106 14, Onlending Agreement 4.12 The Bank Loan for the proposed project will be onlent to NTPC by GOI in accordance with an acceptable onlending agreement as a condition of effectiveness of the Credit. As in previous lending operations, the terms of the onlending agreement would provide for maturity in 20 years, including a grace period of 5 years, and repayment of principal in equal semi-annual installments, with interest payable on outstanding balances at not less than 12% per annum, except as the Bank may otherwise agree. The rate of interest at which GOI currently lends to industrial and commercial undertakings in the power sector is 12.5% per annum and reflects an increase from the rate of 11.75% in effect at the time of the Second Ramagundam appraisal. The foreign exchange risk would be borne by the Government. An, assurance was obtained during negotiations that GOI will ensure prompt availability to NTPC of 1/ Includes onlending of IDA Credits/IBRD loans and KfW, OPEC, U.K. and U.S.S.R. loans.

32 -26- sufficient funds to complete the project, including any additional funds which might be required due to cost overruns or other unforeseeable factors. Future Finances 4.13 Actual and forecast balance sheets, at March 31 annually from FY1977 through FY1995, are set out in Annex 23 and reflect a satisfactory financial position for each of these years. The balance sheets reflect the phased construction program, the commencement of commercial operations in FY1983, and the financing of NTPC's capital requirements by GOI through a combination of long-term borrowing and equity capital, in a ratio which would normally not exceed 1:1. Initially the equity portion of financing would be released by GOI followed by loan capital. Table 4.2 summarizes NTPC's financial position at three significant points in its development. (a) at March 31, revenue earning; end of the year in which NTPC will become (b) at March 31, end of the year following the year in which the proposed project is completed; and (c) at March 31, end of the first year in which all of generating units of the approved projects in the investment program are operating at full capacity These forecasts indicate that by March 31, 1983, when NTPC becomes revenue earning, total capitalization will be Rs 17,005 million (US$1,790 million), divided between GOI loans (including the onlending of Bank Group finance) and equity capital in a ratio of 30/70. Six years later (March 31, 1989), after the proposed project is completed, total capitalization will have risen to Rs 113,973 million (US$11,997 million) reflecting a debt/equity ratio of 48/52. No external debt or equity financing is forecast after FY1992 for the current investment program and this, combined with a significant increase in internal cash generation, will reduce the debt/equity ratio to 33/67 by March 31, 1994.

33 -27- Table 4.2: FINANCIAL POSITION OF NTPC. At March 31 FY 1983 FY 1989 FY 1994 (Rs Millions) Fixed Assets at Cost 6,313 90, ,248 Less: Depreciation 58 5,210 21,604 Net Fixed Assets in Service 6,255 84, ,644 Work-in-Progress 11,075 27,612 19,208 Total Net Fixed Assets 17, , ,852 Short Term Deposits - - 3,864 Working Capital (325) 1,481 2,635 Total Net Assets 17, , ,351 Financed by: Equity Capital 11,775 53,681 63,995 Retained Earnings 45 5,119 31,176 Total Equity 11,820 58,800 95,171 Long-Term Debt (including IDA Credits/IBRD Loans) 5,185 55,173 46,180 Total Capitalization 17, , ,351 Debt/Eqdity Ratio 30/70 48/52 33/67 Borrowing Powers 4.15 The Companies Act 1956 (Section 293.1d) limits borrowing by NTPC to an amount equal to the aggregate of the paid up share capital and "free reserves (i.e. those which are not set apart for specific purposes), except with the consent of the Corporation in general meeting. During negotiations, an assurance was obtained that NTPC will inform the Bank Group beforehand of any proposal to alter or modify existing limitations on the borrowing powers of its Board of Directors. Commercial Arrangements for Sale of NTPC Energy 4.16 Under previous credits and loans GOI and NTPC agreed to prepare bulk supply contracts for the sale of energy to the SEBs on terms and conditions satisfactory to the Bank Group. They also agreed to forward a final draft of the contracts for the Singrauli, Korba, Ramagundam and Farakka power stations six months prior to the first sale of energy from each respective power station. Preliminary draft contracts have been provided to the Bank Group for Singrauli and Korba which in principle are acceptable,however final drafts for Singrauli and Korba which were due by August 1981 and July 1982 respectively have not yet been provided. The reason for this delay is that NTPC has not yet been able to reach agreement on the financial terms of sale with the relevant SEBs. In the interim NTPC has been selling power from the Singrauli station at the inter-state rate of 35 paise per kwh with agreement

34 -28- that such sales would be retroactively adjusted to the bulk sale contract price when final agreement has been reached. Consequently GOI and NTPC agreed during negotiations that bulk supply contracts for the sale of electricity from the Singrauli and Korba power plants must be finalized and signed by all concerned parties as a condition of effectiveness for the proposed project. It was clarified during negotiations that inter-regional sales of power would be priced at the tariff rate of the receiving Region for committed power allocation. WThere sales are in excess of the committed power allocation, the tariff rate of the generating Region would apply NTPC bulk supply contracts will establish regional tariffs which will be applied to power sales in each respective region. Operating costs applicable to the transmission facilities of-the proposed project are absorbed by the relevant regional NTPC organizations. Recovery of such costs, therefore, is reflected in the projected regional tariffs as a separate component of these tariffs. The regional income statements set out in Annexes 25 to 28 show the projected regional tariffs, in current rupees, from FY1983 to FY1995. The regional tariffs projected for FY1991, the qualifying year for NTPC to achieve the 9.5% rate of return, are as follows: Paise/kWh (as of FY1991) Northern Region - Singrauli ) - Rihand ) 38.3 Western Region - Korba ) - Vindhyachal ) 43.4 Southern Region - Ramagundam 53.1 Eastern Region - Farakka 46.0 NTPC Consolidated Average Tariff 43.9 Variations in the above tariffs reflect regional differences in capital investment, coal costs, investment timing and level of energy generation in FY1991. B. _NDHRA PRADESH STATE ELECTRICITY BOARD (APSEB) 4.18 APSEB will be the major beneficiary of the proposed project as the substations and 400 kv transmission lines at Ramagundam, Vijayawada and Nellore will be located in the State of Andhra Pradesh. Consequently a significant proportion of the power carried by these facilities will be consumed in this State APSEB uses full commercial accounting for project and operational activities. Although internal reporting conforms to the commercial basis,

35 -29- the annual audited statements of account do not as they are published in accordance with the present requirements of the Electricity (Supply) Act Amendments to the Act, anticipated to be incorporated in early 1983, will permit the presentation of audited accounts on a commercial basis. Investment Program 4.20 The investment program for the seven year period FY1983 to FY1989 envisages capital expenditure of Rs 21,433 million (US$2,256) and will provide additional installed capacity of 1,760 MW (1,340 MW hydro and 420 MW thermal) or 81% over the present level. Power generation is projected to increase by 7,554 GWh (90%) by FY1989 due to the added capacity and higher efficiency of new plant. Future Earnings 4.21 The Income Statement set out in Annex 29 shows the actual and projected operating results from FY1980 through FY1989, adjusted for inflation. The forecast earnings performance of APSEB is satisfactory, reflecting a rate of return ranging between 9.5% and 12.3% between FY1983 and FY1989. No State Government subsidies, covering rural electrification losses, are projected for this period as APSEB will be able to achieve a satisfactory cash generation without such State subsidization. The average APSEB tariff is projected to increase from 42.4 paise per kwh in FY1982 to 55.5 paise per kwh in FY1989. Internal Cash Generation 4.22 A statement of internal cash generation is provided in Annex 30 showing actual and forecast cash generation for the period FY1980 through FY1989. Net cash generation, as a percentage of three-year average of capital expenditure, ranges between 30.8% and 45.4% for the forecast period FY1983 through FY1989 thus satisfying the covenant established under the Third Rural Electrification Project which requires a minimum 20% contribution to investment.

36 -30- V. JUSTIFICATION AND ECONOMIC ANALYSIS General 5.01 The proposed project, consisting of (i) a 400 kv network expansion within the Southern Region, (ii) a 400 kv transmission line linking the Southern and Western Regions, and (iii) an HVDC back-to-back link between NTPC stations in the Northern and Western Regions, is justified as part of the least-cost transmission component of the recently completed long-term generation capacity expansion plan for the Indian power sector. It provides needed additional transmission within the Southern Region, and establishes the initial high-voltage inter-regional links that will be the first step towards an integration of the national grid. Method of Analysis 5.02 In September 1982, CEA completed a 15-year least-cost generation expansion plan, which is reviewed in Annex 5. Having determined the optimum plant program for the forecast demand in each Region, the plan develops an optimum transmission grid configuration for that Region. This two-step approach is reasonable in India where selection of plant sites (hydro, pithead coal-fired) is fairly limited, and network costs do not influence the optimal plant mix. This intra-regional optimization results in a 400 kv grid configuration which encompasses, inter alia, the lines proposed under the project. As the intra-regional lines are justified by 1995 as part of the least-cost program, the analysis centers on the rate of return of the transmission lines, and the appropriateness of the timing of the investment. This is done by comparing the costs of the transmission facilities with the cost incurred in case of an outage The two inter-regional transmission links are examined in comparison to the investment that would be necessary to provide peaking capacity in either Region in the absence of the project. The method compares the present values of the transmission links and those of expansions of thermal capacity by amounts equivalent to the capacity made available by inter-regional transmission. In addition, energy cost savings arising from transfers of energy between Regions with different generating costs are identified All costs are expressed in CIF (border price) terms or their equivalents. For local cost components, a standard conversion factor of 0.8 is used. Unskilled labor is valued at 75% of its market wage. Intra-Regional Lines 5.05 The transmission options related to the least-cost generation expansion plan are outlined for the year 1995 in Annex 32. In the long run, the transmission grid development in the Southern Region is straightforward, as capacity expansion takes place relatively more in the North, whereas load growth is higher in the South.

37 The load flow studies performed by the CEA examine various conditions for the year 1989, the anticipated year of completion: - maximum load, maximum thermal despatch - maximum load, maximum hydro dispatch - maximum load, normal dispatch, etc. The variation in hydropower affects mostly the 220 kv network, and increases only marginally the North to South power flow on the 400 kv network. By far the most constraining condition consists in sending out the maximum output from the Ramagundam thermal plant operating as base load. In this condition, the proposed network would withstand single outages on the inland lines not covered by the project, but this would be no longer true when one of the following project components is delayed: Section Shortage (MW) (a) Ramagundam-Mangur 100 to 400 (b) Mangur-Vijayawada 100 to 400 (c) Vijayawada-Nellore 50 to 200 (d) Nellore-Redhills 0 to The shortages are in round figures; they vary according to which one of the seven inland lines is tripped along the alternative route from Ramagundam to Redhills. They disappear during the wet quarter when the 500 MW units are maintained and also another quarter on sections (c) and (d) when 200 MW units are maintained. They are reduced by 20% at all times due to forced outages. The distribution of avoided shortages over the year is taken as follows: Section 6 Months 3 Months 3 Months (a) 80 to 320 MW 0 to (b) 80 to 320 MW 0 to (c) 40 to 160 MW 0 0 (d) 0 to 120 MW Assuming a 5% outage rate for each of the seven inland lines, the probability of having an outage is 35%, i.e. 4.5 weeks per quarter. Further assuming a 90% availability for line sections (c) and (d), and 97.5% availability for sections (a) and (b), the total shortages avoided in 1989 amount to 208 GWh on all four sections The cost of outages avoided as proxy for benefits is estimated as the economic costs incurred by consumers by the use of alternative energy during periods of power cuts. For the major consumer categories, this amounts to the following values:

38 -32- Regional share of total Consumer category Value (Rs/kWh) consumption (%) Industrial and similar Agriculture Domestic/Commercial Weighted average The economic internal rate of return of the intra-regional transmission links is about 13% (Annex 33). The rate of return is not significantly sensitive to reasonable variations in costs and benefits. The appropriateness of timing of the transmission links within the Region can be gauged by comparing the annuitized cost of the links per kwh of outage avoided (about Rsl.10/kWh) with the estimated cost of outage in 1989 (Rs 1.77/kWh). The differential indicates that the lines are justified in or before Southern/Western Region Intertie 5.11 The AC link between the two Regions consists of a double circuit line between Ramagundam and Chandrapur. The 1,000 MW capacity of this link results, after netting out losses and taking into account availability, in about 950 MW available capacity for the receiving Region. According to CEA calculations, an increase of that magnitude in the peak demand would augment the Loss of Load Probability (LOLP) from the target of 1% to 1.8%, so that this support would be available at least 98.2% of the time. Netting out 2% of power losses, this link provides then a peaking capacity of 912 MW. This capacity, in the absence of the link, would have to be provided by 2x5Q0 MW additional capacity in the receiving Region. Under the circumstances prevailing in India, this capacity would be coal-fired thermal The economic cost streams of the transmission link and the alternative solution of an increase in generating capacity are shown in Annex 33. At any discount rate within a reasonable range, the transmission link solution is the lower-cost option by a wide margin (Annex 34) In addition to the justification as least-cost solution, the existence of the transmission link will make possible energy transfers from the Western to the Southern Region during off-peak periods. The estimated marginal off-peak energy cost differentials in 1980 (in 1982 prices) are expected to be about 3.7 paise/kwh during the wet (monsoon) quarter, and about 6.7 paise/kwh during the dry season. Assuming an all-year weighted average differential of about 5 paise/kwh, a feasible transfer period of about 6,000 hours per year would result in an annual marginal energy cost saving of about Rs300/kW, or about Rs273 million per year for the available 912 MW at the receiving end. By 1995, the wet season cost differential would

39 -33- be negligible, but dry season transfers at a cost differential of about 2.8 paise/kwh would still be feasible. Northern/Western Region HVDC Intertie 5.14 This link consists of a 400 kv line between Vindhyachal and Korba, a new AC 400 kv substation and a HVDC back-to-back link at Vindhyachal, and an expansion of the AC 400 kv substation at Korba. After taking into account availability and losses, 466 MW of additional capacity could be made available in the receiving Region. In the absence of the link, this would be provided by a 500 MW thermal unit, most likely by expansion in one of the pithead coal-fired stations The economic cost streams of the DC link (including the full AC part of the link), and of the alternative solution of thermal capacity expansion are shown in Annex 35. At any discount rate within a reasonable range, the DC transmission link solution is the lowest-cost option by a ratio of almost 2: As in the case of the Southern/Western link, the interconnection will also make off-peak energy transfers possible. In 1989 and the following early years, the flow would be from the Western to the Northern Region because of off-peak marginal energy cost differentials of 6.5 paise/kwh (wet) and 3.2 paise/kwh (dry). In 1995, off-peak marginal energy costs during the dry period are approximately equal in both Regions, but wet season energy would flow from the North to the West because of a cost differential of about 5.1/kWh resulting from accelerated hydro development in the North. Assuming again initially 6,000 transfer hours per year, the annual marginal energy cost saving would amount to about RslOO million, decreasing by 1995 to about Rs7O million per year if only wet season transfers were made. Tariffs and Cost of Supply 5.17 The main single beneficiary SEB under the project is the Andhra Pradesh State Electricity Board. In recent years, average tariffs of APSEB have been rising at a rate of about 11% per year to a FY82 level of 42.4 paise/kwh (USc4.5), and industrial tariffs at a rate of about 20% p.a. Domestic and agricultural tariff development has been less encouraging as these tariffs have actually decreased in real terms. Present tariffs are summarized in Annex In 1975, the Bank, in collaboration with APSEB, prepared a marginal cost-based tariff study (Report No. 851-IN). Subsequently, several updating exercises have been performed by the Bank as well as APSEB (Annex 37). At present, APSEB staff is preparing a detailed recalculation of the 1975 study, which is expected to be completed early in In general, average tariffs in FY82 were slightly below or roughly equivalent to Average Incremental Cost

40 -34- (AIC) estimatesl/ (40-50 paise/kwh), a situation which is unchanged from earlier years. More detailed marginal cost estimates, however, yield a significantly higher sales-weighted overall marginal cost (about 80 paise/kwh in FY82). This is due to the fact that APSEB's AIC is heavily influenced by a strong future emphasis on hydro development in the State, while, at the margin, non-apseb thermal generation will have to satisfy demand Cross-subsidization among consumer categories in relation to the marginal cost structure continues to be evident. Industrial consumers pay tariffs of about paise/kwh, while their marginal cost is more likely to be about 45 paise/kwh (at the same load factor). On the other hand, domestic consumers, whose marginal cost is about paise/kwh, pay a tariff of about paise/kwh. Agricultural consumers enjoy an even larger gap between cost of supply and tariff. This policy of cross-subsidization is APSEB and Andhra Pradesh Government policy, and is unlikely to be abandoned in the near future for social and political reasons. However, APSEB has been improving its tariff structure in line with principles highlighted in the 1975 Tariff Study, and plans to continue to do so. Improvements effected in recent years include (i) the replacement of decreasing block tariffs in the domestic category by an increasing system, (ii) the abolishing of the domestic bulk supply category, (iii) the introduction of customer charges, (iv) the introduction of a two-part tariff for HT consumers, (v) the enforcement of a power factor penalty clause in industry, and (vi) the addition of a fuel cost adjustment clause Further improvements to tariff structure and practice are necessary. The major changes would be: (i) Power factor regulations need to be enforced in the agricultural sector, where 100,000 of 500,000 irrigation pumps do not have capacitors, but have not been obliged to pay the power factor penalty. (ii) The ratio between demand and energy charges for customers with a two-part tariff is severely distorted. Marginal capacity cost is much higher than the demand charge, while energy charges exceed marginal energy cost. (iii) The fuel surcharge, while a welcome interim tool to reflect cost changes, may distort the above ratio even more in the long run, if it is carried on and increased instead of absorbed into the tariff at regular revisions. A check on its potential misuse as tariff adjustment substitute is called for. 1/ Depending on the valuation of large incremental purchases from outside the State during the later 1980's.

41 -35- (iv) The first ("lifeline") consumption block for domestic consumers needs to be reduced from the present 100 kwh/month to about 25 kwh to justify the subsidized block for minimum needs. At the same time, the price per unit above this block should be increased significantly. (v) The heterogeneous group of non-domestic LT consumers (hotels, offices, shops, etc.) should be split to reflect consumption patterns, while the two LT industrial categories could be combined. The cottage industry category could usefully be combined with the domestic category. (vi) Tariffs for irrigation consumers should rise in general after a long period of stagnation. The ceiling on LT agricultural consumers' demand charge should be removed. (vii) Street light tariffs for larger municipal corporations with ability to pay should be raised to reflect cost. (viii) Interstate exchange tariffs should be adjusted to reflect cost at the time of supply. APSEB is now discussing a marginal cost-based system with CEA and other SEBs The Chairman of APSEB reviewed the present status in regard to tariff restructuring and gave assurance that the above points are being taken into consideration in the continuing process of the restructuring of APSEB tariffs.

42 -36- Condition of Effectiveness VI. SUMMARY OF AGREEMENTS 6.01 (a) GOI and NTPC should provide copies of bulk supply contracts for the sale of electricity from the Singrauli and Korba power plants, finalized and signed by all concerned parties (para. 4.16). (b) The conclusion of a Subsidiary Loan Agreement between GOI and NTPC satisfactory to the Bank (para. 4.12). Clarifications and Agreements Reached During Negotiations 6.02 During negotiations clarifications were obtained with regard to tariff structure improvements to be implemented by APSEB (para. 5.21) The following issues were raised with GOI and NTPC and satisfactory agreements or assurances were obtained with regard to: Recommendation (a) audit (para. 2.18); (b) import permission (para. 3.15); (c) rate of return (para. 4.03); (d) provision of the balance of capital to complete the project, including any additional funds which might be required to cover cost overruns or other unforeseen factors (para. 4.12); (e) borrowing (para. 4.15); and (f) cost recovery and pricing of inter-regional sales of power (para. 4.16) Subject to the foregoing the project forms a suitable basis for a Bank Loan of US$250.7 million.

43 -37- ANNEX 1 INDIA CENTRAL POWER TRANSMISSION PROJECT Power Sector Loans & Credit' Project Loan No. Amount Remarks Bokaro-Konar Complete Damodar Complete Tata Andhra Valley Complete Tata Trombay Complete Third DVC Complete Koyna Complete Power Transmission Complete Kothagudem II Complete Trombay III Ramagundam Farakka Ramagundam II Rural Electrification III US$m Credit No. Fourth DVC Complete Koyna II Complete Kothagudem Complete Beas Equipment Complete Power Transmission II Complete Power Transmission III Complete Rural Electrification Complete Power Transmission IV Singrauli Korba Ramagundam Rural Electrification II Singrauli II Farakka Korba II ,096.0

44 -38- ANNEX 2 Page 1 of 5 pages INDIA CENTRAL POWER TRANSMISSION PROJECT Electricity (Supply) Act 1948 Proposed Amendments, October 1982 Existing Proposed S.59 (Addition/deletion/Modification) General principles for Board's Subsection (1) of Section 59 shall be finance - (1) The Board shall, substituted by the following:- after taking credit for any subvention from the State "The Board shall, after taking credit Government under section 63, for any subvention from the State carry on its operations under Government under section 63, carry this Act and adjust its tariffs on its operations under this Act and so as to ensure that the total adjust its tariffs so as to ensure revenues in any year of Account that the total revenues in any year shall, after meeting all of Account shall, after meeting all expenses properly chargeable expenses properly chargeable to to revenues, including revenues, including operating, operating, maintenance and maintenance and management expenses, management expenses, taxes (if taxes (if any) on income and profits, any) on income and profits, depreciation and interest payable on depreciation and interest all debentures, bonds and loans, payable on all debentures, leave such surplus which shall not bonds and loans, leave such be less than 3% of the net fixed surplus, as the State Govern- assets employed by the Board or such ment may, from time to time, higher percentage of such assets as specify. the State Government may, from time to time, specify." (2) In specifying the surplus under subsection (1), the State Government shall have due regard to the availability of amounts accrued by way of depreciation and the liability for loan amortization and leave:- (a) a reasonable sum to contribute towards the cost of capital works and

45 -39- ANNEX 2 Page 2 of 5 Existing Proposed (b) where in respect of the Board a notification has been issued under subsection (1) of section 12-A, a reasonable sum by way of return on the capital provided by the State Government under subsection (3) of that section and the amount of the loans (if any) converted by the State Government into capital under subsection (1) of Section 66-A. S.67 Priority of liabilities of Board - Section 67 to be substituted by the (1) If in any year, the revenue following:- receipts are not adequate to enable compliance with the requirements of "Priority of Liabilities of the Board Section 59, the Board shall after - The Board shall distribute the meeting its operating, maintenance surplus of the revenues in any year and management expenses after after meeting all the expenses provision has been made for the referred to in subsection (1) of payment of taxes (if any) on income Section 59, to the extent such and profits, distribute the revenue surplus is available and the receipts, as far as they are avail- amounts accrued by way of depreable, in the following order, namely:- ciation for the year, in the following order, namely:- (i) payment of interest on loans guaranteed under section 66; (i) repayment of principal of any loan raised (including redemp- (ii) repayment of principal of tion of debentures or bonds any loan raised (including issued) under section 65 which redemption of debentures of becomes due for payment in the bonds issued) under section 65 year or which became due for which becomes due for payment payment in any previous year in the year; and has remained unpaid; (iii) payment of interest on loans (ii) repayment of principal of any guaranteed under section 66; loan advanced to the Board by the State Govt. under section 64 (iv) payment of interest on sums which becomes due for payment paid by the State Government in the year or which became due in pursuance of guarantees for payment in any previous year under Section 66; and has remained unpaid; (v) payment of interest on loans and if any balance is left thereafter, advanced to the Board by the the same shall be utilized for other State Government under section purposes specified in subsection (2) 64 or deemed to be advanced of section 59 in such manner as the under subsection (2) of Board may decide. section 60;

46 -40- ANNEX 2 Page 3 of 5 Existing Proposed (vi) repayment of principal of any loan guaranteed by the State Government under section 66 which becomes due for repayment in the year or which became due for payment in any previous year and has remained unpaid; (vii) repayment of principal of any loan advanced to the Board under section 64 which becomes due for payment in the year or which became due for payment in any previous year and has remained unpaid: and if any balance amount is left thereafter, the same shall be utilized for the other purposes specified-in section 59 in such manner as the Board may decide. (2) If for any reason beyond the control of the Board, the revenue receipts in any year are not adequate to meet its operating, maintenance and management expenses, taxes (if any) on incomes and profits and the liabilgities referred to in clauses (i) and (ii) of subsection (1), the shortfall shall, with the previous sanction of the State Government, be paid out of its capital receipts. A new Section 67-A to be inserted as following:- "If for any reasons beyond the control of the Board revenues in any year are not adequate to meet all the expenses referred to in subsection (1) of section 59, the interest on loans advanced to the Board by the State Government under section 64 or deemed to be advanced under subsection (2) of Section 60 and charged to revenues in that year to the extent of the shortfall shall not become payable to the State Government until revenues earned in subsequent years are adequate also to meet such deferred liability of interest to the State Government."~

47 -41- ANNEX 2 Page 4 of 5 Existing Proposed S.68 Charging of depreciation by Board - Charging of depreciation by Board - (1) Subject to the provisions (1) The Board shall provide each of section 67, the Board shall year for depreciation such sum provide each year for depreciation calculated in accordance with such such sum calculated in accordance principles as the Central Government with such principles as the Central may after consultation with the Government may after consultation the Authority, by notification in with the Authority, by notification the Official Gazette lay down from in the Official Gazette lay down time to time. from time to time. (2) The provisions of this section (2) Where in any particular year shall apply to the changing of depreciation cannot be adjusted depreciation for the year in which against revenues, the same may be the Electricity (Supply) Amendment carried over to subsequent years. Act, 1978, comes into force. (3) The provisions of this section [In Section 68 of the Principal Act, shall apply to the changing of in subsection (1), the words depreciation for the year in which "subject to the provisions of the Electricity (Supply) Amendment Section 67" and subsection (2) Act, 1978, comes into force. shall be omitted. Subsection (3) of section 68 shall be renumbered as subsection (2)] S. 69 Account of Audit - (1) The Board In subsection (1) of section 69 of the shall cause proper accounts and Principal Act, for the words "as may other records in relation thereto be prescribed by the State Government to be kept, including a proper in consultation with the Comptroller system of internal check and and Auditor-General of India", the prepare an annual statement of words "as may be prescribed by the accounts including the profit and Central Government in consultation loss account and the balance sheet with the Comptroller and Auditor in such form as may be prescribed General of India and the State by the State Government in consult- Governments'!shall be substituted. ation with the Comptroller and Auditor-General of India. No change in subsection 69(2) to (5). (2) The accounts of the Board siall be audited by the Comptroller and Auditor-General of India or by such person as he may authorize in this behalf and any expenditure incurred by him in connection with such audit shall be payable by the Board to the Comptroller and Auditor-General of India.

48 -42- ANNEX 2 Page 5 of 5 Existing Proposed (3) The Comptroller and Auditor- General of India or any person authorized by him in connection with audit of the accounts of the Board shall have the same rights, privileges and authority in connection with such audit as the Comptroller and Auditor-General of India has in connection with the audit of Government accounts and in particular shall have the right to demand the production of books, accounts, connected vouchers and other documents and papers, and to inspect any of the officers of the Board. (4) The accounts of the Board as certified by the Comptroller and Auditor-General of Tndia or any other person authorized by him in this behalf together with the audit report thereon shall be forwarded to the Authority and to the State Government within six months of the close of the year to which the Accounts and audit report relate, and that Government may issue such instructions to the Board in respect thereof as deems fit and the Board shall comply with such instructions. (5) The State Government shall - (a) cause the accounts of the Board together with the audit report thereon forwarded to it under subsection (4) to be laid annually before the State Legislature; and (b) cause the account of the Board to be published in the prescribed manner and make available copies thereof on sale at a reasonalbe price.

49 INDIA CENTRAL POWER TRANSMISSION PROJECT Rates of Return ' of SEBs(FY FY 1982) (based on audited data, unless otherwise stated) _, FY 1979 FY 1980 F~~~~~~~~~~~~~~~~~~~~Y 1982 FY 1981 Fo ecast Keturn Return Return Return Return Return Return Return to SEB incl. to SEB Incl. to SEB incl. to SEB incl. State State State State Duties Duties Duties Duties Andhra Pradesh Bihar Gujarat Haryana Karnataka F 17.4F Kerala OF 17.3F MadhyaPradesh Maharashtra w Orissa Punjab Rajasthan F 6.4F Tamil Nadu Uttar Pradesh F 7.2F West Bengal F 10.7F 9.5F 10.8F F = Forecast Target rate of return in general is 9.5%. When this was established in 1964, it was also conceived that an average electricity duty equivalent to a return of 1.5% would be applied, making the total expected return 11%. Effective March 1978, GOI levied an additional excise tax of 2 paise/kwh on generation which is not included above. This would add an estimated 2-3 percentage points to the returns noted. Not eligible for assistance under Rural Electrification Credits 572-IN and 911-IN: U.P. subsidy for Bural electrification from FY 1980 agreed in principle but detailed computation still under discussion with State government.

50 INDIA CENTRAL POWER TRANSMISSION PROJECT All India Sales and Energy Data to (Provisional) Installed capacity (Excl. non utility Plant) (MW) Electricity Generated (GWh) Electricity sold (GWh) Electricity generated per Capita (kwh) Electricity consumed per Capita (kwh) utilities only Proportion of Sales (%) Agricultural & Irrigation Railway Traction Industry Commerce Domestic Other (Public lighting, water works and Misc. etc.) Annual growth of sales (%) Losses (as percentage of kwh sent out) Source: CEA

51 -45- ANNEX 5 Page 1 of 12 pages INDIA CENTRAL POWER TRANSMISSION PROJECT Long-Term System Expansion Plan Demand Forecast 1. The Plan is based on a new CEA exercise in demand forecasting, using different methods for different consumer categories. The industrial demand forecast is based on empirical relationships between electricity consumption growth and growth of value added in industry; irrigation pumping forecasts are dependent on the planned rate of new pump connections, the expected utilization rates, and the replacement rate of diesel pumps. Residential and commercial use is extrapolated from past relationship over time. Two growth scenarios, depending on assumptions about higher or lower growth rates of industrial value added, have been developed. The results of the unconstrained forecast, by Region, are summarized in Table 1.

52 -46- ANNEX 5 Page 2 of 12 pages Table 1: Projections of Electricity Requirement and Peak Demand on Utility Systems Region Scenario Electricity Requirements - GWh (at Power Station bus) Northern High Low Western High Low Southern High Low Eastern High Low North- Eastern High Low Peak Demands - MW Northern High Low Western High Low Southern High Low Eastern High Low North- Eastern High Low While, by 1989/90, the new CEA estimate is pitched about midway between all previous forecasts, it is on the high side by the year This is mostly due to the high sustained industrial growth assumptions in the high scenario. The average annual growth rates in All-India electricity consumption resulting from this exercise are high initially (reflecting the growth from present suppressed demand levels), tapering off to about 7-8% p. a. by 1995 (Table 2).

53 -47- ANNEX 5 Page 3 of 12 pages Table 2: Projected Trends in Growth of Electricity Consumption (percentage per annum) High Low Scenario Scenario to to to to The pattern of electricity consumption in various consumer categories is expected to undergo some change. The consumption in the agricultural sector would gradually decline to about 13% from the present 18% by the end of the century due to saturation of demand for agricultural pumping. There would also be a slight decline in the share of industrial consumption, and an increase in consumption in residential, commercial and other categories. 4. Assumptions concerning the transformation of consumption forecasts into energy generation and peak capacity requirements are (i) a reduction in system losses in the two major Regions from more than 20% to 15-17%, and (ii) a decline in system load factor as restrictions on supply are relaxed gradually. For purposes of system expansion planning, CEA is using the high consumption forecast scenario. While this scenario may be somewhat too optimistic in the later years (high sustained industrial growth, little emphasis on industrial energy conservation), its effect on generating requirements, and, consequently, capacity expansion, may be compensated by a likely failure to bring down system losses rapidly. The use of the high scenario as basis for the least-cost expansion plan is therefore the most reasonable choice at this stage. Least-Cost Capacity Expansion Plan 5. The model (WASP, version III) uses the committed generating projects (under construction or sanctioned by CEA for construction) as fixed input, and a list of new hydro and thermal projects with their associated capital and recurrent costs as variable element, in determining the least-cost expansion sequence necessary to meet forecast demand. For each of the five Electricity Supply Regions, separate system optimizations were undertaken. Each optimization was subjected to sensitivity tests with respect to: (i) constraints on the optimum hydro plant development because of possible delays; (ii) the siting of coal-fired plants at pitheads or close to load centers; (iii) the forced outage rate (FOR) of thermal plants; and

54 -48- ANNEX 5 Page 4 of 12 pages (iv) the discount rate. 6. The main variations affecting the expansion program are those of hydro construction and forced outage rates. The results show that the "high hydro" option is usually cheapest (although not always significantly), and that concentration of thermal power at pitheads would reduce the overall costs considerably. High forced outage rates increase the cost significantly. Table 3 summarizes the expansion scenarios for each major Region, subject to a maximum desirable loss of load probability of 1%, together with the least-cost transmission options for each generation option. 7. In general, the high hydro/low FOR option turns out to be the least-cost expansion solution for all Regions. This option is examined with respect to expected future fund constraints in the ongoing Sixth and forthcoming Seventh Plans. If no additional funds can be mobilized in these two Plans, some capacity additions have to be postponed to the Eighth Plan, resulting in higher LOLP and lower peak reserve margins. Table 4 illustrates the effect on reserve margins of a delay in capacity expansion. Table 5 summarizes the final CEA judgement on desirable expansion programs in each Region, taking into account fund constraints, qualitative features, and possible difficulties in bringing down FOR. The program aims at reaching LOLP of about 1% by the early 1990s.

55 -49- ANNEX 5 Table 3 Page 5 of 12 pages Table 3: Regional Generation Expansion Options, High Hydro Low Hydro High Hydro Low Hydro Dispersed Gen. Dispersed Gen. Dispersed Gen. Dispersed Gen. High FOR High FOR Low FOR Low FOR High Hydro Low Hydro Low Hydro High Hydro lhigh FOR Low FOR High FOR Low FOR Northern Region Additions (MW) ,873 3,873 3,873 3,873 3,873 3, ,581 10,390 7,469 7,469 10,601 7, ,108 11,542 10,170 10,897 10,028 10,388 Total 24,562 25,724 22,012 22,239 24,502 22,099 LOLP (Z) Energy not served (GUh) Present value (Rs 10 Generation only Gen. plus least-cost transm Western Region Additions (MW) ,712 4,712 4,712 4,712 4,712 4,712 4,712 4, ,394 9,054 6,499 6,844 9,894 7,604 8,654 6, ,645 9,185 8,293 9,455 9,085 9,275 11,375 7,263 Total 22,751 22,951 19,504 21,011 23,691 21,591 24,741 18,974 LOLP (M) Energy not served (GDh) Present value (Rs 10 Generation only Gen. plus least-cost transm Southern Region Additions (MW) ,896 2,896 2,896 2, ,942 4,892 4,942 4, ,516 6,826 5,293 5,381 Total 14,354 14,614 13,131 13,169 LOLP (X) Energy not served (DSJh) Present value (Rs 10 ) Generation only Den. plus least-cost transm Eastern Region Additions (MW) ,606 2,606 2,606 2, ,903 5,113 4,063 4, ,032 6,841 4,913 5,221 Total 12,541 14,200 11,582 11,890 LOLP (X) Energy not served (GPh) Present value (Rs 10 Generation only Gen. plus least-cost transm

56 -50- ANNEX 5 Table 4 Page 6 of 12 Table 4: Gross Reserve Margins (With and without Funds Constraints in VI Plan) (All India) -- Installed Cap. (MW) --- After shift- Peak As per WASP ing benefits Reduc- Demand --- % Reserve Margin ---- Studies Due to funds tion in in High As per As per High Hydro/ Constraints Benefits Scenario Unrestricted Restricted Year Low FOR in VI Plan (MW) (MW) Program Program 1985/ / / / / VII Plan Additions / / / / / VIII Plan Additions

57 -51- ANN~EX 5 Table 5 Page 7 of 12 pages Table 5: Desirable Power Program (All India) (Actual) Existing capacity as on 31/3/82 (MW) Hydro Thermal Nuclear 860 Sub-Total Additions (MW) from (a) Committed Projects Hydro Thermal Nuclear 1/ Z-i Sub-Total 4 / / 613W (b) New Projects Hydro Thermal Nuclear Sub-Total Total (a) + (b) Cumulative capacity (NW) Peak Load (MW) (Inter-regional Diversity not considered) Energy Requirement (Twh) ! / The above programme assumes that a capacity of MW would be added during the Sixth Plan. The inputs for the long-term planning study were finalised in August At that time, it was envisaged that a capacity of 4662 MW would be commissioned during According to present indications, it is expected that during a capacity of 3717 MW (including Nuclear) would be commissioned and erection in respect of 945 MW would be completed. 2/ Unconstrained:

58 Desirable Power Program (Northern Region) Existing Cap.as 31/3/1982 (MW) Hydro : 4143 Thermal: 4928 Nuclear: 440 Sub- Total : 9511 Additions (MW) from (a) Committed Projects Hydro Thermal Nuclear Sub-Total (A): W n (b) New Projects Hydro Thermal Nuclear Sub-Total (B) = Total (A+B) Cumulative capacity (MW) Peak Load (MW) Energy Requirement (MkWh) L.O.L.P. (%) with w Low F.O.R. L.O.L.P. (%) with High F.O.R.

59 Desirable Power Program (Western Region) '87 87-; Existing capacity as on 31/3/82 (MW) Hydro : 1810 Thermal: 6645 Nuclear: 420 Sub- Total : 8875 Additions (MW) from (a) Committed Projects Hydro Thermal Nuclear Sub-Total (b) New Projects Hydro Thermal Nuclear Sub-Total = = = = U, Total (a) + (b) Cumulative Capacity (MW) Peak Load (MW) Energy Requriement (MkWh) L.O.L.P. (%) with Low F.O.R. L.O.L.P. (%) with High F.O.R. F-

60 Desirable Power Program (Southern Region) Y Existing capacity as on 31/3/82 (MW) Hydro : 5098 Thermal: 3034 Nuclear: - Sub- Total 8132 Additions (MW) from (a) Committed Projects Hydro Thermal Nuclear Sub-Total (b) New Projects Hydro Thermal Nuclear Sub-Total = Total (a) + (b) Cumulative Capacity (MW) Peak Load (M W) Energy Requirement (MkWh) L.O.L.P. (%) with Low F.O.R. L.O.L.P. (2) with High F.O.R. r Dn 0n

61 Desirable Power Program (Eastern Region) Existing capacity as on 31/3/82 (MW) Hydro : 972 Thermal: 4282 Gas 100 Sub- Total 5354 Additions (MW) from (a) Committed Projects Hydro Thermal Nuclear Sub-Total (b) New Projects Hydro Thermal Nuclear Sub-Total _ Total (a) + (b) Cumulative Capacity (MW) Peak Load (M)W Energy Requirement (MkWh) L.O.L.P. (%) with , Low F.O.R. 1 L.O.L.P. (%) with ,298 High F.O.R. D) (12

62 Desirable Power Program (North Eastern Region) Existing Capacity as on 31i3/82 (MW) Hydro : 147 Thermal: 183 Diesel : 53 Gas : 132 Sub- Total 515 MW Additions (MW) from (a) Committed Projects Hydro Thermal Nuclear _ Sub-Total (b) New Projects Hydro Thermal Nuclear _- - Sub-Total - = = ~ Total (a) + (b) Cumulative Capacity (MW) Peak Load (MWn m Fa Energy Requirement (Mklh) L.O.L.P. (Z) with Low F.O.R. L.O.L.P. (2) with a High F.O.R. m

63 -57- ANNEX 6 INDIA CENTRAL POWER TRANSMISSION PROJECT Southern Region Sales and Energy Data 1979/ / / / /82 Installed Capacity (MW)1/ 6,606 7,051 7,532 Electricity Generated (GWh) 2 ' 24,662 26,313 31,613 Electricity Sold (GWh)-/ 19,884 21,767 23,262 Annual sales growth (%) Electricity consumption by category (GWh): Domestic 2,242 2,614 2,794 Commercial 1,342 1,446 1,567 Industrial 12,035 13,294 14,301 Agriculture 3,578 3,787 3,912 Other l/ excluding 600 MW centrally owned generation at Neyveli 2/ including sales outside the Region 3/ including purchases from outside the Region

64 -58- ANNEX 7 INDIA CENTRAL POWER TRANSMISSION PROJECT Southern Region: Installed Capacity, Peak Load and Energy Requirement 1977/ / Installed Capacity (}W)-/ 6,101 6,496 7,206 7,651 8,132 Peak Load (MW)-/ 4,058 4,471 4,385 4,905 4,924 Energy Requirement (GWh)-/ 22,012 25,317 25,492 28,252 31,407 1/ including Neyveli 2/ at station bus, restricted by supply Source: CEA

65 -59- ANNEX 8 INDIA CENTRAL POWER TRANSMISSION PROJECT Southern Region Power Supply Restrictions (% of potential demand) Karnataka Kerala Demand Energy Demand Energy April May June July August Sept Oct Nov Dec Jan ** 10-30** Feb ** 10-30** March ** 10-45** 24-45** - 16 hrs/day cut on agricultural consumers ** Cut on Industries Source: CEA

66 INDIA CENTRAL POWER TRANSMISSION PROJECT National Thermal Power Corporation Limited Organizational Structure (Revised) Board of Directors Chairman & Directorr_I Executive Committee Mancgement Commlttee Directai tor C ~~~~~~~~~~~~~~~~~~~~~~~ExctieDirector Dicg Personnel Technical Director ~~~~~~~~~~ ~~~~~~~~~~~~~~Commercial Fnrc c) e Administratior) Corrany & Training Secretory I ~~~~~~~~~~ transmission ExpEDPi&tn Corporate Oonration Engineering ~~~Panning& Cotat seiigmrketingmaaeit _ Engineering } l l Servicos l l Services l l P Design Services Services Systems Execulie Executive 0 ~~~~~~~~~~~~~~Director Dlrector - (Northern Region) (Western Region) 00 r D Pro ect Project Project Project 1 Project Engineering Headnersg Engineering n Hinv-l,norin Engineering Engineering Eng neering Ramagundom Singraucirian KortY) Faralkk)Vnhyca LY] General General General Chiet 'jt ~~~~~~~~~~~~~~GoGeral ral achtatgeneral Saaurrce NTPCroeli Rihanci Transmission Manager Manager Manag198transmisn Warl nager Manager Manager Ma~~~~~~nagersislo Firakkc indrvchlramagundam Source NTPC October 1982 World Blank

67 -61- ANNEX 10 INDIA CENTRAL POWER TRANSMISSION PROJECT NATIONAL THERMAL POWER CORPORATION LIMITED MANPOWER AS OF SEPTEMBER 30, '1982 Skilled or Engaged on Executive Supervisory Unskilled daily basis Total Singrauli ,013-1,673 Korba ,531 Ramagundam Farakka Vindhyachal Rihand Badarpur , ,876 Corporate Center Western Region Northern Region Southern Region _-_34 Total 'On the Job' 1,938 1,420 4, ,478 Trainees Total Manpower as at September 30, ,153 1,554 5, ,120 Projected 1ianpower Requirements FY1990 1/ 4,514 3,096 13,514-21,124 Present Manpower as % FY1990 requirements 48% 50% 37% - 43% 1/ Projected requirements for Corporate Centre, Singrauli (2,000 MW), Korba (2,100 MW), Ramagundam (2,100 MW), Farakka (2,100 MW), Rihand (1,000 MW) and Vindhyachal (1,260 MW). Source: NTPC October 1982.

68 -62- ANNEX 11 INDIA CFNTRAL POWER TRANSMISSION PROJECT NATIONAL THERMAL POWER CORPORATION LIMITED Recruitment of Trainees Executive Supervisory Skilled Total FY FY FY FY FY FY Actual Trainee Recruitment FY ,278 Projected Trainee Recruitment FY ,400 1,000 3,200 5,600 Total Required by FY1990 1/ 2,116 1,216 3,501 6,878 Actual Trainee Recruitment to FY1982 as % of total Requirement by FY % 18% 9% 19% 1/ Projected requirements for Corporate Centre, Singrauli (2,000 MW), Korba (2,100 MW), Ramagundam (2,100 MW), Farakka (2,100 MW), Rihand (1,000 MW) and Vindyachal (1,260 MW). Source: NTPC October 1982.

69 INDIA CENTRAL POWER TRANSMISSION PROJECT N.-a n -he--ci Power Copolon umteo Oigoflr- onol struptur- Corporoto Fmoonc r[0-o EV3~~~~~~~~~~~~~~ -t t0. A f.7--e 7 fi CT *I F] E ij~~~~~~~~~~~~~~~~~~~li ~ ~ ~ ~ ~ ~~~~~L

70 -64- ANNEX 13 Page 1 of 18 pages INDIA CENTRAL POWER TRANSMISSION PROJECT PROJECT DESCRIPTION The project consists of the following major physical components: kv Transmission Lines (See Attachment 1) Ramagundam - Mangur, double circuit 230 km Mangur - Vijayawada, double circuit 160 km Vijayawada - Nellore, single circuit 305 km Nellore - Red Hills, single circuit 245 km Singrauli - Vindhyachal, single circuit 14 km Ramagundam - Chandrapur, double circuit 158 km /220 kv Substations (See Attachment 2) Ramagundam - extension, to connect the second circuit to Mangur (the equipment for the first circuit is part of the Second Ramagundam Thermal Power Project). Mangur - new, to connect the two circuits to Ramagundam, the two circuits to Vijayawada and one 315 MVA, 400/220 kv transformer. Vijayawada - new, to connect the two circuits to Mangur, one circuit to Nellore and one 315 MVA, 400/220 kv transformer. Nellore - new, to connect the single circuit lines to Vijayawada and Red Hills and one 315 MVA, 400/220 kv transformer. Red Hills - Chandrapur - Singrauli - Vindhyachal - extension, to connect the single circuit line to Vijayawada. extension, to connect the double circuit line to Ramagundam. extension, to connect the single circuit line to Vindhyachal. extension for the single circuit line to Singrauli and the 500 MW HVDC back-to-back substation.

71 -65- Annex 13 Page 2 of 18 pages MW High Voltage Direct Current (HVDC) Back-to-Back Substation at Vindhyachal (See Attachment 3) 4. Meetering and Instrumentation (See Attachment 4) Installation of tariff meetering systems and disturbance recorders in important substations of the Northern, Western and Southern Regional grids. 5. Communication System (See Attachment 5) Power line carrier communication (PLCC) equipment complete for speech transmission, line protections and data transmission on each 400 kv transmission line.

72 -66- Annex 13 Attachment 1 Page 3 of 18 pages 1. Line Configuration Salient Features of the 400 kv Transmission Line Single circuit lines would have a horizontal and double circuit lines a vertical configuration. 2. Equipment Description Towers Self-supporting latticed steel towers, fabricated from structural steel angle sections will be used. A1 the components of the towers will be hot-dip galvanized. Normally, the following four types of towers will be used: - 'A' type suspension straight run tangent towers for up to 2 degrees angle of deviation; - 'B' type tension towers for angles of deviation in the line up to 15 degrees, also to be used as section towers; - 'C' type tension towers for angles of deviation in the line up to 30 degrees, also to be used as section towers in difficult terrain; and - 'D' type tension towers for angles of deviation in the line up to 60 degrees and also as dead-end (terminal) towers. In addition, special towers and foundations are envisaged for major river and power line crossings and places where the right of way is restricted or the terrain is particularly difficult. The design of these towers and foundations will be finalised after detailed soil investigation and route survey. Conductors Twin bundles of 54/7/3.53 'MOOSE' ACSR, or equivalent conductors, will be used per phase, which will provide a power transfer capability of about 600 MW per circuit. As for all 400 kv NTPC lines, the intra-phase spacing will be 450 mm, which will result in the optimum with respect to line inductance and line loss characteristics.

73 -67- Annex 13 Attachment 1 Page 4 of 18 pages Earthwire and Lightning Protection Suitable galvanized steel earthwire will be used to withstand two successive lightning strokes of 150 kiloampere. It will have a tension-to-weight ratio about 20% higher than the power conductor. Since the lines would be passing for an appreciable length over hilly terrain, the shielding angle is intended to be reduced to 20 degrees in order to minimize snielding failure. Grounding The tower footing resistance will be kept below 10 ohms. Normally pipe type grounding will be used. In case of rocky ground where the ground resistance is high, counterpoise earthing will be used to bring tower footing resistance down to an acceptable level. Insulators and Hardware High strength glazed procelain disc insulators will be used. Suspension strings will consist of 23 discs (255x145 mm) of 120 kn mechanical strength and tension strings will consist of 23 discs (280x170 mm) of 160 KN mechanical strength. 3. Summary of Regulations and Practices for Routing 400 kv lines in India Ground Clearance As per item 77 of Chapter VIII of Indian Electricity Rules (as amended upto June 1979) the clearance above ground shall not be less than 5.20m plus 0.3m for every 33 kv or part thereof by which the voltage of the line exceeds 33 kv. For 400 kv lines it works out at 8.84m. Compensation No compensation is normally required for land in case of transmission lines. Compensation is, however, paid for plantations including the land involved. Land compensation is also involved in traversing urban areas but 400 kv lines are usually routed in such a manner as to avoid urban areas. Compensation is made for the crop damaged, if any, during erection work. Forest Clearance While fixing the alignment of the line all efforts are made to avoid reserved forest land. In cases where it is unavoidable as per

74 -68- Annex 13 Attachment 1 Page 5 of 18 pages Forest (conservation) Act advance clearance from the Forest Department, Ministry of Agriculture, Govt. of India is required to be taken. For trees cut down in a reserved forest, the cost of planting three trees, for every tree cut down, is paid to the Forest Department of the State Government. For normal right of way, trees falling on the line route are to be cut and compensation paid to the owner. A right of way of 26 m on either side of the centre line of the route is provided. 4. Measures Adopted to Avoid Electrical Interference in Telecom Circuits Growth of Power and Telecom Systems is vital to any country, especially for a developing country like India. Thus the concentration of telecom and power lines in close vicinity is unavoidable as both have to exist in serving common consumers. This brings in problems of extraneous induction encountered by the telecom circuits. To avoid induction, the transmission line routes are selected in such a way that the alignment, as far as possible, is away from open wire telephone/telegraph line alignment by at least 8 km. Sometimes in unavoidable circumstances it becomes impossible to maintain the adequate separation between the power and telecom lines. In such cases, induced voltages in the paralleling telecom circuits are computed under actual conditions and the following protective measures are adopted as per present practice in India. A.. Communication Circuits i) For induced voltage up to 430 volt no protective measures are considered necessary. ii) Beyond 430 volt but up to 650 volt adequate numbers of gas discharge (G.D.) tubes are installed on the affected telcom circuits. Telecom authorities in such cases do not charge compensation from power authorities. iii) Beyond 650 volt and up to 2000 volt again adequate numbers of G.D. tubes are installed on the affected telecom circuits, but in such cases, whoever, i.e. the power or telecom authority, is the later entrant, has to pay the cost of such protective works. iv) If induced voltage is much higher than 200 volt re-engineering of the affected telecom circuits is done. The following re-engineering works are commonly adopted in India.

75 -69- Annex 13 Attachment 1 Page 6 of 18 pages a) The telecom line is shifted from the existing alignment to a different route to maintain the desired separation distance. The cost of re-routing the telecom line is paid by the later entrant (the power authority); b) The removal of the affected overhead telecom alignment and the provision of aluminium sheathed star quad cable of suitable capacity with screening factor of 0.1 with provision of V.F. repeaters to compensate the cable loss; and c) The removal of the overhead telecom alignment and the provision of the circuit on other media like UHF/Microwave system etc. B. Railway Block Circuits Railway block circuits are provided basically for the safety problems of the trains, although such circuits may also be protected against high induced voltages by the installation of gas discharge tubes and by changing the block instruments with 300 volt to 450 volt immunization level. In cases where induced voltage is higher, overhead block circuits are removed and re-engineering of circuits like that of communication circuits is done at the cost of the later entrant. Conduction As the name implies, conduction is brought about by actual electrical contact between power and telecom lines. Crossing of both the lines therefore is done under the following manner as per the code prescribed by the Power and Telecom Co-ordination Committee constituted by the Government of India. i) Angle of crossing shall be as nearly a right angle as possible; ii) Adequate clearances as prescribed by Central PTCC are to be adopted between power and telecom lines; iii) Adequate guardings shall be provided at the crossings for the power lines below 36 kv; and iv) No guarding arrangements are considered necessary in case of crossings with high voltage power lines above 36 kv.

76 -70- Annex 13 Attachment 2 Page 7 of 18 pages Salient Features of the 400 kv System and Substations 1. Insulation Coordination The 400 kv system has been designed to limit the switching overvoltage to 2.5 PU. The temporary overvoltage could be 2 PU for 1-3 cycles. Consistent with these values and the protected levels provided by lightning arrestors, the following insulation levels have been adopted for the 400 kv system: a) Impulse withstand voltage 1,320 kvp for transformers and reactors 1,425 kvp for other equipment b) Switching surge withstand voltage 1,050 kvp c) Minimum creepage distance 10,000 mm d) Maximum fault current 40 ka e) Duration of fault 1 sec f) Corona extinction voltage 320 kv rms Compensation equipment has been provided to control the steady state transient and dynamic overvoltage to specified levels. Detailed system studies for various combinations of operating conditions will be conducted to work out the required compensation. Tentatively 420 kv shunt reactors of 50 MVar capacity are foreseen. In the event of generators not capable of charging the 400 kv lines in spite of adequate fixed compensation, additional variable compensation may be provided. 2. Interconnecting Transformers Power transformers will conform in general to IEC 76. the knee point voltage of transformers will not be less than 1.1 PU and the air core reactance will not be less than 20% for two winding transformers and 40% for autotransformers. Autotransformers will have a 33 kv tertiary winding which shall be capable of being loaded to 1/3 of the transformer loading. The insulation level of the tertiary will not be less than 250 kv peak for lightning impulse and 95 kv rms for power frequency voltages.

77 - 71- Annex 13 Attachment 2 Page 8 of 18 pages 3. Circuit Breakers Circait breakers will conform in general to IEC 56 and shall be either of air blast or SF6 type. The total break time for any current and any combination of other conditions shall not exceed 50 ms for 400 kv breakers. The 400 kv breakers controlling line feeders will be provided with preinsertion closing resistors of about 400 ohm with 8 ms insertion time. The short line fault capacity shall be the same as the rated capacity and this is proposed to be achieved without the use of opening resistors. 4. Isolators The isolators will conform in general to IEC 129. The 400 kv isolators will be horizontal center break and pantograph type depending upon the layout arrangement adopted for each substation. They will have an individual pole operating mechanism. All isolators shall be preferably of the motor operated type. Earthing switches shall be generously provided to facilitate maintenance. These should be properly interlocked and allinterlocks shall be fail safe type. 5. Current Transformers Current transformers will comply in general to IEC 185. All taps are to be obtained by secondary switching. Current transformers unit with 5 secondaries (4 for protection and I for metering) are proposed. The accuracy of the protection cores shall be class PS and for metering core it shall be 0.5. The burden and the knee point voltage shall be in accordance withn requirements of the system including possible feeds for telemetering. 6. Capacitive Voltage Transformers Voltage transformers will in general conform to IEC 86 and 186A. They shall have three secondaries out of which 2 shall be used for protection and 1 for metering. The accuracy of protection core shall be 3P and for metering shall be 0.5. The VTS provided on lines shall be suitable for carrier coupling. The capitance of CVT shall be 4400 pf. 7. Lightning Arrestors Station class, current limiting heavy duty lightning arrestors are proposed which will be conforming in general to IEC 99. The rated voltage of LA and other characteristics shall be chosen in accordance with system requirements. LA would be provided near line entrances and near transformers and reactors so as to achieve proper insulation coordination for the whole substation.

78 -72- Annex 13 Attachment 2 Page 9 of 18 pages 8. Shunt Reactors 50 MVar, 420 kv Shunt reactors are envisaged. The shunt reactors would have linear characteristics up to 1.5 PU voltage. The neutral of these shunt reactors shall be grounded through adequately rated neutral grounding reactors to facilitate single phase reclosure against trapped charges. The neutral of shunt reactors shall be insulated to 132 kv and shall be protected by means of 132 kv class lightning arrestors. 9. Protection and Control Suitable control and protective relaying system shall be provided for all the 400 kv substations equipment and feeders which include 400 kv transmission lines, bus bars interconnection transformers etc., and complete with all necessary equipment. The complete protection equipment auxiliary relays, trip relays timers, annunciators, indicating lamps, indicating instruments, meters, switches, semaphore indicators, mimic diagrams, name plates, terminals and associated equipments and other inter-facing and auxiliary equipment like event-loggers, disturbance recorders, master clocks, AC clocks and follower clocks, synchronising trolley, relay test kits etc., shall be provided. The protection system shall be in accordance with the modern power system philosophy with equipment having high reliability and speed and the transmission lines protection and auto reclosing single and three phase selection. The transmission line protection system shall have maximum operating time up to trip impulse to breaker (complete protection time including the applicable carrier and trip relay operating times) for all type of faults anywhere in the protected line sections during both maximum and minimum generation conditions of 30 ms at the nearest end and 50 ms at the other end (carrier transmission time may be taken as 20 ms provided that any time reduction in carrier time shall be directly reflected as a deduction in the maximum operating time). The bus bar protection wold be provided for each bus section independently along with the check feature, so that in the event of a fault, only the minimum number of the circuits shall be disconnected at the same time ensuring complete fault isolation and shall be of high speed type. The interconnecting transformer would be provided with differential protection, restricted earth fault protection,back-up protection and overfluxing protection etc. 10. Bus Switching Schemes Ramagundam and Red Hills - Breaker and half scheme. Mangur, Vijayawada and Nellore - Breaker and half scheme.

79 -73- Annex 13 Attachment 2 Page 10 of 18 pages 11. Layout Chandrapur - Madhya Pradesh switchyard where double main and transfer scheme is adopted. Singrauli, Vindhyachal - Double main and transfer scheme like in all NTPC thermal power plants. Breaker and Half Scheme Rigid aluminium tubular bus bars are proposed. The cross-overs, wherever required, could be of rigid or strung type with twin 'Moose' ACSR conductor. Substation is of two levels, i.e. equipment and bus bar at first level and cross-overs at second level. Double Main and Transfer Scheme Quadruple Moose ASCR flexible bus is proposed. The substation is of three levels i.e. equipment at first level, bus bars at second level and cross-over at third level. Bus selector isolators are pantograph type. 12. Substation and Support Facilities Certain basic facilities required for operation and maintenance of the substation are described below: AC & DC Power Supplies For catering to the requirements of three phase and single phase AC and DC control and power supplies for the various substation equipment, the following arrangement is envisaged: a) AC supply: Supply from a nearby reliable medium voltage (33 kv, 11 kv or 6.6 kv) source would be drawn. This would be stepped down to 415 volts for distribution within the substation through two transformers of suitable rating. For additional reliability, diesel generators of suitable capacity would be provided depending upon the reliability of the MV supply. b) DC supply: 220V and 50V batteries of adequate capacity would be provided. Each battery would have a boost charger, float charger and trickle charger.

80 -74- Annex 13 Attachment 2 Page 11 of 18 pages Workshop and Laboratory Workshop and Laboratory facilities would be provided for periodical and preventive maintenance of the equipment. Oil Evacuating, Filtering, Testing and Filling Apparatus To monitor the quality of oil for satisfactory performance of transformers and for periodical maintenance, necessary oil evacuating, filtering, testing and filling apparatus would be provided. Oil tanks of adequate capacity for storage of pure and impure transformer oil would be provided. Fire Fighting System Fire fighting system will, in general, conform to fire insurance regulations of India. The system is proposed with both AC and diesel driven pumps. Automatic heat actuated emulsifying system is proposed for transformers. Lightning and Communications Adequate normal and emergency lightning and communication systems would be provided. Control Room Switchyard control room would be provided to house the control and relay panels, PLCC equipment, telemetering equipment, digital analogue processing and recording equipment, etc. Air conditioning will be provided in the building as functional requirement. Transport Facilities For movement and unloading of heavy apparatus like power transformers and reactors, rail tracks within the substation and mobile cranes would be provided. One tractor trailer of suitable capacity is proposed to be provided under this project for movement of heavy apparatus like transformers and reactors to areas where proper railway sidings are not available. Field Testing Equipment One set of field testing equipment is proposed to be procured under the project.

81 -75- Annex 13 Attachment 2 Page 12 of 18 pages Hotline Washing Equipment Hotline washing equipment would be provided at substations, depending upon need to be established after detailed investigations of site environment. Staff Colony Staff colony to house the personnel manning the substations, would be provided.

82 -76- Annex 13 Attachment 3 Page 13 of 18 pages 500 MW HVDC Back-to-Back Substation at Vindhyachal 1. Solid State Valves The solid state valves to be incorporated in the HVDC terminals will comprise of a series-parallel combination of high power water cooled silicon controlled rectifiers (thyristors) which, through control of their firing angle provide the means of power transfer from the AC to DC side or vice versa. The solid state valves must be of modular building block design for easier design optimisation. 2. Convertor Transformer Two convertor transformers banks, suitably designed to withstand the insulation requirements of DC application will be used per pole to step up or step down the AC voltage to the appropriate level before transformation to achieve optimum valve design. The secondary of the transformers shall be properly connected to achieve the required phase shift for proper convertor operation. 3. Reactors Smoothing reactors will be provided on the DC side for absorption of the ripple voltage generated during conversion. 4. Filters AC and DC filters will be such as to offer a low impedance path to ground for harmonics generated in the AC and DC systems. 5. Reactive Compensation Reactive compensation equipment will be provided to restore the AC side power factor to near unity. These may be of static Var control, shunt capacitor banks, or synchronous condensers or a combination or the three. 6. Communication Control and Instrumentation Protection, monitoring, measuring, communication and auxiliary equipment,as required for the high reliability operation and easy fault detection and maintenance,will be provided.

83 -77- Annex 13 Attachment 4 Page 14 of 18 pages Installation of Tariff Metering Systems and Disturbance Recorders in the Regional Grids in India 1. Background The power systems in the country are being interconnected through 400 kv transmission lines to evolve the regional grids. The construction of thermal power stations by NTPC together with 400 kv lines is accelerating the process of interconnection in the regions. The power generated at NTPC's thermal power stations is allocated to the different States in the Region according to the policy laid down by the Government of India. The power to the beneficiaries sometimes flows through transmission systems in the integrated network belonging to other agencies such as the States, the Damodar Valley Corporation (in the Eastern Region), the Bhakra Beas Management Board (in the Nothern Region) etc., while in certain areas NTPC's transmission system carries power generated by the State generating stations for transmission within the States or sometimes outside the States. The generation from the different agencies such as the power generated by the National Hydro-Electric Power Corporation, the Department of Atomic Energy, the Neyveli Lignite Corporation and other agencies also gets fed into the respective regional grids. In order to compute the energy that is fed into the system from different sources and the energy actually drawn by the different systems, a special metering system is necessary. 2. Objectives of the Metering Schemes The tariff metering schemes would provide for: a) Metering MS, MVar, MVA, MWh, kvar and MVarh exports and imports continuously; b) Facilities for recording (printing) data according to the prescribed format, and storing the data for computing daily, weekly and monthly; and c) Facilities for transmitting data through telemetry systems to the control center in the State and/or in the Region. The instruments will have facilities for dividing the day into different periods to facilitate, if necessary, the introduction at a later stage of time of day metering system. A single instrument shall be capable of accepting all the input information for a mnaximum of ten circuits; at very large substations where the number of circuits is more than ten, two such instruments would be used. The basic element in the instrument is a conventional energy meter which again would receive the inputs from CTs and VTs in the substation or generating station. The energy meter would be interfaced to a microprocessor system which shall compute

84 -78- Annex 13 Attachment 4 Page 15 of 18 pages different quantities for record through a printout in the prescribed format and also for display on demand. The display shall provide for the instantaneous value in MW, MVar, '4VA and cumulative MWh, MVarh and also for display of cumulative figures for say a day, week or a month. The printout facility shall print out different quantities every 30 minutes and also over a period of 24 h as well as the cumulative figures over a month. The approximate cost of an instrument is US$120. The list of stations where instruments of this type are proposed to be installed in the Northern, Western and Southern Regions are given below. The stations where the instruments would be installed would undergo some change when the scheme is finally worked out in consultation with the Regional Electricity Boards. 2. Disturbance Recorders The interconnection of individual systems in the Region necessitates that operating conditions should be carefully monitored and, whenever abnormual conditions in the system arise these are also accurately recorded so that the post-disturbance analysis could be carried out. Such analysis would facilitate taking corrective measures to prevent recurrences of the disturbances. The absence of suitable instruments for recording the system conditions before, during and after the disturbance, has left many of the disturbances in the systems incompletely analysed. NTPC has been providing disturbance recorders on all its 400 kv lines. However, such recorders are not provided on some of the 400 kv lines in the Northern and Western Regions and generally in most of the 220 kv systems in all the Regions. 3. List of Power Stations and Substations where Tariff Metering will be Installed Northern Region Name of the Substations/Power Stations VoltageLevel (kv) I. Narela 220/33 2. Hissar 220/132/11 3. Dadri Ganguwal 220/33/11 5. Dehar Bhakra Pong 220/66/11 3. Badarpur 220/33

85 -79- Annex 13 Attachment 4 Page 16 of 18 pages 9. M4uradnagar Singrauli Kanpur Obra 400/ Raps Lucknow Baira Siul Panipat 220/ G.N.T.P Anpara Bhakra R.B I.P. Station Faridabad UBDC Shanan Bassi Giri Lower Jhelum Chenani Upper Sindh R.P. Sagar Jawahar Sagar Rihand Obra Hydel Matatila 34. Khatima Yamuna I & IV Ramaganga Pathri (Ganga Canal) 38. Chilla Harduaganj 220 Western Region Name of Substation/Power Station Voltage Level (kv) 1. Gandhinagar Wanakbori 400/ Asoj Ukai Walthan Jetpur 400/ Kalwa 400/ Tarapur Trombay Nasik Bableshwar 132

86 -80- Annex 13 Attachment 4 Page 17 of 18 pages 12. Bhusaval 400/ Koyna Karad Kolhapur Parli Indore Koradi Satpura Itarsi Jabalpur Bhilai 400/ Korba (MPEB) Korba (NTPC) Vindhyachal Bodaghar (Barsur) 132/ Chandrapur 400 Southern Region Name of Substation/Power Station Voltage Level (kv) 1. Belgaumi 220/ Hubli 220/ Sharavati Shimoga 220/ Mysore 220/ Bangalore 400/220/ Sanem 400/220/ Idikki Siragiri Tuticorin Neyreli 400/220/ Kalpakkam Ennore 220/ Red Hills 400/220/ Cuddapah 400/220/ Gooty 220/ Munirabad Raichur 220/ Sri Sailam 220/ Nagarjun Sagar 400/ 220/ Hyderabad 400/22/ Vijayawada 400/ Kothagudem 220/ Mangur 400/ Lower Sileru Upper Sileru Ramagundam 400/132

87 -81- Annex 13 Attachmnent 5 Page 18 of 18 pages Communication System Power Line Carrier Communication (PLCC) equipment complete for speech transmission, line protections and data transmission will be provided on each 400 kv transmission line. The protections for the transmission lines and line compensating equipment will have 100% back-up communication channels. The PLCC equipment shall include the following: a) Coupling device, line traps, carrier terminals, voice frequency terminals, protection couplers, HF cables, trunk selectors, automatic exchange for 25 lines, spare parts, maintenance and testing instruments. The equipment supplied will not be limited to the above and shall include all other equipment which is necessary for the proper functioning of communication system; b) Coupling devices suitable for 4400 pf CVTs and for phase-to-phase coupling. The pass band of coupling devices shall have sufficient margin for adding communication channels in future, if required. Necessary protective devices for the safety of personnel and low voltage parts and installations against power frequency voltage and transient over voltages will be provided; c) Line traps broad band tuned and suitable for blocking the complete range of carrier frequencies. Line traps shall have the necessary protective devices such as lightning arrestors for the protection of running pots; and d) Carrier terminals of single side band amplitude modulation type and 4 khz band width. The speech channels shall be suitable for superimposing teleprinter and data signals. The total transmission time for protection signals shall not exceed 20 ms. The carrier frequencies which are already in operation in the area shall be kept in view while selecting the carrier frequencies for the specified PLCC links.

88 -82- ANNEX 14 Page 1 of 4 pages INDIA CENTRAL POWER TRANSMISSION PROJECT Project Cost Estimates Rs. Million US$ Million Local Foreign Total Local Foreign Total kv LINES A. Ramagundam - Chandrapur (double circuit, 158 km) Preliminary works Towers Conductors & Earthwires Insulators & Hardware Accessories Miscellaneous Sub-total A B. Ramagundam - M_angur (double circuit, 230 km) Preliminary works Towers Condunctors & Earthwires Insulators & Hardware Accessories Miscellaneous Sub-total B C. Mangur-Vij ayawada (double circuit, 160 km) Preliminary works Towers Conductors & Earthwires Insulators & Hardware Accessories '4iscellaneous Sub-total C

89 -83- ANNEX 14 Page 2 of 4 pages 0. Vijayawada-Nellore (single circuit, 305 km) Preliminary works Towers Conductors & Earthwires Insulators & Hardware Accessories Miscellaneous Sub-total D E. Nellore-Redhills (single circuit, 245 kin) Preliminary work Towers Conductors & Earthwires Insulators & Hardware Accessories Miscellaneous _ Sub-total E F. Singrauli-Vindhyachal (single circuit, 14 km) Preliminary works Towers Conductors & Earthwires Insulators & Hardware Accessories Miscellaneous Sub-total F Sub-total 1 1, , Physical Contingencies Price Contingencies TOTAL 1 1, , KV_SUBSTATIONS A. Mangur Land & Colony Structure Civil works Construction charges Equipment Sub-total A

90 -84- ANNEX 14 Page 3 of 4 pages B. Vijayawada Land & Colony Structure Civil works Construction charges Equipment Sub-total B ] T4 1.7p9 C. Nellore Land & Colony Structure Civil works Construction charges Equipment Sub-total C D. Redhills Land & Colony Structure Civil works Construction charges Equipment Sub-total D E. Chandrapur Land & Colony Structure Civil works Construction charges Equipment Sub-total E F. Ramagundam Land & Colony Structure Civil works Construction charges Equipment Sub-total F G. Singrauli Land & Colony Structure Civil works Construction charges Equipment Sub-total G =

91 -85- ANNEX 14 Page 4 of 4 pages H. Vindhyachal Land & Colony Structure Civil works Construction charges Equipment Sub-total H Sub-total Physical Contingencies Price Contingencies TOTAL 2 1, , BACK-TO-BACK HVDC VINDHYACHAL Substation (land structure etc. included under AC portion of the substation) Physical Contingencies Price Contingencies TOTAL , , METERING & INSTRUMENTATION Equipment Physical Contingencies Price Contingencies TOTAL PLCC COMMUNICATIONS System Physical Contingencies Price Contingencies TOTAL CONSULTANCY ENGINEERING & ADMINISTRA TION 8. TOTAL PROJECT COST (BEFORE DUTIES & TAXES) 2, , , DUTIES & TAXES TOTAL PROJECT COST 3, , , INTEREST DURING CONSTRUCTION FRONT-END FEE TOTAL FINANCING REQUIRED 4, , ,

92 -86- XX L 4-J U W if -oz _ t = 'i o 4 O e4 ~~ I X ~~~ -3 2_ X E ' i % R % i

93 -87- ANNEX 16 INDIA CENTRAL POWER TRANSMISSION PROJECT ESTIMATED SCHEDULE OF DISBURSEMENTS IDA Fiscal Year Cumulative US$ and Half-Year Million Equivalent % Undisbursed 1983 June December June December June December June December June December June December

94 INDIA CENTRAL POWER TRANSMISSION PROJECT NATIONAI THERMAL POWER CORPORATEON LIMITED Schedule of Commissioning of Power Plants and Power Generation 'lersue Schedule at Time of Second Ramagundam Appraisal (.January 1981) FY1982 FY1983 FY1984 FY1985 FY1986 FY1987 FY1988 FY1989 FY1990 FY1991 FY1992 FY1993 FY1994 FY1995 FY1996 Sate Date a Date a Date a Date * Date * Date Date Date a Dare Date * Date * Date R Date * Date * Sigrauli I MW Units Feb 82- Oct 82 2 Aug MW Units Feb 83 - Feb 84 - SingrauJ.i II MW Units Fob 87 5 Feb 88 5 Korba I MW Units Jan 83 - Jul MW Units Jan 84 - Korba II -500 MW Units Jun 87 6 Jun 88 6 Jun 89 6 Ramagundam I MW Units Feb 84 - Aug MW Units Feb 85 - Ramagundam II MW Units Dec 87 3 Dcc 88 3 Dec 89 3 Farakka I M'' Uinits Jan 85(2) Jul 85 (2) 200 MW Units Jon 86 (7) Faral.ka It MW Units Apr Apr Apr 91 I'll Rihand MW Units Jun 87 - Jun 88- Vindhyachal MW Units Jun 87 - Jun 88 - JuMn MW Units Dec 87 - Dec 88 - Dec 89 - Projects 0ou yet Identified Mar 93- Oct 93 - Oct 94 - Oct MW Units Mar 94 - Mar 95 - TOTAL NTPC COMMISSIONING Currently Scheduled: Units - Fiscal Year I L - To date MW Capacity - Fiscal Year , ,420 1,920 1, ,000 1, To date ,800 2,400 2,800 3,300 5,720 7,640 9,560 10,060 10,560 11,060 12,060 13,060 13,560 Scheduled at Rama&undam Appraisal: Units - Fiscal Year To date MW Capacity - Fiscal Year , ,000 1,500 1,500 1, ,300 8,300 8,300 8,300 8,300 -ToI US CURRENT SCHEDUtiE VRiS ,800 2,400 2,800 3,800 5,300 6,800 7, ,300 8,300 8,300 8,300 8,300 RAMAGUNDAM APPRAISAL Capacity Increase/(Decrease) at FY Year End Due To: Additional Projects (MW) ,840 2,260 2,260 2,260 2,760 3,760 4,760 5,260 Commissioning Slippage (MW) _ (500) (500) (1,000) (500) (500) Power Generation (GWh) TOTAL. Increase/(Decrease) Due To: FY Additional Projects - GWlI - - 1,758 5,538 9,223 11,858 12,430 12,534 14,575 67,916 % Commissioning Slippage Offset by Earlier Stahilication - tloll (1,646) (3,438) (3,816) (2,980) (1,396) (396) - 8,73 w N (8) (13) (11) (7) (3) (1) - (3) x Total Generation Iocrease/ (Decrease)- GWh ,783 1, ,100 5,407 8,878 11,034 12, ,143 % late: * No. -soths later/(earlier) than schedolled at Ramalandao Appraisal S-L-ce: NTPC October 1982

95 INDIA CENTRIL POWER TRANSMISSION PROJECT NATIONAL THERMAL POWER CORPORATION LIMITED INVESTMENT PROGRAM FOR THE PRJIOD FY1977 THROUG. FY1996 (Rupees Million) Year ending March 31st FY1977 FY1978 FY1979 PY1980 FY1981 FY1982 FY1983 FY1984 FY1985 FY1986 FY1987_FY1988 _FY1989 FY1990 FY1991 FY1992 FY1993 FY1994 FY1995 FY1996 Total POWER STATION8 SINGRAULI , , , ,098 XORBA ,131 2,377 1,541 2,581 2,934 2,427 1, _ 16,377 RAMAGUNDAM ,008 1,800 2,457 2,064 4,531 2,789 2,255 1, ,031 PARAKXA ,950 2,735 2,313 2,537 3,140 3,498 1,531 1, ,879 VINDHYAC{A ,771 3,064 3,448 2,700 1, ,597 RIHAND _ ,323 2,933 3,372 2,699 1, ,712 UNIDENTIFIED NEW PROJECTS ,123 4, , ,546 2, ,981 TOTAL ,506 2,181 3,911 6,407 10,618 14,275 18,233 14,830 12,836 11,567 8, ,262 3, TRANSMISSION WORKS SINGRAULI _ ,197 KORBA _ Z146 RAMAGUNDPM _ ,114 1, ,057 FARiKA _ 1,822 VIND4YACKAL - - _ , _ - 3,351 CENTRAL TRANSMISSION _ - _ ,738 2, TOTAL ,439 3, , _ ,487 GRAND TOTAL ,656 2,527 4, ,066 23,338 17,449 13, ,215 10,823 9,908 6,262 3,546 2,l ,162 (Includes interest during -nulructinn) Source: NTPC October 1972

96 -90- C E ANNEX 19 C 0CC)-. )). CCC. <CC CC C Cit C C -8- I I I I C-,C CC CCC C o o -CC C C CCCL Ct CCLCL CLCC I I I II I C)CLECL CCC CCC CCCLI C i I OCICLI CC-. CCL - I SCCL CC> CCLV I I di OCOCI CC II III CL C CC CL CL -CCCL CCC I I II C CL CL CCLC C-C I CL CL CL CCLC.0--C C F - CL 0 C C-C. CCCL CC CL-CL C 0 C CL C C CL CC 0CC CCC -,CCL CC CCC CCC CCCL -CC C - CCH C C CL I-CL CCC) CCLC 0CC I-C I- - - I- CC CCC CCCL 0CC C CCLC C C CCCL C C 00< C - C - CI CC CL CLI C) - C C C C C. 0CC CCLC CLCC CCCL C-CC CCCL 0CC) CLH.CC CL CL CCLC. CCLC CCCL 0CC) II HC- II I I I CL CF-CL C CI C CL 0CC <CC CCC) CL C CL C 00 CL - CL C. FHC CL CL CL C I CL CL CL <I CCCL CCC CCLC CCC -C-CC 000 0CC CLCLC 0CC) CCCL CCC CCC) 0CC. I I II] II I I C CCC CCCL CCCL CL C CL CL CL CL CL C.-. CL CLI CL CL CCC CLCC CCCL CCC C CCC CCC CCC CCC CCC. 0-,C CCC) CCC CCLC I I II.11 I I C CC- -CCC CCC C C C 0CC CCCL CLCC C)CC CCCL C-C CC-C CCC -0CC CCL CC0) CC. CCL C -C -C CCL I <C CL CL CL[CL C CCC CCC CCC CCCL CL CC-C CCCL CC 000 III II I I I C CCCL 0CC CCCL CC-C C C CL 0CC C-.C CC-C C C CL 00 CL CL C -C CL C CL CL H CCC CCC CCLC 0CC C C' CCC COO CC 1 C C-CO I I I I I I I I C C C. C-C -CCCL CCC) CCCL I I C. I-CLCLI - 0CC C C.-C- OCIC 0 NJ CCCL CCC.CL4 COC CCC II I I I I I I C CL C C C. C CL CC CL C CC) C VC C C C - C CL 00 CL CL C C C C CL CL - - CC C CL C C C C C C C CL C C C C S -H C -H - -- C C C C CL S CC C C.C C CC. C 'C C C C C CC C CC H CLCH C CCL - 'CC C.CL CC- CL CC.- ICL CL CL CC C -Cr CCLCCL CC2 C CC CC C CC C CC C ICC C-H CCC CCC CL C C NC I- S CL I-OH CCL CC-H CC CCCH CC CC. CC CCC CCL CC-CC-CL- C.20 CCL C., CLCCLCC CC.-SCC CCHCC CCCC COCLCC CCICC CLC..C <CL C COOC-. C.CCC.-I CCCCC C.CCCCI C.CCC CCCC- COCCI-- F-C) CC CL CCCC.C CCCC.C CC<C.C CCL.-C.C CCCLI-C CLCC CC.I-C CC CL 00 C CL--CF-.F-I CL'CCICH CLCF-.F-. CL--CLF-H ->CF-.H CCLF-'I- >-CLHH CCL CL F-.C C) C CL CL CL - CL C C -C C C C

97 INDIA CENTRAL POWER TRANSMISSION PFOJECT NATIONAL THERMAL POWER CORPORATION LIMITED STATEMENT OF PLANT CAPACITY, GENERATION AND SALES OF ENERGY Year ending March 31st FY1982 FY1983 FY1984 FY1985 FY1986 FY1987 FY]988 FY1989 FY1990 FY1991 FY1992 FY1993 FY1994 FY1995 CAPACITY (MW) Singrauli ,000 1,000 1,000 1,500 2,000 2,000 2,000 2,000 2,000 2,000 2,000 2,000 Korba ,100 1,600 2,100 2,100 2,100 2,100 2,100 2,100 Ramnagundam ,100 1,600 2,100 2,100 2,100 2,100 2,100 2,100 Farakka ,100 1,600 2,100 2,100 2,100 2,100 Vindhyachal ,260 1,260 1,260 1,260 1,260 1,260 Rihand ,000 1,000 1,000 1,000 1,000 1,000 1,000 Unidentified New Projects ,500 2,500 TOTAL ,800 2,400 2,800 3,300 5,720 7,640 9,560 10,060 10,560 11,060 12,060 13,060 GENERATION (GWh) Singrauli , , , , , , , , , , , , ,000.0 Korba , , , , , , , , , , , ,550.0 Ramagundam , , , , , , , , , , ,550.0 Farakka , , , , , , , , , ,550.0 Vindhyachal , , , , , , ,930.0 Rihand , , , , , , , ,500.0 Unidentified New Projects , ,019.9 TOTAL , , , , , , , , , , , , ,099.9 STATION USE (GWh) Singrauli Korba , , , ,039.5 Ramagundam , , , Farakka , , Vindhyachal ' Rihand Unidentified New Projects TOTAL , , , , , , , , , ,859.0

98 FY1982 FY1983 FY1984 F'Y1985 FY1986 FY1987 FY1988 FY1989 FYl990 FY1991 FY1992 FY1993 FY1994 FY1995 ENERGY SENT OUT (GWh) Singrauli , , , , , , , , , , ,010.0 l0,010.0 Korba , , , , , , , , , , , ,510.5 Ramagundam , , , , , , , , , , ,510.5 Farakka , , , , , , , , , ,510.5 Vindhyachal , , , , , , ,306.3 Rihanad , , , , , , ,005.0 Unidentified New Projects , ,388.1 TOTAL , , , , , , , , , , , , ,240.9 TRANSMISSION LOSS (GWh) Singrauli Korba Ramagundam Farakka Vindhyachal Rihand Unidentified Neu Projects TOTAL , , , , ,481.2 ENERGY SALES (GWh) Singrauli , , , , , , , , , , , ,759.8 Korba , , , , , , , , , , , ,247.7 Ramagundam , , , , , , , , , , ,247.7 Farakka , , , , , , , , , (1,247.7 Vindhyachai , , , , , , ,148.6 Rihand , , , , , , ,879.9 Unidentified New Projects , ,228.4 TOTAL ,070.(1 4, , , , , , , , , , , ,759.8 Station use as % of generation FY FY % Transmission losses as % of generation FY FY % (2.5% of energy sent out). Source: NTPC October 1972

99 -93- INDIA ANNEX 21 CENTRAL POWER TRANSMISSION PROJECT NATIONAL THERMAL POWER CORPORATION LIMITRD INCOME STATRMKNT COVERING OPERATIONS FY1983 THROUGH PY1995 (Rupees Million) Year ending March 31st Fl983 PY1984 Y19835 EY1986 FY1987 FY1988 PY1989 FY1990 PYI991 FY1992 PY1993 FY1994 FY1995 TOTAL SALE OF ENERGY (atl) 1,070 4, ,492 13,446 17,922 25,934 35,451 43,963 48,759 30,958 53,435 57,760 REVENUE - SULK SUPPLY (PAI1S/1W) Fuel Surcharge Central EBine (Pa"/K) OPERATING REVENUE Sales - Bulk Supply 345 1,405 2, , , , ,372 29,081 Salon - Fuel Sur-har-g ,506 2,234 2, ,182 4,809 Central Euciee ,011 1,066 TOTAL OPERATINGO REVKNUE ,210 4,864 5,972 8,145 12,122 17,264 22,363 25,919 20,192 30,565 33,956 OPERATING EXPENSES Singrauli - Furl Fuel Snroh-rge R DeFreciation Korhb - Fuel Fuel Sercharge Depreciarion Ranagu-dam - Furl ,045 1,199 1,253 1, Fuel Surcharge ,088 1, n Depr-ciation F-rakka - Fuel ,065 1,065 - Fuel Surcharge & Depreciati.n Vindhyachal - Furl Fuel Surcharge M Depr-ciatiu' Rihand - Fuel Fuel Surcharge M Depr-ciation niddentified 3on Project - Fuel ,115 - Fuel SuSrh-rge M Depr-ciati-n Trucsuinsion - 0 & M Ceutrul - Depreciati-n Tcaenniuulees Prciect DNpreciatiun Central 1.8 P/RWh gcneruted ,011 1,066 YOTAL OPERATING EXPENNES ,704 2,646 3,225 4,678 7,602 10,423 12,935 14,408 15,486 16,984 19,159 OFERATING INCOME (BeEfre Interest) ,218 2,747 3,467 4,520 6,840 9,428 11,510 12,708 13,581 14,797 Less Interest cn Loan 575 1,067 2,134 3,620 4,957 3,730 6,259 6,053 5,686 5,224 5,824 6,366 Seduce: InterestrcapitaliRed , , Net I-ureet Chargeahbl to Operut-ios ,117 1,499 2,500 4,035 5,494 5,782 5,824 4,484 7,757 8,431 Frofit: ,101 1, ,346 3,346 5,824 7, ,431- Def-rred Expe.ue Written off Net Eanings ,101 1, ,346 3,346 5,024 7,484 7,757 8,431 Average fixed acets tn use 3,471 9,320 16,405 22,667 29,870 51,024 76,348 91,488 99, , , , ,845 Rate of Recurn (Op-ratieg iccee bofre interest as I of average net fixed assets ia use). Adj-sted Nate of Esters 2., Operating Matit (Operating onpenses an Z of cpet-ticg revenue) 1/ Detenei.ed en the bhees ef: (i) assets i.u en edjuoted by CpplyiYe to unit i-vest-eet rests, the retio of the -sb-e of =neths following tnebh of toe.stsslnidg e the total -nethe In par (12); (i) unit sales (GVh) adjusted by spplying the rati deteened ir (i) sbove, to unit seine of oebh geder-tin6 unit ssosi- g operetin 't full stabilieed gee..rting capacity; (iii) revenue ad op=ratint sepenses edjnted te reflect adjusted nntes end nit.. Ies on raluulatnd In (i) and (ii) above. SOURC: RIITP October 1972

100 -94- A19NEX 22 0 '0' '0 4004< 4401 ' "'4'" 404 " -, ') <# '0 ' '0 0 0 '0 '0 044". '0 '0 4" ' '44 4" '40 - I I 0 4' 04 "' "' '00 4" - "0-00 '4 44 0' '04 04' '0-0' I F N N' '0 '0 0 0" ' '0 ' '0 444" 40 o ' '4 04 ' j '0 04' '4' 04 '0 N ' ' '0 ' ' o -< '0 '0 0, ' ' CC 40 04'- o o '0 40 0' 4004 ' ' 444 ' !'0"' ' ' '0 '004 '0 '0 '0 04 " 00 '44 '00 '0 '0 '0 '040 0 '0 00 ' '0 0 '0 444 '004 ' ' ' I ' ' '440< ' , N N ' N N ' < 4" '0 00 '0N N N 44 0' ' ' ' '04' '0 0 '0 04 ' ' ' 00' ' '0 44 '0 04 ' ' N I I 00 2 '0 '0 ' '0 00 '0 04 ' ' I ' ' ' $42 $ ' ' I,, '0, ' '0 '-4 ' III $4 $ " I I I 04 I I - I 44 N - <' '04 I-, '44 40 I 4.I ' I. 4 0 '0 I I 441 '0 0404' 04 44,0' 0 ' o ' ' ' ' C 40""' - 04 '40 4" 0 '-4 ' ' ' ' "ii , 40400,. 14> <-0 j : ' ' ' , '

101 INDIA CENTRAL POWER TRANSMISSION PROJECT NATIONAL THERMAL POWER CORPORATION LIMITED BALANCE SHEETS FY 1977 THROUGH FY 1995 (Rupees Million) Year ending March 31st FY1977 FY1978 FY1979 FYL980 FY1981 FY1982- ffy1983 FY1984 FY1985 FY1986 FY1987 FY1988 FY1989 FY1990 EY1991 FY1992 PY1993 FY1994 FY1995 ASSETS Gross Fined Assets ,313 12,636 21,064 26,176 36,880 70,341 90, , , , , ,792 (Historic Cost) Less Depreciation ,268 2,047 3,125 5,210 7,891 11,065 14,408 17,898 21,604 25,747 Net Fined Assets in Use ,255 12,385 20,426 24,908 34,633 62, , , R , Work-in-Progress ,369 4,678 8,856 11,075 19,020 30,658 48,884 55,629 35,704 27,612 19,931 25,307 30,454 29,762 19,208 6,780 Total FPxed Assets ,58S 5,114 9,542 17,330 31,405 51,084 73,792 90, , , , , , ,012 Short Term 134,852 Deposits 132, , CURRENT ASSETS Cash L Receivables , ,840 1,973 2,115 2,290 Inventories ,060 1,114 1, ,372 1,518 Other Debtors Total Current Assets ,345 1,841 2,374 3,036 3,378 3,644 3,997 4,441 Deferred Expenses = _ - - TOTAL ASSETS ,694 5,340 9, ,656 51,534 74,437 91, , , , , , , , ,615 EQUITY 6 IIABILITIES EQUITY Share Capital - Issned ,591 4,628 7,850 11,775 22, ,371 44,650 47,10 50,117 53,681 57,426 63,995 63,995 63,995 63,995 63,995 Share Deposits Retained Earnings ,318 2, ,634 5, ,111 15,935 23,419 31,176 39,607 A QUITY 34 Y I 1 4,628 7,850 11,820 23,223 37,889 47,069 50,777 54,751 58, , ,414 95, ,602 LIABILITIES Loans ,185 7,618 13,781 27,239 40,362 49,280 55,173 56,000 53,696 54,724 50,506 46,288 42,070 Current Liabilities _ _ ,051 TOTAL EQUITY & LTABI1ITIES ,694 5,340 9,746 17,424 31,656 51,554 74,437 91, , , , , , , , ,615 Debt - Equity Ratio /91 12/88 30/70 25/75 27/73 37/63 44/56 47/53 48/52 47/53 42/58 41/59 37/63 33/67 29/71 1/ Audited Accounts Source: NTPC October 1982

102 -96- ANNEX 24 Page 1 of 6 pages INDIA CENTRAL POWER TRANSMISSION PROJECT National Thermal Power Corporation Ltd. Assumptions for Financial Projections 1. The financial statements in this report display NTPC's financial operations for the period FY1977 through FY1995. They comprise income statements (Annex:es 21, and 25 to 28), with supporting statement of plant capacity, energy generation and sales (Annex 20), source and application of funds (Annex 22), with supporting investment program (Annex 18), and summarized balance sheets as at March 31 of each year (Annex 23). 2. Projections for FY 1983 throught FY 1995 are based on the following assumptions: (a) Commissioning of generating plant as reflected in Annex 17. (b) Energy Output 200 MW Units - First 6 months: 2,500 hours operation - Next 6 months : 4,000 hours operation - Second year : 5,500 hours operation 500 MW Units - First Unit Commissioned at Each Station - First year : 2,500 hours operation - Second year: 4,000 hours operation - Third year : 5,000 hours operation - Fouth year : 5,500 hours operation 500 MW Units - Subsequent Units of Each Station - First year : 2,500 hours operation - Second year: 4,000 hours operation - Third year : 5,500 hours operation

103 ANNEX 24 Page 2 of 6 pages (c) Fuel Cost (Basic) Escalation Singrauli - Based on kg/kwh and ) kg/kwh, for 200 and ) 500 MW respectively, at ) Rs /ton in FY 1983 ) Korba - Based on kg/kwh and ) kg/kwh, for 200 and ) 500 MW respectively, at ) FY % p.a. Rs /ton in FY 1983 ) FY % p.a. FY % p.a. Ramagundam- Based on kg/kwh and ) kg/kwh, for 200 and ) FY FY % p.a. 7.0% p.a. 500 MW respectively, at ) FY1987 Rs /ton in FY 1983 ) Onwards- 6.0% p.a. Farakka - Based on kg/kwh and ) kg/kwh, for 200 and ) 500 MW respectively, at ) Rs /ton in FY 1983 ) Rihand - Based on kg/kwh for ) 500 MW, at Rs /ton ) in FY 1983 ) Vindhyachal- Based on kg/kwh for ) 210 MW, at Rs /ton ) in FY 1983 ) An additional 5% is added to cost for fuel oil needed for starting and for low load operation, plus tax of Rs. 5 per ton. (d) Calorific Value of Coal Singrauli - 4,000 Kcal/kg Korba - 3,500 Kcal/kg Ramagundam - 4,300 Kcal/kg Farakka - 3,200 Kcal/kg Rihand - 4,000 Kcal/kg Vindhyachal- 4,110 Kcal/kg (e) Heat Rate Kcal/kWh Stations 200/210 MW 500 MW Boiler Efficiency Singrauli 2,060 2,027 86% Korba 2,030 2,027 87% Ramagundam 2,030 2,027 87%

104 -98- ANNEX 24 Page 3 of 6 pages Farakka 2,030 2,027 87% Rihand - 2,027 87% Vindhyachal 2,030-87% (f) O&M Expenses Power Station - 2.5% on original cost of 200 MW plant % on original cost of 500 MW plant. Transmission - 0.5% on original cost. (g) Depreciation Power Station - 3.1% of original cost. Transmission - 2.6% of original cost. (h) Tariffs5 NTPC has an obligation to achieve a rate of return of not less than 9.5% on the forecast average net fixed assets in service by FY1991. On this basis, and bearing in mind the time it takes for che generating plant to reach an operating level of 5,500 hours a year, regional average tariffs have been calculated which result in a consolidated average NTPC tariff of 32.2 paise/kwh for FY1983. Regional average tariffs have been progressively increased for each subsequent year to levels resulting in an average NTPC tariff of 43.9 paise/kwh in FY1991 which is sufficient to achieve the required 9.5% rate of return in that year. The regional tariffs include provision for the recovery of operating costs of the proposed project. (i) Fuel Fuel costs are based on prices for all projects as indicated in paragraph 2(c). Variations in fuel costs will be recovered as a tariff fuel surcharge. The projected fuel cost increases are shown separately on the income statements. (j) Project Costs (i) Singrauli Construction costs are based on June 1982 prices escalated at rates given in the schedule below except for orders already placed where escalation is applied from award dates onward.

105 -99- (ii) Korba ANNEX 24 Page 4 of 6 pages Construction costs are based on June 1981 prices escalated at rates given in the schedule below. (iii) Ramagundam Construction costs based on January 1982 prices for Phase I and June 1982 prices for Phase II, escalated at rates given in the schedule below. (iv) Farakka Construction costs are based on December 1981 prices escalated at rates given in the schedule below. (v) Vindhyachal Construction costs are based on April 1982 prices escalated at rates given in the schedule below. (vi) Rihand Construction costs are based on January 1982 prices escalated at rates given in the schedule below. (vii) Escalation Schedule Price Escalation a. 10% per annum for FY 1982 b. 8.5% per annum for FY 1983 c. 8% per annum for FY 1984 d. 7.5% per annum for FY 1985 e. 7% per annum for FY 1986 f. 6% per annum for FY 1987 and onward. The turbo-generators and boilers are, however, subject to the following maximum price escalation from the date of order: Singrauli 200 MW units - 25% Korba, Ramagundam and Farakka W units - 20% 500 MW units for all projects - 15% Turbine Generators 20% Steam Generators

106 -100- ANNEX 24 Page 5 of 6 pages Physical Escalation Civil works - 10% of construction costs Equipment - 5% of the equipment costs (k) Capital Requirements (i) The proposed credit would be relent by the GOI to NTPC for a period of 20 years from the date of withdrawal of the first installment including a five year initial grace period, and repayable in equal semi-annual installments of principal, together with interest at the rate of 12.5% per annum on unpaid balances. (ii) Other capital requirements would be advanced by GOI in the form of debt and fully paid up equity capital, provided that the unpaid debt at the end of each year would not exceed the sum of the issued share capital and the "free" reserves, that is to say, those which are not required for specific purposes. Advances would be in the form of equity capital followed by loan capital. (iii) GOI loans (including the onlending of both the proposed credit and also previously approved credits and loan) are assumed to finance either defined projects or individual generation units and transmission lines included in NTPC's investment program. Interest on the loans up to the date of commissioning of each unit of plant would be charged to construction, while subsequent interest accruals would be charged to revenue. Repayment of principal is assumed in 30 semi-annual installments commencng on the first anniversary following the end of the five year grace period. (1) Working Capital Variations in working capital represent the difference between the sums of the individual items making up current assets less current liabilities at the beginning and at the end of the year. (m) Balance Sheets (Annex 23) Current Assets (i) Receivables are assumed at a level equivalent to one-twelfth of the revenue for the year; (ii) Inventories are assumed at 1% of gross assets at the end of the year; and

107 -101- ANNEX 24 Page 6 of 6 pages (iii) Current liabilities are assumed at a level of one month's fuel cost, plus 4% of the annual operating and maintenance expenses.

108 INDIA NATIONAL THERMA1, POWER CORPORATION LIMITED INCOME STATEMENT COVERING OPERATIONS FY1983 THROUGH FYl995 NORTHERN REGION (Rupees Million) 0-oo0-0-o osoososo == o=osono =o----0~= =0o=0=mooovs-0=oo o ao o -o -o -o=oo0=a=o =o =ooovooo oo==== o=0=oo =0 =0=0 =O=CF:O =0=o =O=Oveos= ooovsoo a Year Ending March 31 FY1983 FY 1984 FY1985 FY1986 FY1987 FY1988 FP3909 FY 1990 FY 1991 FY199 2 Y1993 F71l994 FY ' =0. 0s0'OS : :O - OSODo - Eo= oso 0-0- =o=o 0=o0o0-0o=y S:0= 0= 0==sOOO o=0=o=0=o-- 0- =o= 0=0=o= 0O=O o.=o= o-0.0= C=O=o=o =o.co-o=o-o=o -0.0=0-=0-0.6 Sale of energy (Gwh) Revenue Bulk Supply (P/Kwh) ' , , Oentral excise (p/kwh) e ODeratinc Revenue Sales - Bulk supply sales - fpel Surcharge Cntral Utxcise btal Operatina Revenue 3 24_ Oneratina Ax?e&ses Singraili - Fuel Fuel Surcharge & M Deprecietion Rihand - Fuel Fuel Surcharge & M Depreciation New Projects- Fuel Fuel Surcharge & M Depreciation Transmission- 0 & M Deprecintion Central Excise * 1.8P/unit sent Total Operating xixpenses Operating Income(Before Intereste _ - Less:Interest on Loans DeductsInterest Capitalised Net Interest Chargeable to Operations Profit/(Loss) Write off deferred expenses Net Earnings 41 33j.7t3 ji3 _ Average Rate Base c Rate of Return(fterating lo e5 7,2 9, Income as % of Rate Base) Operating Ratio(Operating , ,0 ;3.4 63, ,6 66,9 Expenses as % ofoperating Revenue) Source: NTHPC November }1982

109 INDIA NATIONAL THERMAL POWER CORPORATION LIMITED INCOMF STATE1MENT COVEBING OPERATIONS FY 1983 THROUGH ry 1995 WESTERN REGION (Rupees Million) =o=0-0=osw0 - O"Oe 00_ =o=oe o=-o. OcOeo= o=o-o=o-oso -O -OsOs 0O.Oco=O= O.Oc O.O= O=Oe OeOe O=O O-O=O- 0o0=0=o=o=0=.O=O=OeO=O=OeOeO=O=O = =O-=O=-.O=O=O 0= e= =oeowo=oeo0= o O-O"O Year Ending March 31 FY1983 FP 1984 FY1985 FY 1986 FY1987 FY FY 1989 FY 1990 FY1991 FY199 2 FY1993 FY 1994 FY 1995 Sale of Energy (Gwh) Revenue - Bulk supply (P/kwh) , Central 3xcise (P/Kwh) Onerating Revenue Sales - Bulk Supply Sales - Fuel Surcharge Central Excise Total Operating Revenue Oneratiln ExNenses Korba - Fuel Fuel Surcharge O & M DepreciFtion Vindhyachal - Fuel Fuel Surcharge &M Depreci6tion Transmission- O & X Depreciation Central Sxcise * 1.8P/unit sent Total Operating Expenses Operating Income Expenses l.rir ~nesre5 LesssInterest on Loans Deduct Interest Capitalised _ - Net Interest Chargeable to Operetions Profit/(Loss) Write of deferred Expenses Net Earnines Average Rate Base Rate of Return(OperFting Income as % of Rate Base) Operating Ratio(Operating 58.5 Expenses as % of Operatirg Revenue) Source: RTPC November 1982

110 INDIA NATIONAL THERMAL POWER CORPORATION LIMITED INCOME STATEMENT COVERING OPERATIONS FY1983 THROUGH FY1995 SOUTHERN REGION (Rupees Mi11ioniY Year Ending March 31 FY1983 FY 1984 Fy1985 Fyr98 6 Py 1987 Fy 1988 FY1989 FY 1990 FY1991 FY 1992 FY1993 FY PY _ CO_OleO_OO=O=OEMO= 0_0 =0_ 0~ =C=OOO.OOO-0ot O0=0l Oc=0=0=0= 0 0= Cs =0=Ooe0.00= 0= Oe= =0 O=0 O= O=O=O=O z O=Oe ==O=OO O = O= =0 O0- OC O==0 --O-Q-O= O- C onoa =C0O=O o_-c~0 Sale of Energy (Gwh) ftvenue - Bulk Supply (P/Kwh) - 43e > Central Excise (P/Kwh) Ooaratina Revenue Sales - Bulk Supply Sales - Fuel Surcharge Central Excise , Total Operatina Revenue _ onergting Xxo-enses Ramagundam - Fuel ruel Surcharge O & M Depreciation New Projects-Puel Fuel Surcharge & M _ Depreciation Transmission-4&M Depreciation B Central Sxcisa * 1.8P/unit sent Tbtal OneratinO Exvenses - 62 Z OperatintXg Income(Before Interest) Less$Interest on Loans DeductsInterest Capitalised Net Interest Chargeable to , operf tionls Profit/(Loss) - (10) C 19) (15) Write Off deferred Expenses Net Earnings - ) (15) Average Rate Base Rate of Return(Operating , Income as % of Rate Base) Operating Ratio(Operating , Expenses as % of Operating Revenue) Source: NTPC Novemher 1982

111 INDIA NATIONAL THERMAL POWER CORPORATION LIMITED INCOME STATEMENT COVERING OPERATIONS FY1983 THROUGH FY1995 EASTERN REGION (Rupees Million) Year Ending March 31 E'Yl1983 py19b4 Fy975 Fyr1 98b Y 1987 ~'Yl py 1 99 FY1 90 FY1991 FY 1992 FYl9 9 3 py1994 py1995 Sales of Energy (Gwh) Revenue - Bulk Sup,ly (P/Kwh) Central Excise (P/Kwh) OPERATING REVENUE Sales - Bulk Supply - _ Sales - Fuel Surcharge - _ Central Excise - _ Total Opeiating Revenue T PEi-ATING EXPE2 SES Farakka - Fuel c Fuel Surcharge _ & M Depreciation Transmission - 0&M Depreciation Central 1'9P/Unit sent - _ Total Operating Expenses - _ Operating Income (Before Interest) T062 Less I Interest on Loans Deduct Interest capitalised Net Interest chargeable to operations Profit/(Loss) - - (5) (82) Write off Deferred Expenses _ Net Earnings _ ) (82) Average Rate Base , Rate of Return (Operating Income as % of rate base) , Operating Ratio (Operating Expenses as % of operating Revenue) Source: NTPC November 1982

112 INDTA CENTRAL POWER TRANSMISSION PROJECT ANDHRA PRADESH STATE ELECTRICITY BOARD INCOME STATEMENT COVERING OPERATTONS FY1980 THROUGH FY1989 (Qunses Mi ilion) Year endiing March 31st FY1980 FY1981 FY1982 FY1983 FY1984 FY1985 FY1986 FY1987 FY1988 FY1989 Total Energy Sales (GWh) 4,770 5,328 6,635 7,382 8,339 9,827 11,922 12,804 13,484 14,580 Average Tariff (Ps/kWh) OPERATING REVENUE Energy Sales 1,628 2,011 2,814 3,396 3,909 4,668 5,722 6,113 6,845 8,087 State Government Subsidies Other Income _ 39 _ TOTAL OPERATING REVENUE 1,752 2,167 2,889 3,433 3,947 4,707 5,762 6,154 6,887 8,130 OPERATING EXPENSES Power Purchases ,137 Fuel ,088 1,148 1,228 1,302 1,580 1,891 Employee Costs ,023 1,302 1,580 1,891 Depreciation Central Excise Duty L Other Operating Expenses TOTAL OPERATING EXPENSES 1,273 1,518 2,]47 2,457 2,837 3,315 3,908 4,408 5,090 6,021 OPERATINC INCOME (Before Interest) ,110 1,392 1,856 1,748 1,797 2,109 Less: Interest on Loans ,115 1,291 Deduct:Interest Capitalized Net Interest Chargeable to Operations _ 946 1,123 NET EARNINGS , Rate of Return (9) 9, Operating Ratio (Operating Expenses as % of Operating Revenue) Source: CEA October 1982

113 TNDIA CENTPAL POWER TRANSMISSION PROJECT ANDHRA PRADESH STATE ELECTRICITY BOARD NET INTERNAL CASH GENERAT1ON FY1980 THROUGH FY1989 Year Ending March 31st FY1980 FY1981 FY1982 FY1983 FY1984 FY1985 FY1986 FY1987 FY1988 PY1989 CAPITAL ASSETS INVESTMENT Capital Investment 1,386 1,364 1,504 1,742 2,171 2,524 2,913 3,166 3,729 4,337 Interest during construction l6r TOTAL 1,509 1,483 1,638 1,855 2,245 2,597 3,017 3,316 3,898 4,505 DEBT SERVICE Interest on Loans ,115 1,291 Deduct: Interest Capitalized l ' Net Interest Chargpahle to Operations ,123 Loan Principal Repayments TOTAL ,009 1,176 1,261 1,394 1,591 INTERNAL CASH GENERATION Operating Income ,110 1,392 1,856 1,748 1,797 2,109 Depreciation b Consumer Contributions Consumer Security Deposits TOTAL l,220 1,429 1,646 1,992 2,527 2,474 2,596 3,040 tt Less: Debt Service ,009 1,176 1,261 1,202 1,581 NET INTERNAL CASH GENERATION ,351 1,213 1,202 1,459 Contribution to Investmcnt Net Cash Generation as 7 of Capital Assets Investment) Source: CEA Octoher 1982

114 INDIA CENTRAL POWER TRANSMISSION PROJECT ANDHRA PRADESH STATE ELECTRICITY BOARD BALANCE SHEET AS AT END OF FY1980 ThROUGH PY1989 (Rupees Million) Year Ending March 31st FY1980 FY1981 FY1982 FY1983 FY1984 FY1985 FY1986 FY1937 FY1988 FY1989 Assets Actual Gross Fixed Assets (Historic Cost) 8,193 9,615 10,525 13,526 15,845 18,229 20,010 22,383 26,183 30,542 Less: Depreciation 1,641 1,898 2,211 2,566 3,002 3,502 4,073 4,699 5,398 6,229 Net Final Assets in Use 6,552 7,717 8,314 10,960 12,843 14,727 15,937 17,684 20,785 24,313 Work-in-Progress 2,210 2,152 2,746 1,487 1,339 _1,479 2,611 3,404 3,333 3,311 Total Net Fixed Assets 8,762 9,869 11,060 12,447 14,182 16,206 18,548 21,088 24,118 27,624 Investments/Intangible Assets Working Capital Total Assets 9,048 10,260 11,261 12,517 14,192 16,216 18,558 21,098 24,128 27,634 Equity and Liabilities L Equity Capital Subventions Consumer Contributions Retained Earnings ,260 1,878 2,867 3,642 4,324 5,142 Total EquitM ,058 1,507 2,150 3,164 3,964 4,671 5,514 Liabilities Long-Term Debt 7,853 8,802 9,364 10,121 11,222 12,468 13,651 15,236 17,394 19,882 Consumer Security Deposits ,015 1,090 Staff Super-Annuation Funds Interest Accrued on State Loans Total Liabilities 8,798 9,844 10,588 11,459 12,685 14,066 15,394 17,134 19,457 22,120 Total Equity and Liabilities 9,048 10,260 11,261 12,517 14,192 16,216 18,558 21,098 24,128 27,634 Debt/Equity Ratio 97/3 95/5 93/7 91/9 88/12 85/15 81/19 79/21 79/21 78/22 Soulrce: CEA October 1982

115 -lo9- ANNEX 32 INDIA CENTRAL POWER TRANSMISSION PROJECT Southern Region: Additional Transmission Requirements 1995 High Hydro Low Hydro High Low High Low 400 kv System Element FOR FOR FOR FOR Line-circuit km Sub-stations-Nos Inter-connecting transformers-mva Line Bays-Nos Line Reactor-MVAR Bus Reactor-MVAR Cost-Rs million

116 -110- ANNEX 33 INDIA CENTRAL POWER TRANSMISSION PROJECT Costs and Benefits of Intra-Regional Transmission Econ. Cost Year of transmission (Rs m.) Outage (GWh) Value (Rs m.) Net (Rs m.) 82/ /P / /86 P / /88, / /14 IRP 13.2% NPV 8% 1,010 10% % 161 IRP (cost+10%) 12.1% IRR (benefit-1o%) 12.0%

117 -111- ANNEX 34 INPIA CENTRAL POWER TRANSMISSION PROJECT Southern/Western transmission link: least-cost solution Year Cost of transmission Alternative new generating capacity (Rs m.) (P.s m.) 82/ / / / ,096 86/P / /8'-2013/ PV 5% 376 5% 4, , , , ,303

118 -112- ANNEX 35 INDIA CENTRAL POWER TRANSMISSION PROJECT Northern/Western DC Link: Least-Cost Solution Year Transmission Cost New generation capacity (500 MW) (Rs m.) (Rs m.) 82/83 7: / / / /87 1Q / / / PV 5% 1,227 2, ,105 2, ,039 1, , ,641

119 -113- ANNEX 36 Page 1 of 2 pages INDIA CENTRAL POWER TRANSMISSION PROJECT APSEB Tariffs Consumer category Tariff (as of Oct 1982) Low voltage Domestic (paise/kwh): up to 100 kwh/mo. 45 above 100 kwh/mo. 50 Commercial (paise/kwh) 90 Industrial (paise/kwh): general 50 cottage ind. 35 Agricultural: energy (paise/kwh) 16 capacity (Rs/HP/mo.) 2.0 (ceiling Rs 10) Public lighting: energy (paise/kwh) - panchayat 42 - municipalities 48

120 -114- ANNEX 36 Page 2 of 2 pages - corporations 50 capacity (Rs/fixture/mo.) 2.0 General Purpose (paise/kwh) 60 High voltage Category I: energy (paise/kwh) 40 fuel surcharge (paise/klh) 2.74 capacity (Rs/kVA/mo.) 25.0 Category IT: energy (paise/kwh) 47 fuel surcharge (paise/kwh) 2.74 capacity (Rs/kVA/mo.) 30.0 Agricultture: energy (paise/kwh) 16 capacity (Rs/HP/rno.) 2.0 Power intensive (minimum 403 kwh/kmta/mo.) 32 fuel surcharge (paise/kwh) 2.74

121 -115- ANNEX 37 Page 1 of 2 pages INDIA CENTRAL POWER TRANSMISSION PROJECT Marginal Cost of Electricity Supply in Andhra Pradesh T Tariff Study estimates (1974/75 prices) I/ 11 kv LT consumers consumers Energy (paise/kwh) Capacity (Rs/kW/mo) - generation and transmission distribution total II Bank estimates (1978/79 prices) 1/ 11 kv 11 kv Average Rural Average Rural Capacity (Rs/kW/mo) Generation Transmission and distribution Total / Before application of diversity and load factor considerations.

122 -lib- ANNEX 37 Page 2 of 2 pages 11 kv 11 kv Average Rural Average Rural Energy (paise/kwh) Dry season peak Dry season off-peak and Wet season peak Wet season off-peak !II Bank estimates (1980/81 prices) Average Domestic Industry Agriculture (sales-weighted) Total cost (paise/kwh) IV Average Incremental Cost (1982 prices) (paise/kwh) / 1/ Purchases from other States and NTPC valued at similar cost as APSEB generation. If purchases were valued at NTPC-s Southern Region AIC, or at hydro rates prevalent in the Southern Region, APSEB's AIC would be in the range of paise/kwh.

123 -117- Annex 38 INDIA CENTRAL POWER TRANSMISSION PROJECT National Thermal Power Corporation Limited Documents Available in the Project File 1. National Grid Development Project, Feasibility Report; National Thermal Power Corporation Ltd., Augt.t India, Long Term Power Plan, Generation Expansion Program ( to ) (5 volumes) Central Electricity Authority, Ministry of Energy (Department of Power), Government of India September NTPC, Sixth Annual Report September 17, 1982

124

125 F7 AFGHANISTAN"- PAKISTAN A' HAA I K. ~~~~~~~~~~,N ~~~~~C H I N A 2 '>7 K U T~ ~ ~ ~ ~~~~~~~~7 6 'C~~~~~~~~~~~~~~~~~~~~~~~~~~~I~Kl IAH ( '~~~(o-~~~ ~~ SKKN: S~~HUTAN / AU 010 p p p ~ t U ~ ~~~~~~~~~~~~~~~~~ ~ ~ 9 6,,A Z A T A ' ~ ~..'-.. ~ ~ ~ ; ~ A 9 Aooog h r~~~~~~~~k -f ~ ~ ~ ~ < ~,FGALA2 ~~~~~~~~~~~~~~~~~~~~~~~~~~~B N L R C, JARA7 MtR_ A, , 'WE,E H4 U ooipjr. C 0< <-- -u ~ ~ ~ ~ ~ ~ ~ B U R MA -27 M -'ARA A VTR A A Ch!rho- J F A! IJ ~ 3' - I N D'1 A POWER ~~ tororsodo ~~TRANSMISSIQN PROJECT 4 roercoodo ICENTRAL Op~~~~~~~~~ 400 kv Grid WA Vruoobod 1 A NJ H 1 -R ~~ A RAyESF], AFAR:~~400k LIs KARKA JAKA% C:dph 400C Sobrooo Noflr -13D0 BoA r oolr-ok >1 H ~~~~~~~0 no'f. Pow-rBobo BorooIro& 37 -< RCol4lI 400W ki.o oiyoro Poooot Booboos-n -- -yd -F.-- ScIon, - -~~~~~~~~~R-o 5d.4 oa AppIr KERALA, N A UJoarr SRI LANKA -!rt