Document of The World Bank FOR OFFICIAL USE ONLY ReportNo. 4293-IN STAFF APPRAISAL REPORT INDIA CENTRAL POWER TRANSMISSION PROJECT April 26, 1983 Regional Projects Department South Asia Regional Office 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. Public Disclosure Authorized Public Disclosure Authorized Public Disclosure Authorized Public Disclosure Authorized
Transcript
Document of
The World Bank
FOR OFFICIAL USE ONLY
Report No. 4293-IN
STAFF APPRAISAL REPORT
INDIA
CENTRAL POWER TRANSMISSION PROJECT
April 26, 1983
Regional Projects DepartmentSouth Asia Regional Office
This document has a restricted distribution and may be used by recipients only in the performance oftheir official duties. Its contents may not otherwise be disclosed without World Bank authorization.
AC - Alternating CurrentAIC - Average Incremental CostAPSEB - Andhra Pradesh State Electricity BoardCIF - Cost Insurance FreightCEA - Central Electricity AuthorityDC - Direct CurrentHT - High tensionHVDC - High Voltage Direct CurrentGOI - Government of IndiaIDA - International Development AssociationKfW - Kreditanstalt fuer WiederaufbauLOLP - Loss of Load ProbabilityLT - Low TensionMPC - Mysore Power CorporationNHPC - National Hydro Power CorporationNTPC - National Thermal Power CorporationOPEC - Organization of Petroleum Exporting CountriesPERT - Program Evaluation and Review TechniquePLCC - Power Line Carrier CommunicationREB - Regional Electricity BoardSEB - State Electricity Board
NTPC's FISCAL YEAR (FY)April i - March 31
l/ The US$/Rs exchange rate is subject to change. Conversions in thisreport have been made at US$l to Rs 9.5, which represents the projectedexchange rate over the disbursement period.
-1i-
FOR OFFICIAL USE ONLY
INDIA
CENTRAL POWER TRANSMISSION PROJECT
STAFF APPAISAL REPORT
Table of Contents
Page No.
I. THE POWER SECTOR ...... ............................ 1Background ...................................................Past Bank Group Involvement in the Sector .................... 2Bank Group's Strategy ......................................... 3Southern Region Demand and Supply ....................... 6
II. THE BENEFICIARY - NATIONAL THERMAL POWER CORPORATION LIMITED . 8Legal Status and Authorities ....... ... ....... *............ 8Organization and Management. ....... . . .... . 9Recruitmnt and Training .......... ........... ............. 10Accounting Organization and Systems . ...... ....... 12Audit ... D*s*@@*v@***@¢¢@@@v........................................ * . . . ..... 12
III. THE PROGRAM AND THE PROJECT ........ ......................... . 14The Program .. . .................... .. ............. 14
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 1982.
This document has a restricted distribution and may be used by recipients only in the performance oftheir official duties. Its contents may not otherwise be disclosed without World Bank authorization.
- Commercial Arrangements for Sale of NTPC Energy . .27
B. ANDHRA PRADESH STATE ELECTRICITY BOARD (APSEB) . .28- Investment Program .. 29- Future Earnings .. 29
- Internal Cash Generation. 29
V. JUSTIFICATION AND ECONOMIC ANALYSIS .. 30General .. 30Method of Analysis .. 30Intra-Regional Lines ....................... 30
Southern/Western Region Intertie . . .32Northern/Western Region HVDC Intertie . . 33Tariffs and Cost of Supply . . .33
VI. SUMMARY OF AGREEMENTS AND RECOMMENDATION ............ 36
ANNEXES
1. Power Sector Loans and Credits ................................ 372. Electricity (Supply) Act 1948 - Proposed Ammendments, October
1982 ........................................................ 383. Rates of Return of SEBs (FY1979 - FY1982) ..................... 434. All-India Sales and Energy Data 1974/75 to 1981/82 ............ 445. Long-term System Expansion Plan ............................... 456. Southern Region Sales and Energy Data 1979/80 - 1981/82 ....... 577. Southern Region: Installed Capacity, Peak Load and Energy
Requirement 1977/78 - 1981/82 ............................... 588. Southern Region Power Supply Restrictions ..................... 599. NTPC - Organizational Structure (Revised) ..................... 6010. NTPC - Manpower as of September 30, 1982 ...................... 6111. NTPC - Recruitment of Trainees ................................ 6212 NTPC - Organizational Structure Corporate Finance .. ........... 63
15. Implementation Schedule ...... ................................. 8616. Estimated Schedule of Disbursements .................. ......... 8717. Schedule of Commissioning of Power Plants and Power Generation
Versus Schedule at Time of Second Ramagundam Appraisal .88
-iii-
Page No.
18. Investment Program for the Period FY1977 through FY1996 ....... 8919. Comparison of Current Cost Estimates with Previous Appraisals 9020. Statement of Plant Capacity, Generation and Sales of Energy 9121. NTPC - Income Statement Covering Operations FY1983 through
FY1995 .9322. NTPC - Sources and Application of Funds for the Period FY1977
through FY1995 .............................................. 9423. NTPC - Balance Sheets FY1977 through FY1995 .... ............... 9524. NTPC - Assumptions for Financial Projections .... .............. 9625. NTPC - Income Statement Covering Operations FY1983 through
FY1995 - Northern Region ..............................---... 102
26. NTPC - Income Statement Covering Operations FY1983 throughFY1995 - Western Region ....................... ... 103
30 APSEB - Net Internal Cash Generation FY1980 through FY1989 .... 10731. APSEB - Balance Sheet as at end of FY1980 through FY1989 ..... 10832. Southern Region - Additional Transmission Requirements 1995 ... 10933. Costs and Benefits of Intra-Regional Transmission ............ . 11034. Southern/Western Transmission Link: Least-Cost Solution 11...... I35. Northern/Western D.C. Link: Least-Cost Solution .............. 11236. APSEB Tariffs ................................................. 11337. Marginal Cost of Electricity Supply in Andhra Pradesh ... ...... 11538. Documents Available in the Project File ....................... 117
MAP
IBRD - 16845R
INDIA
CENTRAL POWER TRANSMISSION PROJECT
I. THE POWER SECTOR
Background
1.01 The development of India's economy and the improvement of itspeople's standard of living depend to a large degree on the development ofthe power sector. Over the last two decades, power demand has grown twice asfast as the economy, and the power sector now takes the largest share ofpublic investment (12% of the Sixth Five-Year Plan outlay). This was due tothe rapid development of power-intensive industry and the expansion of ruralelectrification tor irrigation.
1.02 In spite of an increase in generating capacity from 5,600 MW in1960 to about 32,000 MW in 1982, power shortages have been experienced invarious -arts of the country for a number of years, and gaps between supplyand demand will impose major constraints for some years to come.
1.03 Before 1975, power facilities were planned, constructed andoperated by each State to meet its own needs. Because of the rapid growth ofthle power sector, the Government of India (GOI) decided to create newinstitutional structures in the sector, and to emphasize central planning ofgeneration and high voltage transmission with the ultimate objective ofcentral control through a national grid. The Central Electricity Authority{CFA) performed studies of a national power system, and GOI decidegvtoproceed with the construction of four large centrally-owned thermal powerstations located at coal fields, supplying bulk power to the States throughan interconnected 400 kV transmission system. The construction of thesepower stations (2,000 MW at Singrauli, 2,100 MW at Korba, 2,100 MW atRamagundam, and 600 MW at Farakka) was begun with Bank Group financialassistance. The first phase of the program comprised the first stage of 600MW at each plant, and its associated transmission. In addition, IDA Creditsfor 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 subjectof this report is the extension of NTPCts 400 kV transmission system toincrease the capacity of power transmission from Ramagundam to the Southernpart of the country and to interconnect the Northern, Western and SouthernRegional grids. A Bank loan of US$250.7 million is proposed.
1.04 The energy and power sectors and the problems associated with thelatter have been fully described in the Staff Appraisal Report No. 3608b-IN
-2-
dated November 30, 1981 for the Second Ramagundam Thermal Power Project.1/The following paragraphs deal only with the changes that have occurred sinceor with sector aspects directly related to the proposed project. Updatedinformation in regard to the Indian power sector is provided in Annexes 2 to5.
Past Bank Group Involvement in the Sector
1.05 The Bank has made thirteen loans for Indian power projects amountingto US$982.5 million, and fifteen IDA credits totalling US$2,096.0 million(Annex 1). Fifteen projects financed under the following loans and creditshave been completed: ten generating projects, the Beas Project (Credit89-IN), the first three transmission projects (Loan 416-IN, Credits 242-INand 377-IN) and the First Rural Electrification Project (Credit 572-IN). TheFourth Transmission Project (Credit 604-IN) is expected to be completed inthe first half of 1983. The Third Trombay Thermal Power Project (Loan1549-IN), Singrauli (Credit 685-IN), Korba (Credit 793-IN), and Ramagundam(Credit 874-IN and Loan 1648-IN) Thermal Power Projects, and the Second RuralElectrification Project (Credit 911-IN) are in an advanced stage ofimplementation. The credit for the Second Singrauli Thermal Project (Credit1027-IN) and the credit/loan for the first stage of the Farakka Thermal PowerProject (Credit 1053-IN and Loan 1887-IN) were approved in May and June 1980.Korba II (Credit 1172-IN) was approved in July 1981, Ramagundam II (Loan2076-IN) in December 1981 and the Third Rural Electrification Project (Loan2165-IN) in June 1982. The Trombay and Second Rural Electrification Projectsare on schedule. The three 200 MW units of the Singrauli Project and thefirst 200 MW unit of the Korba Project were commissioned on schedule. TheFarakka and Ramagundam Projects are proceeding satisfactorily after initialdelays.
1.06 A Project Performance Audit Report on the Second Power TransmissionProject (Credit 242-IN), issued on June 3, 1980, stated that the project hadbeen successful in assisting nine State Electricity Boards in extending theirtransmission systems to help meet their growing requirements. Utilizationof generating capacity in the nine SEBs exceeded the appraisal forecast.Institutional objectives mainly concerned the rehabilitation of the financesof the SEBs, and while the results achieved by project completion weremodest, improvement was continued by the Third and Fourth Power TransmissionProjects (Credits 377-IN and 604-IN). In FY 1980, seven of the nineparticipating SEBs reached their target rate of return of 9.5%. Theconclusions of the Report pointed to: (a) the difficulty for the Bank Groupin adequately supervising work other than procurement on the project, since
1/ Second Ramagundam Thermal Power Project Staff Appraisal Report (ReportNo. 3608b-IN) paragraphs 1.04 to 1.12 and 1.17 to 1.35.
-3-
it consisted of many sub-projects scattered all over India, and (b) theabsence of a close working relationship between the Bank Group and thebeneficiary SEBs, which made efforts for institutional improvementsdifficult. The Report suggested that more direct involvement with the SEBsin 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 tocooperate with GOI in finding solutions to the many difficult and politicallysensitive problems confronting the Indian electricity supply industry. TheBank's main objectives in the sector are:
(a) to eliminate power shortages by the installation of generationand transmis3ion capacity, and the promotion of measures toimprove the operation and maintenance of existing plant;
(b) to introduce long-range system planning on anationwide 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 institutionsin the sector, particularly the State ElectricityBoards.
1.08 The States, through their Electricity Boards, develop and operatemost power facilities. Under the Constitution, power supply is a concurrentsubject, which means that responsibility is shared between the CentralGovernment and the State Governments, requiring full agreement between thembefore action can be taken. Despite many difficulties, improvements achievedso far have been encouraging. With the establishment of Regional ElectricityBoards (REBs), the National Thermal Power Corporation (NTPC) and the NationalHydro Power Corporation (NHPC), important steps towards an improvedorganizational structuy'e of the power sector have been made. CEA wasreorganized and its powers enlarged; amendments in the financial provisionsof the Electricity (Supply) Act clarified the requirements to be followed intariff setting, the financial performance of SEBs improved, the majority ofSEBs have completed tariff studies based on marginal cost pricing principles,CEA has prepared a national long-term power development plan, and theimplementation of increased investments in the sector will help eliminate thepower deficit.
1.09 Because of the rapid expansion of the power industry, all aspects ofthe sector needed to be reviewed and solutions found for its variousproblems. GOI established in 1978 the Committee on Power, which submitted
-4-
its conclusions to GOI in September 1980. They refer to all major aspects ofthe power sector including planning, project formulation and implementation;operation and maintenance; organization and management; finance, financialmanagement and tariffs; rural electrification; and research and development.The recommendations of the Committee on Power, most of which are satisfactoryin light of the Bank Group's strategy, form a basis for improvement of allthose aspects of the power sector. Implementation of the Committee'srecommendations has already started with those aspects that do not requireGOI's formal approval, such as better planning procedures and improvedoperating and maintenance management.
1.10 In accordance with undertakings agreed during negotiations for theSecond Korba Thermal Power Project, GOI submitted, in May 1982, a program forthe implementation of five categories of power sector improvements which theBank Group considered areas of high priority. Satisfactory progress has beenmade in these five areas for which some of the more recent activities andachievements 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 allthermal power plants with 100/120 MW and 200/210 MW generating units in thecountry to diagnose technical and operational problems, propose solutions,and assign responsibilities for their implementation. Repeat visits areplanned to assess progress.
(b) Coordination of Power Development and Growth in Other Sectors
The Bank Group received the draft national long-range plan for powerdevelopment in September 1982. This plan provides forecasts of power demandthrough the year 2000 and projects the generating capacity and equipment thatwill be required to meet this demand. The draft plan, which is expected tobe finally adopted by the Government, will provide the basis for bothfive-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 ofwhich will be proposed for Bank Group financing and others for bilateralassistance. 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 Indravatiproject, the first hydro-power project in India to be proposed for Bank Groupfinancing, is presently being appraised. In addition, GOI is planning tobegin investigations on what is expected to be the largest hydro-powerproject in the world -- the 15,000 MW Dihang project in north-eastern India,where a number of other projects are also under consideration.
-5-
(d) Strengthening the Role of the Central Sector in Power Generation andInter-state High-Voltage Transmission
(i) GOI, through NTPC, has under construction and partly inoperation over 9,000 MW of power generating capacity. Inaddition to the four ongoing Bank-Group financed super-thermalplants (Singrauli, Korba, Ramagundam and Farakka), which (exceptfor Farakka) are now in their second phases of construction, twolarge thermal power plants -- the 1000 MW plant at Rihand (UP)and the 1260 MW plant at Vindhyachal (MP) -- are also beingundertaken by NTPC. Agreements with the UK and USSR,respectively, for the financing of these plants were signed in1982 (para 4.10).
(ii) The proposed project is designed to reinforce the Centrally-owned NTPC power transmission grid, and provides the first stageof integration of the Northern, Western, and Southern regionalgrids, taking into account compatability for eventual energypooling.
(e) Establishment of Financial Objectives and Policies for theirImplementation, Principles for Evolving Rational Tariff Policies andImprovements in Management Information and Accounting Systems forState Electricity Boards.
(i) Draft legislation for amendment of the financial provisions ofthe Electricity (Supply) Act, 1948 has been prepared by GOI forsubmission to Cabinet at the next session of Parliament, earlyin 1983. These amendments will remove some of the anomalies inthe Act which have been in the past the source of a number ofproblems relating to the financial performance of the SEBs(Annex 2).
(ii) Management consultants have started the review of presentaccounting practices in two of the SEBs with the ultimateobjective of developing a uniform system of commercialaccounting for adoption by all of the SEBs. Their review willbe followed by preparation of a draft accounting manual bySeptember 1983 which will form the basis of the new accountingsystem scheduled for introduction in 1984. An accounting unitis at present being established within CEA to monitor thedevelopment of the new accounting system and the financialperformance of the SEBs.
(iii) With the Third Rural Electrification Project, approved in June1982, new financial performance criteria for the SEBs wereintroduced. These are designed to provide for reasonable
-6-
contributions by the SEBs to power investment, and to graduallyreduce State Government subsidies for rural electrifica;4ionlosses.
Southern Region Demand and Supply
1.11 Data concerning the all-India power demand and supply situation andoutlook are provided in Annex 4. The following paragraphs of this chapterdeal with the demand and supply situation of the Southern Region where theproposed project is located. The major authorities supplying the SouthernRegion are the Tamil Nadu, Andhra Pradesh, Karnataka and Kerala StateElectricity Boards, and the Mysore Power Corporation (MPC). In addition, anumber of small municipalities are engaged in power supply. All entities,except MPC, supply electricity to final consumers, but only the four SEBs andMPC own generation facilities. MPC supplies about 85% of the power madeavailable to consumers by the Karnataka SEB.
1.12 The Southern Region is the only fully integrated electricity supplyregion in India, controlled by a Regional Load Dispatch Center at Bangalore.Load frequency control equipment at Bangalore is now operational. The largehydro component in the system allows energy to be transferred during themonsoon from SEBs with a reservoir-spilling surplus to others in the Region,while in the early summer months thermal generation is maximized to husbandscarce water. In addition to its internal integration, the Region oftenoperates in parallel with the Western Region, particularly the States ofMaharashtra and Gujarat, and with Orissa in the Eastern Region.
1.13 In line with the national pattern, Regional consumption is heavilyoriented towards industry: about 61% of total consumption in the Region isattributable to industrial consumers, and about 18% to agriculturalconsumers. This pattern masks significant differences among States. Theshare of agricultural consumption in Tamil Nadu is about 27%, while 70-75% ofKarnataka's and Kerala's supplies go to industry and only 5-8% toagriculture. Tamil Nadu is the dominant State in the Region with about 40%of the total consumption of electricity. Sales in the Region have beengrowing at a steady rate of about 7% p.a. between 1970 and 1980, most ofthis in periods of supply restrictions. Generation and sales growth in1979/80 was a minimal 2% largely due to widespread supply difficulties andlow reservoir levels, followed by a return to normal growth in 1980/81 (Annex6).
1.14 Andhra Pradesh is the only State in the Region that has more than 50%thermal capacity; Kerala and Karnataka are solely hydro. While installedcapacity has grown at about 7% p.a. between 1970 and 1980, actually availablecapacity at peak showed a growth rate of about 7.5%, resulting in asignificant improvement in availability from about 65% to more than 70%. Asenergy consumption has been increasing at an annual rate of 7% the systemload factor decreased to about 57% in 1980, from more than 60% in the early
-7-
1970s, making the system peak more pronounced. In recent years, developmenthas been erratic. Installed capacity has been increasing at about 7% p.a.,but peak availability declined to just slightly above 60% of installedcapacity. Forced outages have suppressed the growth of peak demand,increasing the system load factor to more than 70% (Annex 7). As in previousyears, severe supply restrictions were imposed mainly in Karnataka andKerala, especially on industrial consumers in 1981/82, ranging from 10% to50% of potential demand or connected load (Annex 8).
1.15 Potential unconstrained peak capacity demand in the Region isexpected 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 insubsequent years are expected to increase supply reliability almostimmediately. The expected loss of load probability during the 1980s isreasonably low, even with high forced outage rates. Much depends on timelyapproval and implementation of generation projects, and the provision ofappropriate transmission capacity (Annex 5).
-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 1975and is registered under the Companies Act, 1956. It is a company whollyowned by GOI and functions under the general supervision cf the Ministry ofEnergy. Its initial authorized share capital of Rs 1,250 million (US$132million) was increased to Rs 8,000 million (US$842 million) in June 1980 andRs 15,000 million (US$1,579 million) in September 1981. The paid-up capitalof the Corporation on Septeber 30, 1982 was Rs 10,047 million. TheCorporation has a Board of ten Directors including the Chairman and ManagingDirector.
2.02 Under its Memorandum and Articles of Association, NTPC has broadpowers to carry out its work. However, the tariffs to be applied as well asany changes in such tariffs, its investment plans and annual capital budgets,have to be approved by the Government. NTPC is also subject to periodicexamination by the Committee on Public Undertakings--a body established byGOI to monitor the performance of public sector enterprises.
2.03 The main objectives for which the Corporation was established are:
(i) to design, construct, and operate large central thermalpower 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 ofthe EHV (extra high voltage) transmission system being established by theCentral Government to develop effective interconnected regional systems forultimate integration into a national grid. NTPC will own and operate this400 kV transmission system, over which power will be distributed from eachplant and sold in bulk to SEBs, as well as the inter and intra-regional linksbeing established under this project. Later these systems will be part ofthe 400 kV interconnected regional systems which, subsequently, is intendedto be integrated into the national grid.
2.04 NTPC's present program provides for the construction of six thermalpower stations (Singrauli, Korba, Ramagundam, Farakka, Rihand andVindhyachal). It is also possible that NTPC might ultimately take overownership of the 720 MW Badarpur station near Delhi, which is at presentbeing managed by NTPC on a management-fee basis. NTPC has also undertakeninvestigations for identifying additional sites for thermal power stations inthe Central sector. Based on these studies, feasibility reports submitted byNTPC for pithead developments at Kahalgaon (Bihar), Talcher (Orissa) andPench (Madhya Pradesh) are under consideration by COI. Feasibility studiesfor other sites, i.e., a Capital Region project near Delhi, Birbhum (WestBengal) and Mangur (Andhra Pradesh) are under formulation. The totalcombined capacity to be installed at these sites in the first instance is
-9-
likely to be about 4,000 MW while the ultimate potential is estimated to benearly 10,000 MW.
Organization and Management
2.05 NTPC has entered the operational phase of its development with thecommissioning of the first three generating units constructed by NTPC. Themost recently installed 210 MW unit at the Badarpur Thermal Power Stationnear Delhi was synchronized in December 1981 while the first two 200 MW unitsat Singrauli were commissioned in February 1982 and November 1982respectively.
2.06 JIi7PC's organization has so far been construction oriented to cater tothe predominant activity of construction work on the large power plants. Arevised corporate organization structure (Annex 9) has now been designedkeeping in view the beginning of the operations phase of the power plants andthe 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. Thefirst tier consisted of the corporate functions of Planning and Marketing,Personnel and Finance which were entrusted with normal corporate levelresponsibilities. The second tier consisting of other services relevant tothe construction phase of the projects such as Technical Services, Contractand Procurement Services, Quality Control, Expediting and Project ManagementServices were centralized as service functions and located at headquarters.The third tier, which embraced direct project activities, consisted of aproject organization for each of the four power plants which were underconstruction. Each project organization was headed by a General Managerentrusted with total responsibility for implementation of all aspects of theproject's construction program. Under this structure, the heads of thecorporate and service functions departments, as well as heads of projectorganizations, reported to the Chairman and Managing Director. This, withaccent on centralization at the corporate level, had some major advantageswhich undoubtedly served the organization well during the formative years.
2.08 However, with the recent addition of the Rihand and Vindhyachalprojects and the advent of the operational phase of both generation andtransmission, there has been a significant increase in the task before NTPCin terms of volume, dimension and complexity. The increased scale ofactivities, as well as the geographically dispersed nature of operations,brought into focus the need for greater decentralization. In consultationwith the Central Electricity Generating Board of U.K., an organizationalstudy was undertaken. As a result of this study, and in-house efforts, arevised organization structure was developed. The proposals formulated inthis regard have now been considered and approved by the Board of Directorsof the Corporation.
-10-
2.09 Under the new organizational structure (Annex 9), regional groupsheaded by Executive Directors have been formed with total responsibility forplanning, design, procurement, construction, commissioning, operations andmaintenance for thermal power stations and associated transmission facilitiesin each region. These activities will be carried out within the framework ofoverall guidelines laid down by the corporate headquarters. Teams for each
project have also been constituted at the regional level consisting of groupsfor planning, engineering, contracts and expediting and will be headed bysenior level officers. This will enable greater accountability of thetechnical support functions to the project organizations. At present theregional headquarters are functioning from Delhi. However, at an appropriatetime they will be shifted to suitable locations within the boundaries of therespective regions. The organizational set-up at project sites remains thesame as before.
2.10 Under the new set-up the role of the corporate center will be one ofpolicy making and providing functional guidance to the regional and projectorganizations. In addition to the corporate functions of Finance, Personneland 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 uniformimplementation of policies and corporate guidelines, various groups anddepartments at the regional and project levels will be functionallyresponsible to the corresponding staff departments at the Corporate Center.
2.11 The decentralized organizational structure should contributesignificantly to the effective management of the expanding Corporationthrough providing for a greater delegation of responsibility and authorityand through establishing accountability and measurement of performance onregional and sub-regional levels.
Recruitment and Training
2.12 NTPC is a young organization which is growing rapidly to meet thedemands of its large construction program. The next phase of expansion wil1involve the need to recruit and train operating staff. When all currentdevelopments have been completed and commissioned, NTPC will have a staff ofabout 21,000. The importance, therefore, of implementing training programsfor the various skills required during the construction and operationalphases cannot be too highly stressed. Manpower by category of staff atSeptember 30, 1982 and additional recruitment required to meet projectedrequirements by FY1990 are provided in Annex 10. NTPC's present manpowerrepresents 43% of its FY1990 requirement (48% for executives, 50% forSupervisors, and 37% for skilled and unskilled staff). These figures showthat recruitment is progressing at a sufficiently satisfactory level to meetoperational needs as plant completions progress and commercial operationsexpand.
-11-
2.13 NTPC has placed special emphasis on the importance of training in itsorganizational development, and programs are being developed by theCorporation which will be backed by 200 MW and 500 MW simulators, financedfrom the proceeds of Credits 793-IN and 1053-IN, as well as other modernfacilities for instructing and training the operating staff. Well plannedand well structured training programs have been developed for all categoriesof staff. The program is being effectively executed and is modified andimproved on a continuing basis in light of actual experience. Traineerecruitment, by category of staff, to date and projected requirements toFY1990 are set forth in Annex 11. Actual trainee recruitment to date as apercentage of projected requirements by FY1990 is 19% (executives 34%,Supervisors 18%, and skilled workers 9%).
2.14 Training programs which previously have concentrated onpre-operational activities such as Planning, Design and ConstructionManagement, are now aimed more at operations. Some of the current major
activities are:
(a) Training in professional engineering for executivetrainees.
(b) Training in professional engineering for supervisorytrainees.
(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 managerialstaff on the accounting systems and procedures beingimplemented.
Mainly engineering graduates (mechanical, electrical, civil) are beingrecruited and inducted into a one-year training program. The first group of35 young executive trainees was recruited in February 1977. Since then sixmore groups consisting of 831 trainees have been recruited, the last of which(150 trainees) was recruited in September 1982. The training programs havebeen 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 experiencedengineers and managers selected throughout the country. NTPC is alsoutilizing the facilities of the Central Electricity Generating Board (U.K.)for training of operation and maintenance staff.
2.15 The first two 200 MW generating unit (at Singrauli), which commencedoperation in February and November, 1982 respectively, have been adequately
-12-
staffed. Advance action has been taken for the requirement of subsequentunits for which 146 executives and 119 supervisors are in postion. NTPC hasfinalized comprehensive plans for training operational staff, particularlythe non-supervisory staff in the various technical and non-technical trades,and to provide foremen for the 200 MW units at Singrauli and Korba. Themanpower for these is being drawn from experienced staff as well as fromfresh recruitment. The personnel required for the first 200 MW unit at Korbaare already in position. Recruitment of operational manpower has alsocommenced for the subsequent units at Korba and Ramagundam. Key personnelrequired for the associated transmission systems, together with adequatesupport staff, are in position.
2.16 On-the-job training has high priority. The methodology includesclassroom lectures, participation in group exercises and discussionssupported 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 andimplementation of its finance and accounting organization (Annex 12) and inthe design and implementation of accounting systems and procedures. Thedesign of accounting systems for both the construction and operational phasesof NTPC's activities has been completed. Implementation of systems for theconstruction phase has been completed both at the corporate center atheadquarters, and also at the sites, while systems for the operational phasehave been designed and are being implemented at Singrauli. Consultants arebeing utilized for the on-going implementation of systems. To familiarizestaff with the systems and procedures, training courses are being conductedby the consultants in conjuction with staff members from NTPC's CorporateCenter.
Audit
2.18 The audit of NTPC's accounts and records is undertaken by aprofessional auditor appointed by the Company Law Audit Board, on therecommendation of the Comptroller and Auditor General of India. The auditoris normally a member of the Indian Institute of Chartered Accountants, andhis audit report on NTPC's financial statements is subject to comment by theAuditor General. For the audit of the accounts for FYs 1980, 1981 and 1982two auditors were appointed, Messrs.Raghu Nath Rai and Company and Messrs.Prasad Azad and Company, both firms of Indian Chartered Accountants. Therewere no adverse comments from the auditors on the accounts of each respectiveyear and the audits were satisfactory to the Bank. It should be borne inmind that NTPC's activities covered only project construction until FY 1982when power was sold for the first time. NTPC has already undertaken inconnection with previous credits and loans to furnish to the Bank Groupaudited financial statements within seven months of the end of the fiscal
-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. Thisundertaking has been reconfirmed during negotiations for the proposed Loan.
-14-
III. THE PROGRAM AND THE PROJECT
The Program
3.01 NTPC's development program, previously consisting of four centralpower stations with associated 400 kV transmission (Singrauli, Korba,Ramagundam and Farakka), has recently been expanded to include two additionalpower stations, Vindhyachal and Rihand, as well as the proposed Fifth PowerTransmission Project. All power plants are situated at coal fields as theresulting reduced coal transport costs far outweigh the increased costs ofpower transmission. The Vindhyachal Project will be located near Waidhan inMadhya Pradesh with an initial capacity of 1,260 MW and ultimate envisagedcapacity of 2,260 MW, while the Rihand Project will be located near Bijpurin Uttar Pradesh with an initial capacity of 1,000 MW and an ultimatecapacity of 3,000 MW. With the addition of these two new projects NTPC'sapproved current development program, which is compatible with the India LongTerm 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 Ramagundamthermal power plant (2,100 MW final capacity) to the southern partof the country;
(ii) a strong power transmission tie between the predominantlyhydro-based Southern Regional grid and the predominantlythermal-based Western Regional grid; and
(iii) an asychronous inter-tie between the Northern and the WesternRegional grids which would permit larger power transfers to meetthe growing system needs in the context of the present stage ofsystem operation, control and communication facilities while alsoensuring the stability of the systems. K
3.03 The Project would include: about 550 km of 400 kV double-circuitlines, and 560 km of 400 kV single-circuit lines; the construction orextension of a number of related 400/220 kV substations; a back-to-back highvoltage direct current (HVDC) substation at the future Vindhyachal thermalpower plant as part of the 400 kV asynchronous link between the Singrauli andKorba thermal power stations; technical services for the carrying out ofdetailed equipment and system engineering and supervision duringconstruction, for the HVDC back-to-back line at Vindhyachal; and, metering,instrumentation and communication facilities. The proposed project alsoprovides power line carrier communication (PLCC) equipment for speechtransmission, line protection and data transmission on each 400 kV line.
3.04 The Central Power Transmission Project, which is described in detailin Annex 13, provides for the construction of the following 400 kV lines and400/220 kV substations (see attached map):
-15-
(a) Lines Approximate length
Ramagundam - Mangur, double circuit line 230 kmMangur - Vijayawada, double circuit line 160 kmVijayawada - Nellore, single circuit line 305 kmNellore - Red Hills, single circuit line 245 kmSingrauli - Vindhyachal, single circuit line 14 kmRamagundam - Chandrapur, double circuit line 158 km
(b) Substations
Ramagundam - extension for the 400 kV Ramagundam -Chandrapur line and for the second 400 kV
Ramagundam - Mangur circuit (the equipmentfor the first circuit is provided under theSecond 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 lineChandrapur - extension for the 400 kV Ramagundam - Chandrapur
lineSingrauli - extension for the 400 kV Singrauli - Vindhyachal
lineVindhyachal- extension for the 400 kV Singrauli - Vindhyachal
line and a 500 MW twin modula (two 250 MW) HVDCback-to-back inter-tie linking the Singrauli andKorba thermal power plants.
Estimated Cost
3.05 The estimated cost of the Project, excluding interest duringconstruction, duties and taxes, and front-end fee is Rs 4,750 million US$500million) Based on the experience with similar projects in India, the directand 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$307million). The estimated costs of the Project are set out in Annex 14 andsummarized in Table 3.1 below:
-16-
Table 3.1: ESTIMATED COST
Local Foreign Total Local Foreign Total------- Rs Million ------- US$ Million ----
Total FinancingRequired 4,024.00 1,840.31 5,864.31 423.58 193.70 617.28
3.06 The estimates for the main items of equipment and materials are basedon the quotations received since 1980 for similar projects, such as the 400kV links and substations associated with the Singrauli, Korba, Ramagundam andFarakka power plants, with prices updated to mid-1982 levels. It has beenassumed that the foreign cost would represent the following percentages of
-17-
the total cost: 100% of the cost of equipment for the HIIVDC substation, themetering and instrumentation and the communication equipment; 80% of the costof steel in the towers for 400 kV lines; 50% of the cost of insulators andhardware; 36% of the cost of conductors and 20% of the cost of 400/220 kVtransformers. The rest of the substation equipment is assumed to contain nosignificant foreign components with the exception of the 50 MVar shuntreactors for which the estimated cif price has been considered as foreigncost. Inland freight and insurance is calculated at 4% of ex-works priceplus excise duty (8% of ex-factory component) for local supply, and 4% of cifcost plus custom duty plus landing charges on imported equipment. Customsduties 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 theex-works cost. Erection is estimated at 8% of the electrical equipment cost.
3.07 Physical contingencies of 10% on construction costs and 5% on theequipment costs have been allowed to provide for unforseen factors. Inassessing price contingencies, it has been assumed that contracts will eitherbe on a fixed price basis or with ceiling on price inflation as was the casein the past with some of NTPC's contracts. Costs for equipment and erectionhave 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 theproject cost (excluding duties and taxes and interest during construction andincluding the capitalized front-end fee), would be applied to the cif and/orex-factory prices of equipment and materials, and to the cost of consultants'services. The credit would cover all the foreign exchange costs and about18% of the local costs. GOI would provide the balance of the funds requiredin the form of loan and equity share capital.
Engineering
3.09 The 400 kV transmission system, being implemented by NTPC under theirthermal power projects and by the SEBs under the power transmission projects,has been based on the recommendation of CEA, and has been included in theLong Term Power Plan as part of the least-cost transmission component of thatplan. CEA had employed under the Fourth Power Transmission Project (Credit604-IN) consultants (Teshmont of Canada) for system planning. Theirrecommendations in 1977 have been continuously updated by CEA based onin-house studies to reflect changing system conditions. The major elementsof the 400 kV transmission design and construction have been standardized forall India and form the basis for detailed design of the lines.
3.10 NTPC has also carried out comprehensive engineering studies onover-voltage and stability problems to establish equipment parameters for thesystems implemented by them. As the digital model used in the studies is
-18-
limited in the representation of various non-linearities, over-voltagestudies are being taken up through the transient network analyzer techniquealso. These studies are being financed under the Second Korba Thermal PowerProject (Credit 1172-IN).
3.11 The proposed project consists of inter-regional links using both HVDCand 400 kV AC, as well as 400 kV AC intra-regional links. These have beenestablished by CEA on the basis of system studies aiming at evolving a powertransmission system based on requirements to the end of the decade. CEA,with the assistance of consultants, is extending these studies to 1995. Thebroad scope of these studies (not part of the project) includes:
- expansion of the 400 kV system with an overlay of higher ACvoltage (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.
3.12 As part of the proposed project, NITPC will undertake, with theassistance of consultants, detailed equipment and system engineering andsupervision during construction for the back-to-back HVDC link atVindhyachal. These technical services would require an input of about 190man-months of consultancy at an average rate of about US$13,000 per man-monthincluding salary, fees, international travel and subsistence.
Construction and Procurement
3.13 The Project involves construction of 400 kV transmission lines anderection of substations and high voltage D.C. terminal equipment for theback-to-back link. NTPC has been constructing through contractors 400 kVlines and substations effectively over the last few years under each of itsthermal power projects financed by the Bank Group. The same arrangement forconstruction of the lines and substations is proposed to be followed for thisproject too. W4hile NTPC would procure through international competitivebidding the conductors, line material such as insulators and hardware and theelectrical equipment including metering and instrumentation, for a totalamount of about US$145 million, separate contracts for supply and erectionof towers, stringing of conductors, design of structures, civil works andcommissioning of lines and substations, totalling about US$140 million, wouldbe entrusted to contractors based on local competitive bidding. The highvoltage DC back-to-back link, estimated at about US$118.5 million is atechnology being introduced for the first time in the Indian power sector andtherefore, the contract for the supply of equipment, would include adequateprovision for supervision of erection and commissioning. The engineeringof the link would be handled by competent consultants (see para. 3.12).
-19-
3.14 The project construction implementation schedule is shown in Annex15. Project completion is expected by March 1988.
3.15 Procurement of equipment and materials in an amount of about US$240million to be financed from the proposed credit would be on the basis ofinternational competitive bidding in accordance with the Association'sguidelines. Documents for individual contracts above US$2,500,000 equivalentwould be subject to prior review by the Association. Bidding documents forsuch equipment, and tender analyses and recommendations for award ofcontracts, would be prepared by NTPC, where necessary with the assistance ofits consultants, and approved by the Bank Group. The contracts could includecivil works in certain cases where these cannot be disassociated from theequipment contract, as for instance, the substation structure. Localmanufacturers would be expected to bid for almost all categories of equipmentand materials. A domestic preference of 15% or the import duty, whichever isless, would be applied in bid comparison for equipment and materialcontracts. To prevent administrative procurement delays, in cases where thelowest evaluated bidder is a foreign manufacturer, GOI agreed duringnegotiations 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 engineeringand supervision during construction for the HVDC back-to-back substation atVindhyachal (para. 3.12) and against the cost of equipment and materials tobe financed from the proposed credit, on the following basis:
(a) 100% of the ex-factory cost of equipment and materials procuredin India subject to international competitive bidding; and
(b) 100% of the foreign cost of equipment and materials procuredabroad.
Estimated disbursements as provided in Annex 16, have been determined by NTPdand relate to the project implementation schedule (Annex 15). Although theperiod of disbursements (5-1/2 years) corresponds to that of the Bankdisbursements profile, the proportionate disbursements by semester differsomewhat to reflect NTPC's experience in implementation of transmissioncomponents of other projects for which their disbursement estimates haveproven reasonably accurate.
Ecology
3.17 No ecological problems are expected. Conductor sizes and spacingwill be designed to keep energy losses and radio interference withinacceptable limits. Since one 400 kV circuit is equivalent to approximately
-20-
three and a half 220 kV circuits, the amount of right of way is greatlyreduced and the appearance improved. The substations will be provided with afire fighting system which will conform to fire insurance regulations ofIndia and will be equipped with both AC and Diesel-driven pumps. Anautomatic heat-actuated emulsifying system is proposed for transformers.
Project Risks
3.18 The principal risk is the possibility of slippage which could giverise to delayed commissioning of the power transmission facilities. Suchpossible slippage would normally have no negative impact on the continuity ofelectricity supply, but would result in delay of the economic benefits ofsystem interconnection. To ensure effective coordination of the differentactivities during project implementation, NTPC will use PERT charts, whichnot only schedule the various physical activities but also indicate thephasing and quantum of inputs such as financial resources, manpower ofdifferent types, scarce materials, etc. In view of NTPC's previousexperience with transmission construction, it is expected that the risk ofslippage will be kept to a minimum through careful coordination andsupervision during construction, careful attention when placing contracts,and to the capability of manufacturers to meet the delivery schedule.
3.19 Other risk areas are in engineering design, equipment quality andcost overruns. These risks have been carefully assessed and the followingsafeguards taken:
(a) NTPC will be assisted by consultants in those areas where it hasnot sufficient experience, which should minimize problems dueto error at the engineering and design stages; and
(b) project costs are based on similar works currently in progressin India; provision has been made for cost escalation and thereshould be little risk of any substantial cost overrun.
3.20 There is also risk of damage due to fire, explosion, etc, which iscovered by insurance provided by the respective contractors during theconstruction stage and by GOI through its self-insurance policy aftercommissioning.
-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 whichoriginally provided for the constrtuction of four large thermal power stationswith an aggregSate capacity of 7,300 P. together with about 6,000 circuitkilometers of associated 400 kV transmission lines, estimated to cost aboutRs 4l1,i00 million (US84,767 million), However, because of rescheduling andexpansio;,i of the construction program, the investment program has beensubjeet ro conitinuous review over the past six years, with appropriaterevisions being made during appraisal of the previous projects. Revisionswere made during appraisal of the proposed project to reflect (i) increase inthe expected base costs of equipment; (ii) increase in price contingencyfactors attributable to higher projected inflation rates; (iii) reschedulingof generating plant commissioning dates; (iv) provision for projects not yetidentified (3,000 MW), extending the investment program from FY1991 toFY1996; and (v) inclusion of the proposed project.
4.02 NTPC's currently revised investment program is set out in Annexes 18and 19 and indicates capital expenditure of Rs 159,162 million (US$16,754aill-on) over the twenty-year period FY 1977 to FY 1996, reflecting anincrease of 138% (Rs 92,295 million, US$9,715 million) over the investmentprogram as previous"ly revised during the Second Ramagundam appraisal (FY 1977to FY 1991). The increase in generating capacity and transmission facilitiesaccounts for about Rs 79,500 million (US$8,370 million) or 86% of the costincrease. The remaining 14% of the increase in the investment program is dueto increased costs for station and transmission facilities at Singrauli,Korba, Ramagundam and Farakka (Annex 19), largely attributable to (a) priceescalation 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 fromchanges in the exchange rate applied, and (d) increase in price contingenciesresulting from application of revised inflation factors. Financialstatements showing both past performance and future forecasts of NTPC'sconsolidated operations are provided in Annexes 21 through 23. Assumptionsupon which the forecasts are based are provided in Annex 24.
Future Earnings
4.03 NTPC commenced commercial operations in February 1982 when its first200 MW generating unit at Singrauli was commissioned. The growth of powergeneration and unit sales resulting from plant commissioning (Annex 17), andthe subsequent stabilization of generation, for the ensuing thirteen- yearperiod to FY 1995, is set forth in Annex 20. NTPC's projected earnings arebased on the assumption that NTPC will supply bulk power at 400 kV to StateElectricity Boards at regional tariff levels sufficient to enable it to earn
-22-
a 9.5% return on the historic value 1/ of average net fixed assets inoperation from FY199l when NTPC's sales volume is estimated to reach about83% of the maximum output of the four power projects Singrauli, Korba,Ramagundam and Farakka. Between FYs1984 and FY1990 NTPC should achieve aminimum rate of return of 8%. This return is heavily influenced by the pointin time within any given year of commissioning of assets and the assumptionof stabilization periods of generation plant. Consequently, duringFY1984-1990 the revenues, investment costs and operating expenditures shouldbe adjusted to reflect the hypothetical situation of fully operative andstabilized generation plant (for detailed explanation see Annex 21). Duringnegotiations an assurance was obtained that NTPC will achieve in FY17917,andmaintain thereafter, a rate of return of not less than 9.5% on the netaverage fixed assets in operation. Between FYs1984 and 1990 a minimum rateof 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 projectedconsolidated operating results of NTPC from FY1983 through FY1995. Theforecast earnings performance of NTPC is satisfactory. On the basis of theprojections 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 31.8paise per kWh projected during the Second Ramagundam appraisal. The increaseof 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 2.0 paise per kWh
(d) Return at 9.5% on average netfixed assets in operation 6.2 paise per kWh
Total 12.1 paise per kWh
- of which 1.6 paise per kWh is attributable to the proposedtransmission project which is not directly revenue producing.
1/ Fixed assets are recorded at historical cost as the Government does notpermit NTPC to revalue to current price levels.
-23-
For the years FY1983 to FY1991 regional bulk supply tariffs have beenprojected to progressively increase from 32.2 paise per kWh in FY1983 to the43.9 paise per kWh (excluding fuel surcharge) required to achieve thecovenanted rate of return of 9.5% in FY 1991 (para. 4.03).
4.05 NTPC will become profitable in FY1983 and, as a consequence of therapid commissioning of plant from FY 1984, earnings will rise rapidlythereafter. The rate of return will continue to increase to 12.3% in FY1994when all generating units in each of the stations will be operating at fullcapacity.
NTPC Regional Operations
4.06 Regional income statements for the Northern, Western, Southern andEastern Regions set out in Annexes 25 to 28 showing the projected operatingresults for each region from FY1983-FY1995 are satisfactory. All fourRegions are projected to achieve a 9.5% rate of return in FY1991, thequalifying year (para. 4.03) for NTPC consolidated operations. Minor lossesoccur in FYs1984, 1985 and 1989 for the Southern Region, and in FYs1985 and1986 for the Eastern Region, which are acceptable at that stage in NTPC'sdevelopment program. Power sales from the generating stations in each regionwill be priced at a uniform regional bulk supply tariff (para. 4.17).Operating costs of the transmission facilities provided by the proposedproject 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 1977 - FY 1995
4.08 A Statement of Sources and Applications of Funds covering NTPC's K
current investment program is provided in Annex 22. Internally generatedfunds are expected to contribute 12% to NTPC's investment program betweenFY1983 and FY1992 (Table 4.1), the year in which the last of the Bank Groupfinanced power units (Farakka) will be commissioned. Internal cashgeneration rises rapidly from FY1989 and is projected to provide 100% of theinvestment 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 theinvestment program covers only the provision for projects not yet identifiedas all defined and approved projects are projected as completed by FY 1992.Dividends on equity share capital are not included in the forecasts on theassumption that surplus funds would be applied to the expansion of NTPC'sactivities beyond its current investment program. From the Eirst year of
-24-
operations onward, debt service coverage is satisfactory at 1.3 times andabove.
NTPC's Financing Plan FY 1983 - FY 1992.
4.09 The financing plan for the ten year period FY1983-92 is set out in
Table 4.1 and is satisfactory. The investment cost of the proposed projectrepresents about 4% of the construction expenditures in the financing plan.
4.10 In addition to the proposed project and a provision for projects notyet identified, two new projects (Rihand and Vindhyachal) have been added tothe investment program and financing plan since approval of the SecondRamagundam project. The Rihand project (2 units of 500 MW) is beingimplemented by a consortium of British companies led by Northern EngineeringIndustries Limited and is being financed by the U.K. Government. The loanof p344 million bears interest of 7.75% per annum with principal repayable insemi-annual installments over ten years, excluding a five-year grace period.Equipment and materials, supplied by the U.S.S.R., for the Vindhyachalproject (six units of 210 MW and associated transmission facilities) arebeing financed by a credit of about U.S.S.R. roubles 317 million from theU.S.S.R. Government. The credit bears interest at 2-1/2% per annum withprincipal repayable in equal annual installments within a period of 17 yearsand with the first installment being payable in the third year after thefirst drawing from the credit. Interest and principal payments will be madein Indian currency.
4.11 Bank financing of the proposed project, US$250.7 million, togetherwith Bank Group financing of NTPC's investment program to date, in totalUS$2,101 million, represents about 17% of the total investment involved(excluding the provision for projects not yet identified).
-25-
Table 4.1 NTPC's FINANCING PLAN FY 1983-FY 1992
US$ Million
Rs Million Equivalent %
Source of Funds.
Internal Cash Generation 57,511 6,053 42
Less: Debt Service (37,533) (3,951) (28)Working Capital Increase (2,950) (310) 2)
Contribution to Investment 17,028 1,792 12
Capital Raised
GOI Equity Capital 56,145 5,910 41GOI Loans 1/ 63,933 6,730 47
Total Sources 137,106 14,432 100
Requirements:
Construction Program(including interest duringconstruction) 137,106 14,432 100
Onlending Agreement
4.12 The Bank Loan for the proposed project will be onlent to NTPC by GOIin accordance with an acceptable onlending agreement as a condition ofeffectiveness of the Credit. As in previous lending operations, the terms ofthe onlending agreement would provide for maturity in 20 years, including agrace period of 5 years, and repayment of principal in equal semi-annualinstallments, with interest payable on outstanding balances at not less than12% per annum, except as the Bank may otherwise agree. The rate of interestat which GOI currently lends to industrial and commercial undertakings in thepower sector is 12.5% per annum and reflects an increase from the rate of11.75% in effect at the time of the Second Ramagundam appraisal. The foreignexchange risk would be borne by the Government. An, assurance was obtainedduring negotiations that GOI will ensure prompt availability to NTPC of
1/ Includes onlending of IDA Credits/IBRD loans and KfW, OPEC, U.K. andU.S.S.R. loans.
-26-
sufficient funds to complete the project, including any additional fundswhich 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 FY1977through FY1995, are set out in Annex 23 and reflect a satisfactory financialposition for each of these years. The balance sheets reflect the phasedconstruction program, the commencement of commercial operations in FY1983,and the financing of NTPC's capital requirements by GOI through a combinationof long-term borrowing and equity capital, in a ratio which would normallynot exceed 1:1. Initially the equity portion of financing would be releasedby GOI followed by loan capital. Table 4.2 summarizes NTPC's financialposition at three significant points in its development.
(a) at March 31, 1983 - end of the year in which NTPC will becomerevenue earning;
(b) at March 31, 1989 - end of the year following the year inwhich the proposed project is completed; and
(c) at March 31, 1994 - end of the first year in which all ofgenerating units of the approved projects in the investmentprogram are operating at full capacity.
4.14 These forecasts indicate that by March 31, 1983, when NTPC becomesrevenue earning, total capitalization will be Rs 17,005 million (US$1,790million), divided between GOI loans (including the onlending of Bank Groupfinance) and equity capital in a ratio of 30/70. Six years later (March 31,1989), after the proposed project is completed, total capitalization willhave risen to Rs 113,973 million (US$11,997 million) reflecting a debt/equityratio of 48/52. No external debt or equity financing is forecast afterFY1992 for the current investment program and this, combined with asignificant increase in internal cash generation, will reduce the debt/equityratio to 33/67 by March 31, 1994.
-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 90,090 137,248Less: Depreciation 58 5,210 21,604Net Fixed Assets in Service 6,255 84,880 115,644Work-in-Progress 11,075 27,612 19,208Total Net Fixed Assets 17,330 112,492 134,852Short Term Deposits - - 3,864Working Capital (325) 1,481 2,635Total Net Assets 17,005 113,973 141,351
4.15 The Companies Act 1956 (Section 293.1d) limits borrowing by NTPC toan amount equal to the aggregate of the paid up share capital and "freereserves (i.e. those which are not set apart for specific purposes), exceptwith the consent of the Corporation in general meeting. During negotiations,an assurance was obtained that NTPC will inform the Bank Group beforehand ofany proposal to alter or modify existing limitations on the borrowing powersof its Board of Directors.
Commercial Arrangements for Sale of NTPC Energy
4.16 Under previous credits and loans GOI and NTPC agreed to prepare bulksupply contracts for the sale of energy to the SEBs on terms and conditionssatisfactory to the Bank Group. They also agreed to forward a final draft ofthe contracts for the Singrauli, Korba, Ramagundam and Farakka power stationssix months prior to the first sale of energy from each respective powerstation. Preliminary draft contracts have been provided to the Bank Groupfor Singrauli and Korba which in principle are acceptable,however finaldrafts for Singrauli and Korba which were due by August 1981 and July 1982respectively have not yet been provided. The reason for this delay is thatNTPC has not yet been able to reach agreement on the financial terms of salewith the relevant SEBs. In the interim NTPC has been selling power from theSingrauli station at the inter-State rate of 35 paise per kWh with agreement
-28-
that such sales would be retroactively adjusted to the bulk sale contractprice when final agreement has been reached. Consequently GOI and NTPC agreedduring negotiations that bulk supply contracts for the sale of electricityfrom the Singrauli and Korba power plants must be finalized and signed by allconcerned parties as a condition of effectiveness for the proposed project.It was clarified during negotiations that inter-regional sales of power wouldbe priced at the tariff rate of the receiving Region for committed powerallocation. WThere sales are in excess of the committed power allocation,the tariff rate of the generating Region would apply.
4.17 NTPC bulk supply contracts will establish regional tariffs which willbe applied to power sales in each respective region. Operating costsapplicable to the transmission facilities of-the proposed project areabsorbed by the relevant regional NTPC organizations. Recovery of suchcosts, therefore, is reflected in the projected regional tariffs as aseparate component of these tariffs. The regional income statements set outin Annexes 25 to 28 show the projected regional tariffs, in current rupees,from FY1983 to FY1995. The regional tariffs projected for FY1991, thequalifying 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 capitalinvestment, coal costs, investment timing and level of energy generation inFY1991.
B. _NDHRA PRADESH STATE ELECTRICITY BOARD (APSEB)
4.18 APSEB will be the major beneficiary of the proposed project as thesubstations and 400 kV transmission lines at Ramagundam, Vijayawada andNellore will be located in the State of Andhra Pradesh. Consequently asignificant proportion of the power carried by these facilities will beconsumed in this State.
4.19 APSEB uses full commercial accounting for project and operationalactivities. Although internal reporting conforms to the commercial basis,
-29-
the annual audited statements of account do not as they are published inaccordance with the present requirements of the Electricity (Supply) Act1948. 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 FY1989envisages capital expenditure of Rs 21,433 million (US$2,256) and willprovide additional installed capacity of 1,760 MW (1,340 MW hydro and 420 MWthermal) or 81% over the present level. Power generation is projected toincrease by 7,554 GWh (90%) by FY1989 due to the added capacity and higherefficiency of new plant.
Future Earnings
4.21 The Income Statement set out in Annex 29 shows the actual andprojected operating results from FY1980 through FY1989, adjusted forinflation. The forecast earnings performance of APSEB is satisfactory,reflecting a rate of return ranging between 9.5% and 12.3% between FY1983 andFY1989. No State Government subsidies, covering rural electrificationlosses, are projected for this period as APSEB will be able to achieve asatisfactory cash generation without such State subsidization. The averageAPSEB tariff is projected to increase from 42.4 paise per kWh in FY1982 to55.5 paise per kWh in FY1989.
Internal Cash Generation
4.22 A statement of internal cash generation is provided in Annex 30showing actual and forecast cash generation for the period FY1980 throughFY1989. Net cash generation, as a percentage of three-year average ofcapital expenditure, ranges between 30.8% and 45.4% for the forecast periodFY1983 through FY1989 thus satisfying the covenant established under theThird Rural Electrification Project which requires a minimum 20% contributionto investment.
-30-
V. JUSTIFICATION AND ECONOMIC ANALYSIS
General
5.01 The proposed project, consisting of (i) a 400 kV network expansionwithin the Southern Region, (ii) a 400 kV transmission line linking theSouthern and Western Regions, and (iii) an HVDC back-to-back link betweenNTPC stations in the Northern and Western Regions, is justified as part ofthe least-cost transmission component of the recently completed long-termgeneration capacity expansion plan for the Indian power sector. It providesneeded additional transmission within the Southern Region, and establishesthe initial high-voltage inter-Regional links that will be the first steptowards an integration of the national grid.
Method of Analysis
5.02 In September 1982, CEA completed a 15-year least-cost generationexpansion plan, which is reviewed in Annex 5. Having determined the optimumplant program for the forecast demand in each Region, the plan develops anoptimum transmission grid configuration for that Region. This two-stepapproach is reasonable in India where selection of plant sites (hydro,pithead coal-fired) is fairly limited, and network costs do not influence theoptimal plant mix. This intra-Regional optimization results in a 400 kV gridconfiguration which encompasses, inter alia, the lines proposed under theproject. As the intra-Regional lines are justified by 1995 as part of theleast-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 thecost incurred in case of an outage.
5.03 The two inter-Regional transmission links are examined in comparisonto the investment that would be necessary to provide peaking capacity ineither Region in the absence of the project. The method compares the presentvalues of the transmission links and those of expansions of thermal capacityby amounts equivalent to the capacity made available by inter-Regionaltransmission. In addition, energy cost savings arising from transfers ofenergy between Regions with different generating costs are identified.
5.04 All costs are expressed in CIF (border price) terms or theirequivalents. For local cost components, a standard conversion factor of 0.8is used. Unskilled labor is valued at 75% of its market wage.
Intra-Regional Lines
5.05 The transmission options related to the least-cost generationexpansion 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 loadgrowth is higher in the South.
-31-
5.06 The load flow studies performed by the CEA examine various conditionsfor 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 increasesonly marginally the North to South power flow on the 400 kV network. By farthe most constraining condition consists in sending out the maximum outputfrom the Ramagundam thermal plant operating as base load. In this condition,the proposed network would withstand single outages on the inland lines notcovered by the project, but this would be no longer true when one of thefollowing 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 150
5.07 The shortages are in round figures; they vary according to which oneof the seven inland lines is tripped along the alternative route fromRamagundam to Redhills. They disappear during the wet quarter when the 500MW units are maintained and also another quarter on sections (c) and (d) when200 MW units are maintained. They are reduced by 20% at all times due toforced outages. The distribution of avoided shortages over the year is takenas follows:
Section 6 Months 3 Months 3 Months
(a) 80 to 320 MW 0 to 160 0(b) 80 to 320 MW 0 to 160 0(c) 40 to 160 MW 0 0(d) 0 to 120 MW 0 0
5.08 Assuming a 5% outage rate for each of the seven inland lines, theprobability of having an outage is 35%, i.e. 4.5 weeks per quarter. Furtherassuming a 90% availability for line sections (c) and (d), and 97.5%availability for sections (a) and (b), the total shortages avoided in 1989amount to 208 GWh on all four sections.
5.09 The cost of outages avoided as proxy for benefits is estimated as theeconomic costs incurred by consumers by the use of alternative energy duringperiods of power cuts. For the major consumer categories, this amounts tothe following values:
-32-
Regionalshare of total
Consumer category Value (Rs/kWh) consumption (%)
Industrial and similar 0.98 74
Agriculture 2.49 18Domestic/Commercial 3.33 18Weighted average 1.77 100
5.10 The economic internal rate of return of the intra-Regionaltransmission links is about 13% (Annex 33). The rate of return is notsignificantly sensitive to reasonable variations in costs and benefits. Theappropriateness of timing of the transmission links within the Region can begauged by comparing the annuitized cost of the links per kWh of outageavoided (about Rsl.10/kWh) with the estimated cost of outage in 1989 (Rs1.77/kWh). The differential indicates that the lines are justified in orbefore 1989.
Southern/Western Region Intertie
5.11 The AC link between the two Regions consists of a double circuit linebetween Ramagundam and Chandrapur. The 1,000 MW capacity of this linkresults, after netting out losses and taking into account availability, inabout 950 MW available capacity for the receiving Region. According to CEAcalculations, an increase of that magnitude in the peak demand would augmentthe Loss of Load Probability (LOLP) from the target of 1% to 1.8%, so thatthis 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. Thiscapacity, in the absence of the link, would have to be provided by 2x5Q0 MWadditional capacity in the receiving Region. Under the circumstancesprevailing in India, this capacity would be coal-fired thermal.
5.12 The economic cost streams of the transmission link and thealternative solution of an increase in generating capacity are shown in Annex33. At any discount rate within a reasonable range, the transmission linksolution is the lower-cost option by a wide margin (Annex 34).
5.13 In addition to the justification as least-cost solution, theexistence of the transmission link will make possible energy transfers fromthe Western to the Southern Region during off-peak periods. The estimatedmarginal off-peak energy cost differentials in 1980 (in 1982 prices) areexpected to be about 3.7 paise/kWh during the wet (monsoon) quarter, andabout 6.7 paise/kWh during the dry season. Assuming an all-year weightedaverage differential of about 5 paise/kWh, a feasible transfer period ofabout 6,000 hours per year would result in an annual marginal energy costsaving of about Rs300/kW, or about Rs273 million per year for the available912 MW at the receiving end. By 1995, the wet season cost differential would
-33-
be negligible, but dry season transfers at a cost differential of about 2.8paise/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, andan expansion of the AC 400 kV substation at Korba. After taking into accountavailability and losses, 466 MW of additional capacity could be madeavailable in the receiving Region. In the absence of the link, this would beprovided by a 500 MW thermal unit, most likely by expansion in one of thepithead coal-fired stations.
5.15 The economic cost streams of the DC link (including the full AC partof the link), and of the alternative solution of thermal capacity expansionare shown in Annex 35. At any discount rate within a reasonable range, theDC transmission link solution is the lowest-cost option by a ratio of almost2:1.
5.16 As in the case of the Southern/Western link, the interconnection willalso make off-peak energy transfers possible. In 1989 and the followingearly years, the flow would be from the Western to the Northern Regionbecause 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 thedry period are approximately equal in both Regions, but wet season energywould flow from the North to the West because of a cost differential of about5.1/kWh resulting from accelerated hydro development in the North. Assumingagain initially 6,000 transfer hours per year, the annual marginal energycost saving would amount to about RslOO million, decreasing by 1995 to aboutRs7O 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 AndhraPradesh State Electricity Board. In recent years, average tariffs of APSEBhave been rising at a rate of about 11% per year to a FY82 level of 42.4paise/kWh (USc4.5), and industrial tariffs at a rate of about 20% p.a.Domestic and agricultural tariff development has been less encouraging asthese tariffs have actually decreased in real terms. Present tariffs aresummarized in Annex 36.
5.18 In 1975, the Bank, in collaboration with APSEB, prepared a marginalcost-based tariff study (Report No. 851-IN). Subsequently, several updatingexercises have been performed by the Bank as well as APSEB (Annex 37). Atpresent, APSEB staff is preparing a detailed recalculation of the 1975 study,which is expected to be completed early in 1983. In general, average tariffsin FY82 were slightly below or roughly equivalent to Average Incremental Cost
-34-
(AIC) estimatesl/ (40-50 paise/kWh), a situation which is unchanged fromearlier years. More detailed marginal cost estimates, however, yield asignificantly higher sales-weighted overall marginal cost (about 80 paise/kWhin FY82). This is due to the fact that APSEB's AIC is heavily influenced bya strong future emphasis on hydro development in the State, while, at themargin, non-APSEB thermal generation will have to satisfy demand.
5.19 Cross-subsidization among consumer categories in relation to themarginal cost structure continues to be evident. Industrial consumers paytariffs of about 50-55 paise/kWh, while their marginal cost is more likelyto be about 45 paise/kWh (at the same load factor). On the other hand,domestic consumers, whose marginal cost is about 130-150 paise/kWh, pay atariff of about 45-50 paise/kWh. Agricultural consumers enjoy an even largergap between cost of supply and tariff. This policy of cross-subsidization isAPSEB and Andhra Pradesh Government policy, and is unlikely to be abandonedin the near future for social and political reasons. However, APSEB has beenimproving its tariff structure in line with principles highlighted in the1975 Tariff Study, and plans to continue to do so. Improvements effected inrecent years include (i) the replacement of decreasing block tariffs in thedomestic category by an increasing system, (ii) the abolishing of thedomestic bulk supply category, (iii) the introduction of customer charges,(iv) the introduction of a two-part tariff for HT consumers, (v) theenforcement of a power factor penalty clause in industry, and (vi) theaddition of a fuel cost adjustment clause.
5.20 Further improvements to tariff structure and practice are necessary.The major changes would be:
(i) Power factor regulations need to be enforced in theagricultural sector, where 100,000 of 500,000 irrigationpumps do not have capacitors, but have not been obliged topay the power factor penalty.
(ii) The ratio between demand and energy charges for customers witha two-part tariff is severely distorted. Marginal capacitycost is much higher than the demand charge, while energycharges exceed marginal energy cost.
(iii) The fuel surcharge, while a welcome interim tool to reflectcost changes, may distort the above ratio even more in thelong run, if it is carried on and increased instead of absorbedinto the tariff at regular revisions. A check on its potentialmisuse as tariff adjustment substitute is called for.
1/ Depending on the valuation of large incremental purchases from outsidethe State during the later 1980's.
-35-
(iv) The first ("lifeline") consumption block for domestic consumersneeds to be reduced from the present 100 kWh/month to about25 kWh to justify the subsidized block for minimum needs. Atthe same time, the price per unit above this block should beincreased significantly.
(v) The heterogeneous group of non-domestic LT consumers (hotels,offices, shops, etc.) should be split to reflect consumptionpatterns, while the two LT industrial categories could becombined. The cottage industry category could usefully becombined with the domestic category.
(vi) Tariffs for irrigation consumers should rise in general after along period of stagnation. The ceiling on LT agriculturalconsumers' demand charge should be removed.
(vii) Street light tariffs for larger municipal corporations withability to pay should be raised to reflect cost.
(viii) Interstate exchange tariffs should be adjusted to reflectcost at the time of supply. APSEB is now discussing amarginal cost-based system with CEA and other SEBs.
5.21 The Chairman of APSEB reviewed the present status in regard to tariffrestructuring and gave assurance that the above points are being taken intoconsideration in the continuing process of the restructuring of APSEBtariffs.
-36-
VI. SUMMARY OF AGREEMENTS
Condition of Effectiveness
6.01 (a) GOI and NTPC should provide copies of bulk supply contractsfor the sale of electricity from the Singrauli and Korbapower plants, finalized and signed by all concerned parties(para. 4.16).
(b) The conclusion of a Subsidiary Loan Agreement between GOI andNTPC satisfactory to the Bank (para. 4.12).
Clarifications and Agreements Reached During Negotiations
6.02 During negotiations clarifications were obtained with regard totariff structure improvements to be implemented by APSEB (para. 5.21).
6.03 The following issues were raised with GOI and NTPC and satisfactoryagreements or assurances were obtained with regard to:
(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 covercost 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).
Recommendation
6.04 Subject to the foregoing the project forms a suitable basis for aBank Loan of US$250.7 million.
-37-ANNEX 1
INDIA
CENTRAL POWER TRANSMISSION PROJECT
Power Sector Loans & Credit'
Project Loan No. Amount Remarks
US$m
Bokaro-Konar 23 18.5 CompleteDamodar 72 19.5 CompleteTata Andhra Valley 106 16.2 CompleteTata Trombay 164 9.8 CompleteThird DVC 203 25.0 CompleteKoyna 223 25.0 CompletePower Transmission 416 70.0 CompleteKothagudem II 417 14.0 CompleteTrombay III 1549 105.0Ramagundam 1648 50.0Farakka 1887 25.0Ramagundam II 2076 300.0Rural Electrification III 2165 304.5
982.5
Credit No.
Fourth DVC 19 18.5 CompleteKoyna II 24 17.5 CompleteKothagudem 37 20.0 CompleteBeas Equipment 89 23.0 CompletePower Transmission II 242 75.0 CompletePower Transmission III 377 85.0 CompleteRural Electrification 572 57.0 CompletePower Transmission IV 604 150.0Singrauli 685 150.0Korba 793 200.0Ramagundam 874 200.0Rural Electrification II 911 175.0Singrauli II 1027 300.0Farakka 1053 225.0Korba II 1172 400.0
2,096.0
-38-ANNEX 2Page 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 befinance - (1) The Board shall, substituted by the following:-after taking credit for anysubvention from the State "The Board shall, after taking creditGovernment under section 63, for any subvention from the Statecarry on its operations under Government under section 63, carrythis Act and adjust its tariffs on its operations under this Act andso as to ensure that the total adjust its tariffs so as to ensurerevenues in any year of Account that the total revenues in any yearshall, after meeting all of Account shall, after meeting allexpenses properly chargeable expenses properly chargeable toto 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 ondepreciation and interest all debentures, bonds and loans,payable on all debentures, leave such surplus which shall notbonds and loans, leave such be less than 3% of the net fixedsurplus, as the State Govern- assets employed by the Board or suchment may, from time to time, higher percentage of such assets asspecify. the State Government may, from time
to time, specify."(2) In specifying the surplusunder subsection (1), the StateGovernment shall have due regardto the availability of amountsaccrued by way of depreciationand the liability for loanamortization and leave:-
(a) a reasonable sum tocontribute towards thecost of capital works and
-39-ANNEX 2
Page 2 of 5
Existing Proposed
(b) where in respect of theBoard a notification hasbeen issued under sub-section (1) of section 12-A,a reasonable sum by way ofreturn on the capitalprovided by the StateGovernment under subsection (3)of that section and the amountof the loans (if any)converted by the StateGovernment into capital undersubsection (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 enablecompliance with the requirements of "Priority of Liabilities of the BoardSection 59, the Board shall after - The Board shall distribute themeeting its operating, maintenance surplus of the revenues in any yearand management expenses after after meeting all the expensesprovision has been made for the referred to in subsection (1) ofpayment of taxes (if any) on income Section 59, to the extent suchand profits, distribute the revenue surplus is available and thereceipts, as far as they are avail- amounts accrued by way of depre-able, 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 anyloan raised (including redemp-
(ii) repayment of principal of tion of debentures or bondsany loan raised (including issued) under section 65 whichredemption of debentures of becomes due for payment in thebonds issued) under section 65 year or which became due forwhich becomes due for payment payment in any previous yearin the year; and has remained unpaid;
(iii) payment of interest on loans (ii) repayment of principal of anyguaranteed 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 duein pursuance of guarantees for payment in any previous yearunder 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 otherState Government under section purposes specified in subsection (2)64 or deemed to be advanced of section 59 in such manner as theunder subsection (2) of Board may decide.section 60;
-40- ANNEX 2
Page 3 of 5
Existing Proposed
(vi) repayment of principal ofany loan guaranteed by theState Government undersection 66 which becomes duefor repayment in the year orwhich became due for paymentin any previous year and hasremained unpaid;
(vii) repayment of principal of anyloan advanced to the Boardunder section 64 whichbecomes due for payment in theyear or which became due forpayment in any previous yearand has remained unpaid:
and if any balance amount isleft thereafter, the sameshall be utilized for theother purposes specified-insection 59 in such manner asthe Board may decide.
(2) If for any reason beyond thecontrol of the Board, the revenuereceipts in any year are notadequate to meet its operating,maintenance and managementexpenses, taxes (if any) onincomes and profits and theliabilGities referred to inclauses (i) and (ii) of sub-section (1), the shortfall shall,with the previous sanction of theState Government, be paid out ofits capital receipts.
A new Section 67-A to be inserted asfollowing:-
"If for any reasons beyond the controlof the Board revenues in any year arenot adequate to meet all the expensesreferred to in subsection (1) ofsection 59, the interest on loansadvanced to the Board by the StateGovernment under section 64 or deemedto be advanced under subsection (2) ofSection 60 and charged to revenues inthat year to the extent of the short-fall shall not become payable to theState Government until revenues earnedin subsequent years are adequate alsoto meet such deferred liability ofinterest to the State Government."~
-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 eachof section 67, the Board shall year for depreciation such sumprovide each year for depreciation calculated in accordance with suchsuch sum calculated in accordance principles as the Central Governmentwith such principles as the Central may after consultation with theGovernment may after consultation the Authority, by notification inwith the Authority, by notification the Official Gazette lay down fromin 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 ofdepreciation cannot be adjusted depreciation for the year in whichagainst revenues, the same may be the Electricity (Supply) Amendmentcarried 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 wordsdepreciation for the year in which "subject to the provisions ofthe Electricity (Supply) Amendment Section 67" and subsection (2)Act, 1978, comes into force. shall be omitted. Subsection (3)
of section 68 shall be renumberedas subsection (2)]
S. 69
Account of Audit - (1) The Board In subsection (1) of section 69 of theshall cause proper accounts and Principal Act, for the words "as mayother records in relation thereto be prescribed by the State Governmentto be kept, including a proper in consultation with the Comptrollersystem of internal check and and Auditor-General of India", theprepare an annual statement of words "as may be prescribed by theaccounts including the profit and Central Government in consultationloss account and the balance sheet with the Comptroller and Auditorin such form as may be prescribed General of India and the Stateby the State Government in consult- Governments'!shall be substituted.ation with the Comptroller andAuditor-General of India. No change in subsection 69(2) to (5).
(2) The accounts of the Boardsiall be audited by the Comptrollerand Auditor-General of India or bysuch person as he may authorize inthis behalf and any expenditureincurred by him in connection withsuch audit shall be payable by theBoard to the Comptroller andAuditor-General of India.
-42- ANNEX 2
Page 5 of 5
Existing Proposed
(3) The Comptroller and Auditor-General of India or any personauthorized by him in connectionwith audit of the accounts of theBoard shall have the same rights,privileges and authority inconnection with such audit as theComptroller and Auditor-General ofIndia has in connection with theaudit of Government accounts andin particular shall have the rightto demand the production of books,accounts, connected vouchers andother documents and papers, and toinspect any of the officers of theBoard.
(4) The accounts of the Board ascertified by the Comptroller andAuditor-General of Tndia or anyother person authorized by him inthis behalf together with theaudit report thereon shall beforwarded to the Authority and
to the State Government within sixmonths of the close of the year towhich the Accounts and audit reportrelate, and that Government mayissue such instructions to the Boardin respect thereof as deems fit andthe Board shall comply with suchinstructions.
(5) The State Government shall -(a) cause the accounts of the Boardtogether with the audit report thereonforwarded to it under subsection (4)to be laid annually before the StateLegislature; and
(b) cause the account of the Boardto be published in the prescribedmanner and make available copiesthereof on sale at a reasonalbe price.
Maharashtra 14.2 15.7 9.5 11.0 9.5 12.2 9.5 12.3 w
Orissa 1.7 9.7 6.7 14.3 10.4 19.3 10.4 20.6
Punjab 9.5 11.9 9.5 11.7 9.5 11.7 9.5 11.8
Rajasthan 8.6 9.7 9.5 10.7 5.3F 6.4F 9.5 10.4
Tamil Nadu 9.5 10.4 9.5 9.9 9.5 9.8 9.5 9.8
Uttar Pradesh 1.8 2.4 9.5 10.1 6.4F 7.2F 9.5 10.4
West Bengal 9.5 11.0 9.5F 10.7F 9.5F 10.8F 9.5 10.9
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 additionalexcise tax of 2 paise/kWh on generation which is not included above. This would add anestimated 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 computationstill under discussion with State government.
INDIA
CENTRAL POWER TRANSMISSION PROJECT
All India Sales and Energy Data 1974-75 to 1980-81.
1. The Plan is based on a new CEA exercise in demand forecasting, usingdifferent methods for different consumer categories. The industrial demandforecast is based on empirical relationships between electricity consumptiongrowth and growth of value added in industry; irrigation pumping forecastsare dependent on the planned rate of new pump connections, the expectedutilization rates, and the replacement rate of diesel pumps. Residentialand commercial use is extrapolated from past relationship over time. Twogrowth scenarios, depending on assumptions about higher or lower growth ratesof industrial value added, have been developed. The results of theunconstrained forecast, by Region, are summarized in Table 1.
-46-ANNEX 5Page 2 of 12 pages
Table 1: Projections of Electricity Requirement and PeakDemand on Utility Systems
Region Scenario 1984-85 1989-90 1994-95 2000-01Electricity Requirements - GWh
(at Power Station bus)
Northern High 49411 77666 116420 178836Low 47173 71713 104943 155215
Western High 50406 76382 112979 175626Low 47458 68480 97096 144020
Southern High 40314 60032 86583 133368Low 37983 53777 74016 108361
Eastern High 27393 41356 59916 91900Low 25595 36516 50111 72206
North-Eastern High 2120 4028 6943 13051
Low 2004 3710 6299 11772
Peak Demands - MW
Northern High 9563 14938 22213 34025Low 9157 13906 20193 29779
Western High 8618 13211 19541 30377Low 8221 11935 17052 25293
Southern High 7204 10709 15444 23789Low 6835 9669 13306 19480
Eastern High 4767 7263 10523 16140Low 4458 6463 8869 12779
North-Eastern High 443 855 1495 2865
Low 420 792 1370 2635
2. While, by 1989/90, the new CEA estimate is pitched about midwaybetween all previous forecasts, it is on the high side by the year 2000.This is mostly due to the high sustained industrial growth assumptions in thehigh scenario. The average annual growth rates in All-India electricityconsumption resulting from this exercise are high initially (reflecting thegrowth from present suppressed demand levels), tapering off to about 7-8%p. a. by 1995 (Table 2).
-47-ANNEX 5Page 3 of 12 pages
Table 2: Projected Trends in Growth of Electricity Consumption
(percentage per annum)High LowScenario Scenario
1980-81 to 1984-85 12.81 11.291984-85 to 1989-90 8.93 7.981989-90 to 1994-95 8.17 7.331994-95 to 2000-01 7.62 6.81
3. The pattern of electricity consumption in various consumer categoriesis expected to undergo some change. The consumption in the agriculturalsector would gradually decline to about 13% from the present 18% by the endof the century due to saturation of demand for agricultural pumping. Therewould also be a slight decline in the share of industrial consumption, andan increase in consumption in residential, commercial and other categories.
4. Assumptions concerning the transformation of consumption forecastsinto energy generation and peak capacity requirements are (i) a reduction insystem 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 relaxedgradually. For purposes of system expansion planning, CEA is using the highconsumption forecast scenario. While this scenario may be somewhat toooptimistic in the later years (high sustained industrial growth, littleemphasis on industrial energy conservation), its effect on generatingrequirements, and, consequently, capacity expansion, may be compensated by alikely failure to bring down system losses rapidly. The use of the highscenario as basis for the least-cost expansion plan is therefore the mostreasonable 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 capitaland recurrent costs as variable element, in determining the least-costexpansion sequence necessary to meet forecast demand. For each of the fiveElectricity 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 ofpossible delays;
(ii) the siting of coal-fired plants at pitheads or close to loadcenters;
(iii) the forced outage rate (FOR) of thermal plants; and
-48-ANNEX 5Page 4 of 12 pages
(iv) the discount rate.
6. The main variations affecting the expansion program are those ofhydro construction and forced outage rates. The results show that the "highhydro" option is usually cheapest (although not always significantly), andthat concentration of thermal power at pitheads would reduce the overallcosts considerably. High forced outage rates increase the costsignificantly. Table 3 summarizes the expansion scenarios for each majorRegion, 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 theleast-cost expansion solution for all Regions. This option is examined withrespect to expected future fund constraints in the ongoing Sixth andforthcoming Seventh Plans. If no additional funds can be mobilized in thesetwo Plans, some capacity additions have to be postponed to the Eighth Plan,resulting in higher LOLP and lower peak reserve margins. Table 4 illustratesthe effect on reserve margins of a delay in capacity expansion. Table 5summarizes the final CEA judgement on desirable expansion programs in eachRegion, taking into account fund constraints, qualitative features, andpossible difficulties in bringing down FOR. The program aims at reachingLOLP of about 1% by the early 1990s.
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
LOLP (X) 1995 0.813 0.989 0.892 0.997Energy not served (GPh) 1995 14.1 27.4 17.0 22.3Present value (Rs 10
Generation only 33.2 34.3 30.4 30.8Gen. plus least-cost transm. 35.9 36.9 33.0 33.3
-50- ANNEX 5Table 4Page 6 of 12
Table 4: Gross Reserve Margins (With and withoutFunds Constraints in VI Plan)
(All India)
-- Installed Cap. (MW) ---
After shift- PeakAs per WASP ing benefits Reduc- Demand --- % Reserve Margin ----Studies Due to funds tion in in High As per As perHigh Hydro/ Constraints Benefits Scenario Unrestricted Restricted
1/ The above programme assumes that a capacity of 19866 MW would be added during the Sixth Plan.The inputs for the long-term planning study were finalised in August 1981. At that time, itwas envisaged that a capacity of 4662 MW would be commissioned during 1982-83. According topresent indications, it is expected that during 1982-83 a capacity of 3717 MW (including Nuclear)would be commissioned and erection in respect of 945 MW would be completed.
N.-a n -he--ci Power Copolon umTeOOigoflr- onol struptur-
Corporoto Fmoonc
EV3~~~~~~~~~~~~~~ r[0-o -t t0 .
iJ~~~~~~~~~~~~~~~~~~~Li ~ ~ ~ ~ ~ ~~~~~LCT F] *I E
A f .7--e 7 fI
-64- ANNEX 13Page 1 of 18 pages
INDIA
CENTRAL POWER TRANSMISSION PROJECT
PROJECT DESCRIPTION
The project consists of the following major physical components:
1. 400 kV Transmission Lines (See Attachment 1)
Ramagundam - Mangur, double circuit 230 kmMangur - Vijayawada, double circuit 160 kmVijayawada - Nellore, single circuit 305 kmNellore - Red Hills, single circuit 245 kmSingrauli - Vindhyachal, single circuit 14 kmRamagundam - Chandrapur, double circuit 158 km
2. 400/220 kV Substations (See Attachment 2)
Ramagundam - extension, to connect the second circuit to Mangur(the equipment for the first circuit is part ofthe 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 kVtransformer.
Nellore - new, to connect the single circuit lines toVijayawada and Red Hills and one 315 MVA,400/220 kV transformer.
Red Hills - extension, to connect the single circuit line toVijayawada.
Chandrapur - extension, to connect the double circuit line toRamagundam.
Singrauli - extension, to connect the single circuit line toVindhyachal.
Vindhyachal - extension for the single circuit line to Singrauliand the 500 MW HVDC back-to-back substation.
-65-Annex 13Page 2 of 18 pages
3. 500 MW High Voltage Direct Current (HVDC) Back-to-BackSubstation at Vindhyachal (See Attachment 3)
4. Meetering and Instrumentation (See Attachment 4)
Installation of tariff meetering systems and disturbancerecorders in important substations of the Northern, Western andSouthern Regional grids.
5. Communication System (See Attachment 5)
Power line carrier communication (PLCC) equipment complete forspeech transmission, line protections and data transmission oneach 400 kV transmission line.
-66- Annex 13
Attachment 1Page 3 of 18 pages
Salient Features of the 400 kV Transmission Line
1. Line Configuration
Single circuit lines would have a horizontal and double circuitlines a vertical configuration.
2. Equipment Description
Towers
Self-supporting latticed steel towers, fabricated from struc-tural steel angle sections will be used. A1 the components of the towerswill 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 lineup to 15 degrees, also to be used as section towers;
- 'C' type tension towers for angles of deviation in the lineup to 30 degrees, also to be used as section towers indifficult terrain; and
- 'D' type tension towers for angles of deviation in the line upto 60 degrees and also as dead-end (terminal) towers.
In addition, special towers and foundations are envisaged formajor river and power line crossings and places where the right of way isrestricted or the terrain is particularly difficult. The design of thesetowers and foundations will be finalised after detailed soil investigationand route survey.
Conductors
Twin bundles of 54/7/3.53 'MOOSE' ACSR, or equivalent conduc-tors, will be used per phase, which will provide a power transfercapability of about 600 MW per circuit. As for all 400 kV NTPC lines, theintra-phase spacing will be 450 mm, which will result in the optimum withrespect to line inductance and line loss characteristics.
-67-
Annex 13Attachment 1
Page 4 of 18 pages
Earthwire and Lightning Protection
Suitable galvanized steel earthwire will be used to withstandtwo successive lightning strokes of 150 kiloampere. It will have a ten-sion-to-weight ratio about 20% higher than the power conductor. Sincethe lines would be passing for an appreciable length over hilly terrain,the shielding angle is intended to be reduced to 20 degrees in order tominimize snielding failure.
Grounding
The tower footing resistance will be kept below 10 ohms. Nor-mally pipe type grounding will be used. In case of rocky ground wherethe ground resistance is high, counterpoise earthing will be used to bringtower 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 kNmechanical strength and tension strings will consist of 23 discs (280x170mm) of 160 KN mechanical strength.
3. Summary of Regulations and Practices for Routing 400 kV lines inIndia
Ground Clearance
As per item 77 of Chapter VIII of Indian Electricity Rules -1956 (as amended upto June 1979) the clearance above ground shall not beless than 5.20m plus 0.3m for every 33 kV or part thereof by which thevoltage of the line exceeds 33 kV. For 400 kV lines it works out at8.84m.
Compensation
No compensation is normally required for land in case of trans-mission lines. Compensation is, however, paid for plantations includingthe land involved. Land compensation is also involved in traversing urbanareas but 400 kV lines are usually routed in such a manner as to avoidurban areas. Compensation is made for the crop damaged, if any, duringerection work.
Forest Clearance
While fixing the alignment of the line all efforts are made toavoid reserved forest land. In cases where it is unavoidable as per
-68-
Annex 13Attachment 1Page 5 of 18 pages
Forest (conservation) Act - 1980 advance clearance from the Forest Depart-ment, 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 StateGovernment.
For normal right of way, trees falling on the line route are tobe cut and compensation paid to the owner. A right of way of 26 m oneither 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 oftelecom and power lines in close vicinity is unavoidable as both have toexist in serving common consumers. This brings in problems of extraneousinduction encountered by the telecom circuits.
To avoid induction, the transmission line routes are selected insuch a way that the alignment, as far as possible, is away from open wiretelephone/telegraph line alignment by at least 8 km.
Sometimes in unavoidable circumstances it becomes impossible tomaintain the adequate separation between the power and telecom lines. Insuch cases, induced voltages in the paralleling telecom circuits arecomputed under actual conditions and the following protective measures areadopted as per present practice in India.
A.. Communication Circuits
i) For induced voltage up to 430 volt no protective measuresare considered necessary.
ii) Beyond 430 volt but up to 650 volt adequate numbers of gasdischarge (G.D.) tubes are installed on the affected telcomcircuits. Telecom authorities in such cases do not chargecompensation from power authorities.
iii) Beyond 650 volt and up to 2000 volt again adequate numbers ofG.D. tubes are installed on the affected telecom circuits, butin such cases, whoever, i.e. the power or telecom authority, is thelater entrant, has to pay the cost of such protective works.
iv) If induced voltage is much higher than 200 volt re-engineeringof the affected telecom circuits is done. The followingre-engineering works are commonly adopted in India.
-69-
Annex 13Attachment 1Page 6 of 18 pages
a) The telecom line is shifted from the existing alignment toa different route to maintain the desired separationdistance. The cost of re-routing the telecom line is paidby the later entrant (the power authority);
b) The removal of the affected overhead telecom alignment andthe provision of aluminium sheathed star quad cable of suitablecapacity 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 provisionof the circuit on other media like UHF/Microwave system etc.
B. Railway Block Circuits
Railway block circuits are provided basically for the safetyproblems of the trains, although such circuits may also be protectedagainst high induced voltages by the installation of gas discharge tubesand by changing the block instruments with 300 volt to 450 voltimmunization level.
In cases where induced voltage is higher, overhead block circuitsare removed and re-engineering of circuits like that of communicationcircuits is done at the cost of the later entrant.
Conduction
As the name implies, conduction is brought about by actualelectrical contact between power and telecom lines. Crossing of both thelines therefore is done under the following manner as per the codeprescribed by the Power and Telecom Co-ordination Committee constitutedby 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 beadopted between power and telecom lines;
iii) Adequate guardings shall be provided at the crossings for thepower lines below 36 kV; and
iv) No guarding arrangements are considered necessary in case ofcrossings with high voltage power lines above 36 kV.
-70- Annex 13Attachment 2Page 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 switchingovervoltage to 2.5 PU. The temporary overvoltage could be 2 PU for 1-3cycles. Consistent with these values and the protected levels provided bylightning arrestors, the following insulation levels have been adopted forthe 400 kV system:
a) Impulse withstand voltage 1,320 kVP for transformersand reactors1,425 kVP for otherequipment
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 steadystate transient and dynamic overvoltage to specified levels. Detailedsystem studies for various combinations of operating conditions will beconducted to work out the required compensation. Tentatively 420 kV shuntreactors of 50 MVar capacity are foreseen. In the event of generators notcapable of charging the 400 kV lines in spite of adequate fixed compensa-tion, additional variable compensation may be provided.
2. Interconnecting Transformers
Power transformers will conform in general to IEC 76. the kneepoint voltage of transformers will not be less than 1.1 PU and the aircore reactance will not be less than 20% for two winding transformers and40% for autotransformers. Autotransformers will have a 33 kV tertiarywinding which shall be capable of being loaded to 1/3 of the transformerloading. The insulation level of the tertiary will not be less than 250kV peak for lightning impulse and 95 kV rms for power frequency voltages.
- 71-
Annex 13Attachment 2Page 8 of 18 pages
3. Circuit Breakers
Circait breakers will conform in general to IEC 56 and shall beeither of air blast or SF6 type. The total break time for any current andany combination of other conditions shall not exceed 50 ms for 400 kVbreakers. The 400 kV breakers controlling line feeders will be providedwith preinsertion closing resistors of about 400 ohm with 8 ms insertiontime. The short line fault capacity shall be the same as the ratedcapacity and this is proposed to be achieved without the use of openingresistors.
4. Isolators
The isolators will conform in general to IEC 129. The 400 kVisolators will be horizontal center break and pantograph type dependingupon the layout arrangement adopted for each substation. They will havean individual pole operating mechanism. All isolators shall be preferablyof the motor operated type. Earthing switches shall be generouslyprovided to facilitate maintenance. These should be properly interlockedand allinterlocks shall be fail safe type.
5. Current Transformers
Current transformers will comply in general to IEC 185. Alltaps are to be obtained by secondary switching. Current transformers unitwith 5 secondaries (4 for protection and I for metering) are proposed.The accuracy of the protection cores shall be class PS and for meteringcore it shall be 0.5. The burden and the knee point voltage shall be inaccordance withn requirements of the system including possible feeds fortelemetering.
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 protec-tion and 1 for metering. The accuracy of protection core shall be 3P andfor metering shall be 0.5. The VTS provided on lines shall be suitablefor carrier coupling. The capitance of CVT shall be 4400 pf.
7. Lightning Arrestors
Station class, current limiting heavy duty lightning arrestorsare proposed which will be conforming in general to IEC 99. The ratedvoltage of LA and other characteristics shall be chosen in accordance withsystem requirements. LA would be provided near line entrances and neartransformers and reactors so as to achieve proper insulation coordinationfor the whole substation.
-72-
Annex 13Attachment 2Page 9 of 18 pages
8. Shunt Reactors
50 MVar, 420 kV Shunt reactors are envisaged. The shunt reac-tors would have linear characteristics up to 1.5 PU voltage. The neutralof these shunt reactors shall be grounded through adequately rated neutralgrounding reactors to facilitate single phase reclosure against trappedcharges. The neutral of shunt reactors shall be insulated to 132 kV andshall be protected by means of 132 kV class lightning arrestors.
9. Protection and Control
Suitable control and protective relaying system shall beprovided for all the 400 kV substations equipment and feeders whichinclude 400 kV transmission lines, bus bars interconnection transformersetc., and complete with all necessary equipment. The complete protectionequipment auxiliary relays, trip relays timers, annunciators, indicatinglamps, indicating instruments, meters, switches, semaphore indicators,mimic diagrams, name plates, terminals and associated equipments and otherinter-facing and auxiliary equipment like event-loggers, disturbancerecorders, master clocks, AC clocks and follower clocks, synchronisingtrolley, relay test kits etc., shall be provided. The protection systemshall be in accordance with the modern power system philosophy with equip-ment having high reliability and speed and the transmission lines protec-tion and auto reclosing single and three phase selection. The transmis-sion line protection system shall have maximum operating time up to tripimpulse to breaker (complete protection time including the applicablecarrier and trip relay operating times) for all type of faults anywhere inthe protected line sections during both maximum and minimum generationconditions of 30 ms at the nearest end and 50 ms at the other end (carriertransmission time may be taken as 20 ms provided that any time reductionin carrier time shall be directly reflected as a deduction in the maximumoperating time). The bus bar protection wold be provided for each bussection independently along with the check feature, so that in the eventof a fault, only the minimum number of the circuits shall be disconnectedat the same time ensuring complete fault isolation and shall be of highspeed type. The interconnecting transformer would be provided with dif-ferential protection, restricted earth fault protection,back-up protectionand overfluxing protection etc.
10. Bus Switching Schemes
Ramagundam and Red Hills - Breaker and half scheme.
Mangur, Vijayawada andNellore - Breaker and half scheme.
-73-
Annex 13Attachment 2
Page 10 of 18 pages
Chandrapur - Madhya Pradesh switchyard wheredouble main and transfer scheme
is adopted.
Singrauli, Vindhyachal - Double main and transfer schemelike in all NTPC thermal powerplants.
11. Layout
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 pantographtype.
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 distributionwithin the substation through two transformers ofsuitable rating. For additional reliability, dieselgenerators of suitable capacity would be provideddepending upon the reliability of the MV supply.
b) DC supply:220V and 50V batteries of adequate capacity would beprovided. Each battery would have a boost charger,float charger and trickle charger.
-74-
Annex 13Attachment 2Page 11 of 18 pages
Workshop and Laboratory
Workshop and Laboratory facilities would be provided for peri-odical and preventive maintenance of the equipment.
Oil Evacuating, Filtering, Testing and Filling Apparatus
To monitor the quality of oil for satisfactory performance oftransformers and for periodical maintenance, necessary oil evacuating,filtering, testing and filling apparatus would be provided. Oil tanks ofadequate capacity for storage of pure and impure transformer oil would beprovided.
Fire Fighting System
Fire fighting system will, in general, conform to fire insuranceregulations of India. The system is proposed with both AC and dieseldriven pumps. Automatic heat actuated emulsifying system is proposed fortransformers.
Lightning and Communications
Adequate normal and emergency lightning and communication sys-tems would be provided.
Control Room
Switchyard control room would be provided to house the controland relay panels, PLCC equipment, telemetering equipment, digital analogueprocessing and recording equipment, etc. Air conditioning will beprovided in the building as functional requirement.
Transport Facilities
For movement and unloading of heavy apparatus like power trans-formers and reactors, rail tracks within the substation and mobile craneswould be provided. One tractor trailer of suitable capacity is proposedto be provided under this project for movement of heavy apparatus liketransformers and reactors to areas where proper railway sidings are notavailable.
Field Testing Equipment
One set of field testing equipment is proposed to be procuredunder the project.
-75-Annex 13
Attachment 2Page 12 of 18 pages
Hotline Washing Equipment
Hotline washing equipment would be provided at substations,depending upon need to be established after detailed investigations ofsite environment.
Staff Colony
Staff colony to house the personnel manning the substations,would be provided.
-76-Annex 13Attachment 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 terminalswill comprise of a series-parallel combination of high power water cooledsilicon controlled rectifiers (thyristors) which, through control of theirfiring angle provide the means of power transfer from the AC to DC side orvice versa. The solid state valves must be of modular building blockdesign for easier design optimisation.
2. Convertor Transformer
Two convertor transformers banks, suitably designed to withstandthe insulation requirements of DC application will be used per pole tostep up or step down the AC voltage to the appropriate level before trans-formation to achieve optimum valve design. The secondary of the trans-formers shall be properly connected to achieve the required phase shiftfor proper convertor operation.
3. Reactors
Smoothing reactors will be provided on the DC side for absorp-tion of the ripple voltage generated during conversion.
4. Filters
AC and DC filters will be such as to offer a low impedance pathto ground for harmonics generated in the AC and DC systems.
5. Reactive Compensation
Reactive compensation equipment will be provided to restore theAC side power factor to near unity. These may be of static Var control,shunt capacitor banks, or synchronous condensers or a combination or thethree.
6. Communication Control and Instrumentation
Protection, monitoring, measuring, communication and auxiliaryequipment,as required for the high reliability operation and easy faultdetection and maintenance,will be provided.
-77-
Annex 13Attachment 4Page 14 of 18 pages
Installation of Tariff Metering Systems and DisturbanceRecorders in the Regional Grids in India
1. Background
The power systems in the country are being interconnectedthrough 400 kV transmission lines to evolve the regional grids. Theconstruction of thermal power stations by NTPC together with 400 kV linesis accelerating the process of interconnection in the regions. The powergenerated at NTPC's thermal power stations is allocated to the differentStates in the Region according to the policy laid down by the Governmentof India. The power to the beneficiaries sometimes flows through trans-mission systems in the integrated network belonging to other agencies suchas the States, the Damodar Valley Corporation (in the Eastern Region), theBhakra Beas Management Board (in the Nothern Region) etc., while in cer-tain areas NTPC's transmission system carries power generated by the Stategenerating stations for transmission within the States or sometimes out-side the States. The generation from the different agencies such as thepower generated by the National Hydro-Electric Power Corporation, theDepartment of Atomic Energy, the Neyveli Lignite Corporation and otheragencies also gets fed into the respective regional grids. In order tocompute the energy that is fed into the system from different sources andthe energy actually drawn by the different systems, a special meteringsystem 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 andimports continuously;
b) Facilities for recording (printing) data accordingto the prescribed format, and storing the datafor computing daily, weekly and monthly; and
c) Facilities for transmitting data through telemetrysystems to the control center in the State and/orin the Region.
The instruments will have facilities for dividing the day intodifferent periods to facilitate, if necessary, the introduction at a laterstage of time of day metering system. A single instrument shall becapable of accepting all the input information for a mnaximum of ten cir-cuits; at very large substations where the number of circuits is more thanten, two such instruments would be used. The basic element in the instru-ment is a conventional energy meter which again would receive the inputsfrom CTs and VTs in the substation or generating station. The energymeter would be interfaced to a microprocessor system which shall compute
-78-
Annex 13Attachment 4Page 15 of 18 pages
different quantities for record through a printout in the prescribedformat and also for display on demand. The display shall provide for theinstantaneous value in MW, MVar, '4VA and cumulative MWh, MVarh and alsofor display of cumulative figures for say a day, week or a month. Theprintout facility shall print out different quantities every 30 minutesand also over a period of 24 h as well as the cumulative figures over amonth.
The approximate cost of an instrument is US$120. The list ofstations where instruments of this type are proposed to be installed inthe Northern, Western and Southern Regions are given below. The stationswhere the instruments would be installed would undergo some change whenthe scheme is finally worked out in consultation with the Regional Elec-tricity Boards.
2. Disturbance Recorders
The interconnection of individual systems in the Region neces-sitates that operating conditions should be carefully monitored and,whenever abnormual conditions in the system arise these are also accuratelyrecorded so that the post-disturbance analysis could be carried out. Suchanalysis would facilitate taking corrective measures to prevent recurren-ces of the disturbances. The absence of suitable instruments for record-ing the system conditions before, during and after the disturbance, hasleft many of the disturbances in the systems incompletely analysed.
NTPC has been providing disturbance recorders on all its 400 kVlines. However, such recorders are not provided on some of the 400 kVlines in the Northern and Western Regions and generally in most of the 220kV systems in all the Regions.
3. List of Power Stations and Substations where Tariff Metering will beInstalled
Northern Region
Name of the Substations/Power Stations VoltageLevel (kV)
Power Line Carrier Communication (PLCC) equipment complete for
speech transmission, line protections and data transmission will beprovided on each 400 kV transmission line. The protections for the trans-
mission lines and line compensating equipment will have 100% back-upcommunication 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 belimited to the above and shall include all other equipment
which is necessary for the proper functioning of communicationsystem;
b) Coupling devices suitable for 4400 pf CVTs and forphase-to-phase coupling. The pass band of coupling devicesshall have sufficient margin for adding communication channelsin future, if required. Necessary protective devices for thesafety of personnel and low voltage parts and installationsagainst power frequency voltage and transient over voltageswill be provided;
c) Line traps broad band tuned and suitable for blocking
the complete range of carrier frequencies. Linetraps 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 datasignals. The total transmission time for protectionsignals shall not exceed 20 ms. The carrier frequencies whichare already in operation in the area shall be kept in viewwhile selecting the carrier frequencies for the specified PLCClinks.
-82-
ANNEX 14Page 1 of 4 pages
INDIA
CENTRAL POWER TRANSMISSION PROJECT
Project Cost Estimates
Rs. Million US$ MillionLocal Foreign Total Local Foreign Total
13. TOTAL FINANCING REQUIRED 4,024.00 1,840.31 5,864.31 423.58 193.70 617.28
-86-
U W if _ _ -oz _ t = 'i ------ ------ --------- -
XX L
e4 X O
4-J
o 4
~~ __ I
~~~ -3 2_ X_ _ _ E_ ' _ _i i % R %
-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 1983 - 100.0
1984
December 1983 3.5 98.6
June 1984 8.0 96.8
1985
December 1984 20.0 92.0
June 1985 55.5 77.8
1986
December 1985 90.0 64.0
June 1986 150.0 40.0
1987
December 1986 180.0 28.0
June 1987 227.5 9.0
1988
December 1987 240.5 3.8
June 1988 245.0 2.0
1989
December 1988 250.7
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 FY1996Sate Date a Date a Date a Date * Date * Date Date a Date Dare Date * Date * Date R Date * Date *
Sigrauli I - 200 MW Units Feb 82- Oct 82 2 Aug 83 -- 200 MW Units Feb 83 - Feb 84 -
SingrauJ.i II - 500 MW Units Fob 87 5 Feb 88 5Korba I - 200 MW Units Jan 83 - Jul 83 -
200 MW Units Jan 84 -
Korba II -500 MW Units Jun 87 6 Jun 88 6 Jun 89 6Ramagundam I - 200 MW Units Feb 84 - Aug 84 -
- 200 MW Units Feb 85 -Ramagundam II - 500 MW Units Dec 87 3 Dcc 88 3 Dec 89 3
Farakka I - 200 M'' Uinits Jan 85(2) Jul 85 (2)200 MW Units Jon 86 (7)
Faral.ka It - 500 MW Units Apr 89 12 Apr 90 12 Apr 91 I'll
Rihand - 500 MW Units Jun 87 - Jun 88-Vindhyachal - 210 MW Units Jun 87 - Jun 88 - JuMn 89 -
- 210 MW Units Dec 87 - Dec 88 - Dec 89 -Projects 0ou yet Identified Mar 93- Oct 93 - Oct 94 - Oct 95-
- 500 MW Units Mar 94 - Mar 95 -TOTAL NTPC COMMISSIONING
Currently Scheduled:
Units - Fiscal Year 1 3 5 3 2 1 6 5 5 1 1 I 2 2 1 L- To date 1 4 9 12 14 15 21 26 31 32 33 34 36 38 39
F CL C C- 0 C�-C. CCCL CC CL�-�CL C 0 CCL CL C C CC 0CC CCC -,CCL
CC CCC CCC CCCL -CC C - CCH C C CLI-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 CCCLC-CC CCCL 0CC) CLH.CC CL
CL CCLC. CCLC CCCL 0CC) II HC- II I I I CLCF-CL
C CI C CL 0CC <CC CCC) CL C CL
C C. FHC 00 CL - CL CL CL CL C I CL CL CL
<I CCCL CCC CCLC CCC000 0CC CLCLC -C-CC
0CC. 0CC) CCCL CCC I I CCC) II] II I I C
CCC CCCL CCCL CL C CLCL C CL .-. CL CL CL
CLI CL CL
CCC CLCC CCCL CCC CCCC 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)CCCCCL C-C CC-C
CC0) CCC -0CC CCLCC. CCL C
-C CCL I -C<C CL CL CL[CL
C
CCC CCC CCC CCCL CLCC-C CCCL CC 000CCCL 0CC CCCL CC-C III II I I I C
C C CL 0CC C-.C CC-C C C CL
00 CL CL CL C C CL -C
CL H CCC CCC CCLC 0CC CC C' CCC COO CC
1C C-CO I I I I I I I I C
C C. C-C -CCCL CCC) CCCL I IC. 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 C VC CC) C CC - C CL 00 CL CL C
C C C CL CLC C - - C C C C C C C CC C
CL C C C C C C C CL C C C S-H C -H S -� -- C C C C CC CLC C.C C CC. C 'C C C C C CC C CC H
�CLCH C CCL CC - 'CC C.CL CC- CL .- ICLCC C -C�r CCLCCL C�C2 C-H C�CC NC CL CL
C CC CC C CC C CC C ICC CCC CL C C I- S CLI-OH CCL CC-H CC CCCH CC CC. CC CCC CCL CCL C., CC-CC-CL- C .20CLCCLCC CC.-SCC CCHCC CC�CC COCLCC CC�ICC CLC.�.C C <CLCOOC-. C.CCC.-I CCCCC C.CCCCI C.CCC� CCCC- COCCI-- CC CL F-C)CCCC.C CCCC.C CC<C.C CCL.-C.C CCCLI-C CLCC CC.�I-C CC CL 00 CCL--CF-.F-I CL'CCICH CLCF-.F-. CL--CLF-H ->CF-.H CCLF-'I- >-CLHH CCL CL F-.C-
- . . - - - - - - C) C
CL C C -C C CL C CL C - CL
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
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)
1. The financial statements in this report display NTPC's financialoperations for the period FY1977 through FY1995. They comprise incomestatements (Annex:es 21, and 25 to 28), with supporting statement of plantcapacity, energy generation and sales (Annex 20), source and application offunds (Annex 22), with supporting investment program (Annex 18), andsummarized balance sheets as at March 31 of each year (Annex 23).
2. Projections for FY 1983 throught FY 1995 are based on the followingassumptions:
(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
ANNEX 24
Page 2 of 6 pages
(c) Fuel Cost (Basic) Escalation
Singrauli - Based on 0.600 kg/kWh and )0.589 kg/kWh, for 200 and )500 MW respectively, at )Rs. 127.87/ton in FY 1983 )
Korba - Based on 0.666 kg/kWh and )0.665 kg/kWh, for 200 and )500 MW respectively, at ) FY1982 - 10.0% p.a.Rs. 96.88/ton in FY 1983 ) FY1983 - 8.5% p.a.
FY1984 - 8.0% p.a.Ramagundam- Based on 0.542 kg/kWh and ) FY1985 - 7.5% p.a.
0.541 kg/kWh, for 200 and ) FY1986 - 7.0% p.a.500 MW respectively, at ) FY1987Rs. 175.95/ton in FY 1983 ) Onwards- 6.0% p.a.
Farakka - Based on 0.729 kg/kWh and )0.728 kg/kWh, for 200 and )500 MW respectively, at )Rs. 102.86/ton in FY 1983 )
Rihand - Based on 0.590 kg/kWh for )500 MW, at Rs. 134.03/ton )in FY 1983 )
Vindhyachal- Based on 0.577 kg/kWh for )210 MW, at Rs. 134.03/ton )in FY 1983 )
An additional 5% is added to cost for fuel oil needed forstarting and for low load operation, plus tax of Rs. 5 perton.
Power Station - 2.5% on original cost of 200 MW plant.- 2.0% 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 takesfor che generating plant to reach an operating level of 5,500hours a year, regional average tariffs have been calculated whichresult in a consolidated average NTPC tariff of 32.2 paise/kWhfor FY1983. Regional average tariffs have been progressivelyincreased for each subsequent year to levels resulting in anaverage NTPC tariff of 43.9 paise/kWh in FY1991 which issufficient to achieve the required 9.5% rate of return in thatyear. The regional tariffs include provision for the recoveryof operating costs of the proposed project.
(i) Fuel
Fuel costs are based on 1982-83 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 increasesare shown separately on the income statements.
(j) Project Costs
(i) Singrauli
Construction costs are based on June 1982 prices escalatedat rates given in the schedule below except for ordersalready placed where escalation is applied from award datesonward.
-99-
ANNEX 24Page 4 of 6 pages
(ii) Korba
Construction costs are based on June 1981 prices escalatedat rates given in the schedule below.
(iii) Ramagundam
Construction costs based on January 1982 prices for Phase Iand June 1982 prices for Phase II, escalated at ratesgiven in the schedule below.
(iv) Farakka
Construction costs are based on December 1981 pricesescalated at rates given in the schedule below.
(v) Vindhyachal
Construction costs are based on April 1982 pricesescalated at rates given in the schedule below.
(vi) Rihand
Construction costs are based on January 1982 pricesescalated at rates given in the schedule below.
(vii) Escalation Schedule
Price Escalation
a. 10% per annum for FY 1982b. 8.5% per annum for FY 1983c. 8% per annum for FY 1984d. 7.5% per annum for FY 1985e. 7% per annum for FY 1986f. 6% per annum for FY 1987 and onward.The turbo-generators and boilers are, however, subject tothe following maximum price escalation from the date oforder:
Singrauli 200 MW units - 25%
Korba, Ramagundam andFarakka 200 14W units - 20%
500 MW units for allprojects - 15% Turbine Generators
20% Steam Generators
-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 ofthe first installment including a five year initial grace
period, and repayable in equal semi-annual installmentsof 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, providedthat the unpaid debt at the end of each year would notexceed the sum of the issued share capital and the "free"reserves, that is to say, those which are not required forspecific purposes. Advances would be in the form of equitycapital 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 orindividual generation units and transmission lines includedin 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 accrualswould be charged to revenue. Repayment of principal is
assumed in 30 semi-annual installments commencng on thefirst anniversary following the end of the five year graceperiod.
(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
-101-
ANNEX 24Page 6 of 6 pages
(iii) Current liabilities are assumed at a level of one month'sfuel cost, plus 4% of the annual operating and maintenanceexpenses.
INDIA
NATIONAL THERMA1, POWER CORPORATION LIMITEDINCOME STATEMENT COVERING OPERATIONS FY1983 THROUGH FYl995
NORTHERN REGION
(Rupees Million)0-oo0-0-o osoososo-0 -000-== 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 FY1992
Year Cost of transmission Alternative new generating capacity
(Rs m.) (P.s m.)
82/83 2.3 273
83/84 30.4 685
84/85 115.8 959
85/86 171.1 1,096
86/P7 60.8 821
87/88 12.1 365
88/8'-2013/14 2.9 105
PV 5% 376 5% 4,863
8 340 8 4,214
10 320 10 3,891
12 302 12 3,625
15 279 15 3,303
-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 7:3.7 147
83/84 133.1 252
84/85 312.2 546
85/86 430.2 546
86/87 1Q7.3 420
87/88 94.7 189
88/89-2013/14 12.3 52.5
PV 5% 1,227 2,427
8 1,105 2,101
10 1,039 1,938
12 981 1,804
15 908 1,641
-113-
ANNEX 36Page 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
-114-ANNEX 36Page 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
-115-
ANNEX 37Page 1 of 2 pages
INDIA
CENTRAL POWER TRANSMISSION PROJECT
Marginal Cost of Electricity Supply in Andhra Pradesh
T. 1975 Tariff Study estimates (1974/75 prices) I/
11 kV LT
consumers consumers
Energy (paise/kWh) 11.5 13.7
Capacity (Rs/kW/mo)
- generation and transmission 33.7 41.0
- distribution 4.1 41.1
- total 37.8 82.1
II. 1978 Bank estimates (1978/79 prices) 1/
11 kV 11 kV
Average Rural Average Rural
Capacity (Rs/kW/mo)
Generation 40 47 50 65
Transmission and distribution 27 35 61 77
Total 67 82 111 142
1/ Before application of diversity and load factor considerations.
-lib-
ANNEX 37Page 2 of 2 pages
11 kV 11 kV
Average Rural Average Rural
Energy (paise/kWh)
Dry season peak 23 29 29 35
Dry season off-peak and
Wet season peak 12 15 15 18
Wet season off-peak 0 0 0 0
!II. 1981 Bank estimates (1980/81 prices)
Average
Domestic Industry Agriculture (sales-weighted)
Total cost (paise/kWh) 110 30-40 100-120 68
IV. 1982 Average Incremental Cost (1982 prices)
(paise/kWh) 45-50 1/
1/ Purchases from other States and NTPC valued at similar cost as APSEBgeneration. If purchases were valued at NTPC-s Southern Region AIC, orat hydro rates prevalent in the Southern Region, APSEB's AIC would bein the range of 40-45 paise/kWh.
-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 1982
2. India, Long Term Power Plan, Generation Expansion Program(1981-82 to 1994-95) (5 volumes)Central Electricity Authority, Ministry of Energy (Departmentof Power), Government of India
