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Document of
The World Bank
FOR OFFICIAL USE ONLY I
Report No. 2976a-IN
INDIA
FARAKKA THERMAL POWER PROJECT
STAFF APPRAISAL REPORT
May 27, 1980
Regional Projects DepartmentSouth Asia Projects Department
This document has a restricted distribution and may be used by recipients only in the performance oftheir official duties. Its contents may not otherwise be disclosed without World Bank authorization.
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CURRENCY EQUIVALENTS
Currency Unit Rupee (Rs)Rs 1 = Paise 100
US$1 = Rs 8.4 1/Rs 1 = US$0.1190 1/Rs 1 million US$119,047.62 1/
MEASURES AND EQUIVALENTS
1 Kilometer (km) = 1,000 meters (m) = 0.6214 miles (mi)1 Meter (m) = 39.37 inches (in)
1 Cubic meter (m3) 1.31 cubic yard (cu yd) = 35.35 cubic feet (ft)1 Hectare (ha) = 10,000 m = 2.471 acres (ac)1 Kilogram (kg) = 2.2046 pounds (lb)1 Tonne 1 metric ton = 2,200 lbs1, Kilocalorie (kcal) = 3.968 British thermal unit (Btu)1 Kilovolt (kV) = 1,000 volts (V)1 Kilovolt-ampere (kVA) = 1,000 volt-amperes (VA)1 Megawatt (MW) = 1,000 kilowatts (kW) = 1 million watts1 Gigawatt hour (GWh) 1,000,000 kilowatt hours
ABBREVIATIONS AND ACRONYMS
APS - Annual Power Survey
ARDC - Agriculture Refinance and Development CorporationBHEL - Bharat Heavy Electricals LimitedBSEB - Bihar State Electricity BoardCANDU - Canadian Deuterium Uranium (Natural Uranium, Heavy
Water Reactor)CEA - Central Electricity AuthorityCESC - Calcutta Electricity Supply CorporationCWPC - Central Water and Power CommissionDPL - Durgapur Products LimitedDVC - Damodar Valley CorporationGDP - Gross Domestic ProductGOI - Government of IndiaHVDC - High Voltage Direct CurrentLICI - Life Insurance Corporation of IndiaNHPC - National Hydro Power CorporationNTPC - National Thermal Power CorporationOSEB - Orissa State Electricity BoardPERT - Program Evaluation and Review TechniqueRAPS - Rajasthan Atomic Power StationREB - Regional Electricity BoardREC - Rural Electrification Corporation LimitedSEB - State Electricity BoardTDO - Thermal Design OrganizationUNDP - United Nations Development ProgramVGB - Verein Grosser Betriebe
WBSEB - West Bengal State Electricity Board
NTPC's FISCAL YEAR (FY)
April 1 - March 31
1/ Since September 25, 1975, the Rupee has been officially valued relativeto a basket of currencies. As these currencies are floating, the US$/Rsexchange rate is subject to change. Conversions in this report havebeen made at US$1 to Rs 8.4.
INDIA FOR OFFICIAL USE ONLY
FARAKKA THERMAL POWER PROJECT
STAFF APPRAISAL REPORT
Table of Coutents
Page No.
I. THE POWER SECTOR ....................................... 1Background ............................................. 1Energy Resources ...................................... 1Past Bank Group Involvement in the Sector .... .......... 2Sector Institutions .................................... 3Existing Facilities - All India ........................ 5Power Supply/Demand Balance - All India .... ............ 6Future Development - All India ......................... 7Regional Demand and Supply - Eastern Region .... ........ 8Future Integrated System Operation ..................... 10Bank Group's Strategy in the Sector .................... 11
II. THE BENEFICIARY - NATIONAL THERMAL POWER CORPORATIONLIMITED ................................................ 15Legal Status and Authorities ........................... 15Organization and Management ............................ 16Training ............................................... 16Sale of Power from the Project ......................... 18Accounting Organization and Systems .................... 18Audit .................................................. 18
III. THE PROGRAM AND THE PROJECT ............................ 18The Program ............................................ 18The Project ............................................ 19Estimated Cost ......................................... 20Project Financing ...................................... 21Engineering and Construction ........................... 22Procurement ............................................ 22Disbursements .......................................... 23Ecological Aspects ..................................... 23Project Risks .......................................... 24
IV. FINANCIAL ANALYSIS ..................................... 25Introduction ........................................... 25Future Earnings ........................................ 25Taxation ............................................... 26
This report is based on information provided by CEA, Department of Power inthe Ministry of Energy, NTPC and SEBs during an appraisal carried out byMessrs. B.C. Lynch, V. Antonescu, K.G. Jechoutek and A.E. Bailey (consultant)during May/June 1979.
This document has a restricted distribution ad may be used by recipients only in the performanceof their ofcial duties. Its contents nay not otherwise be disclosed without World Bank authorization.
Table of Contents (continuation)
Page No.
F.nancing Plan FY1977-FY1987 .............................. 26Internal Cash Generation ................................. 28Future Finances .......................................... 28Borrowing Powers ......................................... 30NTPC's Bulk Tariff ....................................... 30Regional Tariffs ......................................... 30-Commercial Arrangements for Sale of NTPC Power .... ....... 31Tariff Level and Marginal Cost ........................... 31
V. JUSTIFICATION ............................................ 32Project Definition ....................................... 32Comparison of Alternative ................................ 32Benefits ................................................. 33
VI. AGREEMENTS REACHED AND RECOMMENDATION .................... 34
ANNEXES
1. All India-Sales and Energy Data for 1969/70, 1974/75,1975/76, 1976/77, 1977/78 and 1978/79 .... ............. 36
2. Regional Demand and Supply; Energy Exchanges Among VariousSystems 1978/79; Schedule of Yearly Additions to ThermalGenerating Capacity - Eastern Region .................. 37
3. Sales and Energy Data for 1974/75 - 1978/79 - SEBs ofEastern Region ........................................ 42
4. Power Supply Position 1976/77-1984/85 - Eastern Region 455. Tentative Demand Forecasts 1984/85 to 1988/89 - Eastern
Region ................................................ 466. Financial Position of the State Electricity
Boards and DVC ......................................... 477. Organization Chart of NTPC .............................. 538. Organization Charts of NTPC's Finance and Accounting
Organization .......................................... 569. Description of the Farakka Development .................. 5810. Project Cost Estimates .................................. 6111. Estimated Construction Schedule ......................... 6312. Estimated Schedule of Disbursements ..................... 6513. NTPC - Income Statements FY1979 through FY1991 .... ...... 6614. NTPC - Source and Application of Funds FY1977 through
FY1991 ................................................ 6815. NTPC - Condensed Balance Sheets FY1977 through FY1991 ... 7016. Assumptions on Financial Projections .................... 7117. Annual Rates of Return in Real Terms .................... 7618. NTPC's Bulk Tariff (Eastern Region) and Bulk Exchange
Tariffs in Eastern Region ............................. 77
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Table of Contents (continuation)
19. Regional Marginal Cost Analysis of NTPC Operations ...... 7920. Definition and Cost of Alternative to the Project ....... 8521. Additional Transmission and Distribution Cost .... ....... 8622. Economic Costs-Farakka Project and Alternative .... ...... 8723. Shadow Pricing of Costs and Benefits .... ................ 8924. Structure of Operation and Maintenance Costs .... ........ 9125. Economic Justification: Results ........................ 9226. Economic Benefits ....................................... 9427. Documents Available in the Project File .... ............. 96
MAPS
IBRD - 14743IBRD - 14518
INDIA
FARAKKA THERMAL POWER PROJECT
I. THE POWER SECTOR
Background
1.01 Economic growth and improvement of the standard of living in Indiadepend critically on the development of the power sector. In the presentstage of economic development, the demand for power grows roughly twice asfast as the economy. Because the power industry is relatively capital inten-sive, its share in total fixed asset formation is increasing rapidly: thepower sector, which has made great strides in the last two decades, is todaythe largest economic sector in the country in terms of investment. The sheersize and increasing complexity of India's power sector, as well as economicconsiderations, necessitate an approach to system planning which, to a muchlarger extent than in the past, should concentrate on nationwide power devel-opment and aim at making use of economies of scale through construction oflarger, more efficient power stations and interconnected high voltage trans-mission systems.
1.02 The strategy of the Government of India (GOI) is to intensify cen-tralized planning of generation and high voltage transmission with a view toultimately centralize control through a national grid with the operation ofgenerating plant on a merit order basis. To this end, GOI established in 1975two power generating companies, the National Thermal Power Corporation (NTPC)and the National Hydro Power Corporation (NHPC) to construct and operate largethermal and hydro power stations and associated transmission. Consultants havebeen engaged to assist the Central Electricity Authority (CEA) in undertakinga 400 kV system study to determine the configuration and parameters of thefuture interconnected national power system. GOI also decided to proceedwith the construction of four large thermal power stations of 1,100 MW to2,100 MW capacity located at coal fields and supplying bulk power to theStates via an interconnected 400 kV transmission system. Construction ofthree such developments, the 2,000 MW Singrauli, the 2,100 MW Korba andthe 2,100 MW Ramagundam projects, has been started with IDA/Bank financialassistance, each project consisting initially of 600 MW of generating plantand transmission (Credits 685-IN Singrauli, 793-IN Korba, 874-IN and Loan1648-IN Ramagundam). An IDA credit of US$300 million has recently beenapproved for the second stage of Singrauli, comprising two additional 200 MWunits and two 500 MW units. NTPC's fourth large thermal power plant is the1,100 MW Farakka plant, located in the Eastern part of the country about 250kms north of Calcutta. The first stage of this power plant, comprising threeunits of 200 MW each, is the subject of this report. Bank Group finance ofUS$250 million is proposed comprising a loan of US$25 million and a creditof US$225 million.
Energy Resources
1.03 India's main commercial energy resources are coal, oil, naturalgas and hydro power. There are also resources of nuclear fuels, principallyuranium and thorium, and India's power program includes the construction of
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further "CANDU" type heavy water reactors using domestically produced naturaluranium as fuel. Two nuclear power stations have been constructed to dateand a third is under construction. Some geothermal energy sites have alsobeen identified, but the potential appears to be limited.
1.04 coal is by far the most extensive indigenous fossil fuel; reservesare estimated at 83 billion tons of which some 21 billion tons have beenproven. Additionally, total reserves of lignite at the Neyveli field in TamilNadu are estimated at around 2 billion tons. If low quality coal, e.g., coalwith high ash and moisture content, is excluded, the estimate of commerciallyusable coal and lignite is reduced to approximately 24 billion tons which,on a forecast countrywide usage, would be adequate for about 50 years undercurrent assumptions of economic growth.
1.05 By comparison with coal, proven reserves of oil are small. However,oil and gas exploration programs continue. Exploration and drilling activitiesto date have already proven an estimated 230 million tons on shore, and recentoff-shore discoveries west of Bombay in the Arabian Sea have led to delinea-tion of fields with proven recoverable reserves of about 250 million tons ofcrude oil and 30 billion cubic meters of natural gas. Other reserves ofnatural gas, which are found in India both alone and in association withcrude oil, are estimated at over 100 billion cubic meters.
1.06 The potential of hydroelectric power resources is estimated at70,000 MW of which some 11,000 MW has already been developed. A further4,700 MW is scheduled for commissioning by FY1984 (see Table 1.2) and some23,000 MW is currently under investigation or scheduled for investigation.Some 70% of the total potential is in the Northern and Northeastern regions.Greater emphasis on hydro-power investments is planned.
1.07 Oil and natural gas have important alternative uses and it is un-likely that they will be a significant factor in the generation of electricpower. The Government intends, therefore, to base the development of generat-ing facilities for the foreseeable future on coal or lignite burning thermalstations and hydroelectric power stations and to gradually develop a smallnuclear program.
Past Bank Group Involvement in the Sector
1.08 The Bank has made nine loans to India for power projects amountingto US$334.5 million and IDA thirteen credits totalling US$1,471 million. Ofthis amount US$1,170.5 million involves financing of generating plant; US$23million the purchase of construction equipment for the Beas hydroelectricproject; US$380 million the provision of high voltage transmission; and
US$232 million the purchase of rural electrification equipment. Nine loansand credits for generating plant, the Beas project (Credit 89-IN) and thefirst three transmission projects (Loan 416-IN Credits 242-IN and 377-IN)have been completed. The Fourth Transmission Project (Credit 604-IN) isnearing completion and the whole credit amount of US$150 million has beencommitted. The third Trombay Thermal Power Project (Loan 1549-IN) wasapproved in April 1978. The Ramagundam Thermal Power Project (Credit 874-INand Loan 1648-IN) and the Second Rural Electrification Project (Credit 911-IN)
are still in the preliminary implementation stage. The credit for theSecond Singrauli Thermal Power Project (Credit 1027-IN) was approved inMay 1980. Commitments to April 30, 1980 totalled some US$500 millionon the four thermal power plant projects (Singrauli, Korba, Ramagundamand Trombay) and US$150 million on the two Rural Electrification Projects(Credits 572-IN and 911-IN).
1.09 The Singrauli, Korba and Trombay projects are on schedule. TheRamagundam project, the Fourth Power Transmission Project and the FirstRural Electrification Project are proceeding satisfactorily notwithstandinginitial delays in implementation and the substantial delay in preparationof specifications and review of tenders for the more sophisticated load dis-patch equipment in the case of the transmission project.
Sector Institutions
1.10 The principal agencies in the industry are: (i) the State Elec-tricity Boards (SEBs); (ii) the Atomic Energy Commission; (iii) the CentralElectricity Authority (CEA); (iv) Regional Electricity Boards; (v) the twocentral power corporations (NTPC and NHPC); and (vi) the Rural ElectrificationCorporation Ltd (REC).
1.11 The SEBs are constituted by the State Governments under the provi-sions of the Electricity (Supply) Act, 1948, to promote the coordinateddevelopment of the generation, supply and distribution of electricity withintheir respective States in the most efficient and economical manner, and forthe control and regulation of other supply undertakings which are privatelicensees. These comprise municipal utilities such as Bombay Suburban Elec-tric Supply Undertaking, and private utilities, the largest of which are theTata Electric Companies, (Bombay), the Calcutta Electric Supply Company (CESC),and the Ahmedabad Electric Supply Company. At the present time, the Stateseffectively own or control well over 90% of electricity supply facilities.While the SEBs are corporate entities in their own right and enjoy someautonomy in the management of their day-to-day operations, they are underthe control of their State Governments in such matters as policy, capitalinvestment, tariff changes, borrowings, pay scales and personnel policies.
1.12 The CEA was formally created in 1950 with responsibility for devel-oping a national policy for power development and coordinating the activitiesof the various planning agencies involved in electricity supply. At thattime, it came under the Power Wing of the Central Water and Power Commission(CWPC). As a result of administrative changes introduced in October 1974,responsibility for power was transferred to the Ministry of Energy, which wascreated at that time to bring together ministerial responsibility for coal andpower. This involved the transfer of the Power Wing of the former CWPC to theCEA, which now comes under the Department of Power of the Ministry of Energyand is responsible for developing a sound national policy for the electricitysupply industry. The Department of Atomic Energy, which is directly responsi-ble to the Prime Minister, deals with nuclear power generation.
1.13 CEA's powers were enlarged through amendments to the generalprovisions of the Electricity (Supply) Act, 1948, which were enacted on
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November 30, 1976. In addition to its general responsibilities for nationalpower policies, it is now responsible for the formulation and coordinationof plans for power development, optimization of investments in the powersector for the whole country, development of interconnected system operation,training of personnel and research and development. It includes specialistengineering organizations which provide comprehensive project engineeringservices to the electricity supply industry. The Thermal Department alsotakes responsibility for monitoring the performance and maintenance recordsof thermal power stations and for organizing the training of power stationpersonnel. The Economic and Commercial Department accumulates data on econo-mic, finance and accounting aspects of the power industry in India, both atCenter and State levels, with particular reference to the operations of theSEBs. The emerging role of CEA in financial affairs is evidenced by theconveying of statutory authority 1/ on it to formulate, in conjunction withGOI, policy for the accounting treatment of depreciation of fixed assetsin the power sector in India. CEA is also playing a leading role in advisingState Governments on the measures to be taken to implement the amendmentsto the financial provisions of the Electricity (Supply) Act, 1948, and isalso providing information to the various working panels of the RajadhyakshaCommittee (para 1.42). A recent major achievement for the CEA was the adop-tion by the SEBs of a uniform system of commercial accounting, devised by itover a period of time. This system, which applies to all SEB accounts fromApril 1979, brings uniformity to the procedures relating to the maintenanceof accounts, and, for the first time, enables direct inter-Board comparisonof financial results.
1.14 The SEBs and the other licensed electricity undertakings are requiredto submit their investment proposals to the CEA for technical and economicappraisal and to the Energy Division of the Planning Commission for inclusionin the Five Year Plan. The Planning Commission is responsible for the alloca-tion of Plan funds among the States and among sectors. Planning of generation,transmission, and distribution development has traditionally been undertakenby each SEB for its own State rather than on a regional or national basis.However, with the rapid growth of the power sector and with the resultantincreasing complexity of operation, GOI sees the necessity for an integratednational approach to sector development.
1.15 As a means of improving collaboration between the SEBs and estab-lishing power systems on a regional rather than a State basis, Regional Elec-tricity Boards (REBs) have been set up for the Northern, Southern, Eastern andWestern regions. The chairmanship of each REB is assumed in rotation by theChairmen of the SEBs within the region and they are staffed by engineersseconded from their constituent SEBs. The general functions of the REBs areto plan integrated operation of the power systems in the region for the maximumbenefit of the region as a whole, coordinate overhaul and maintenance programs,determine generation schedules to be followed and the power available fortransfer between States and determine a suitable tariff structure for thetransfer of power within the region. At present, the Boards function mainly
1/ Amendment of Section 68 of the Electricity (Supply) Act, 1948.
in an advisory role in relation to the SEBs. As mentioned, the REBs wereestablished between 1964 and 1966 by common resolution of the State andCentral Governments, to help develop integrated power systems in the respec-tive regions, and thus prepare for the transition from separate power systemsat State level to regional systems and finally to an interconnected nationalgrid.
1.16 NTPC and NHPC are at present not intended to take a leading rolein the generation and sale of power in the States. At the present time, theconstruction of four large central thermal power stations has been started asmentioned in paragraph 1.02. All of these developments are being constructedand will be operated by NTPC. NHPC will construct and operate large hydro-electric projects. A transmission wing has also been established in NHPC todesign and construct the 220 kV and 400 kV overhead transmission associatedwith hydro-projects, and any other transmission work which it might be commis-sioned to undertake. In most States, the SEB will continue for some time tobe the largest power undertaking.
1.17 REC was incorporated in July 1969 under the Indian Companies Act,1965, as a company wholly owned by GOI, under the general supervision of thethen Ministry of Irrigation and Power (now under the Ministry of Energy).REC's chief objective is to finance rural electrification schemes throughoutthe country, acting as a financial intermediary with technical expertise,and administering funds received primarily from GOI. It is REC's functionto ensure efficient allocation of these funds by establishing policies,procedures, and criteria for the formulation, approval and implementationof such schemes. In doing so, REC is directed to adopt a "project approach,"coordinating electrification with other inputs in rural development in orderto achieve increased agricultural production and overall economic development.
Existing Facilities - All India
1.18 The total installed generating capacity in the whole of India asof March 31, 1979 was just under 29,000 MW, including about 2,225 MW of non-utility capacity, mostly thermal, which is owned by major industrial consumersto meet their own needs. The generating capacity is shown in Table 1.1 below:
Table 1.1: INSTALLED GENERATING CAPACITY AS OF MARCH 31, 1979(MW)
Region Conventional Thermal Nuclear Hydro Total
Northern 3,773 220 3,718 7,711Western 5,204 420 1,770 7,394Southern 2,193 - 4,303 6,496Eastern 3,854 - 895 4,749North-eastern 188 - 146 334Andaman and NicobarLakshadweep 6 - - 6
Non-utility Capacity 2,225 - - 2,225Total 17,443 640 10,832 28,915
Source: CEA.
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1.19 Transmission is at 132 kV and 220 kV and, general'ly, lod ceare interconnected by 132 kV and 33 kV subtransmission lines. Distributionvoltages are 11 kV and 415/240 V. The supply, in general, is reliable, butpower shortages, especially during the summer months, necessitate shutdownsand brownouts. System losses have been reduced in recent years but they arestill high accounting for about 20% of units sent out. This subject is underexamination by the "Committee on Power" (see para 1.42).
Power Supply/Demand Balance - All India
1.20 India's installed power generating capacity increased at an annualrate of 10.3% during the 1950s and 1960s while gross electricity generationgrew at just under 12% during this 20-year period due to better utilizationof generating capacity. Although local and intermittent shortages occuredduring this period, system failures did not present a major problem. However,by the early 1970s, the supply situation had grown more serious and potentialdemand consistently outpaced supply in a number of states. This situation wasdue to several factors such as: failure to impleme.at projects in accordancewith planned schedules; inadequate transmission development; operating andmaintenance problems leading to a low plant availability factor of around 72%;inadequate budget allocations and; the absence of monsoon rains, particularlyduring the early 1970s, leading to lower hydro output.
1.21 The shortage situation was most serious in 1974/75 and 1977/78 andis again extremely serious now, particularly in the Eastern Region. Theestimated deficit of energy throughout India in 1974/75 was about 11,000 GWh(14.1%); this fell to 8,600 GWh (10.3%) in 1975/76 and to 5,100 GWh (5.8%) in1976/77, but increased to 15,800 GWh (15.5%) in 1977/78. Data for 1978/79indicate that the deficit was of the order of 10%.
1.22 Power shortages, particularly in the industrial sector, have affectedthe output of the country and the cost in terms of industrial production fore-gone has been substantial (generally, energy restrictions fall on industry andthere is relatively little loss to the economy on account of power shortages ineither the residential or agricultural sectors). Lost value-added due to lostindustrial production because of power restrictions, could weil be in theneighborhood of 3% of GDP. 1/
1.23 The growth of the power sector during the last 10 years and thepattern of consumption during this period is shown in Annex 1. Sales to agri-culture and irrigation have increased substantially during the 1970s, mainlybecause of the rural development programs. Industrial demand as a proportionof the total demand has declined, and there has been a small but steady increasein domestic demand. It is expected that this pattern of demand will continuewith a gradual improvement in the annual load factor.
1/ See: India, Economic Issues in the Power Sector, 1979 (World Bank ReportNo. 2335-IN, paragraph 68).
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Future Development - All India
1.24 The countrywide peak demand in 1977/78 was 15,520 MW. Accordingto CEA's estimates, unconstrained demand is expected to be about 20,300 MW in
1979/80, 18,600 MW of which is expected to be met by available plant capacity.Installed capacity in 1979/80 is expected to reach about 31,900 MW of which29,700 MW would be utility plant with the balance of 2,200 MW non-utility.
1.25 The development program provides for an expansion of generatingcapacity by about 19,000 MW during the five-year period 1979/80-1983/84,including the nuclear power plants which are scheduled to come into operation,bringing the total planned installed capacity to 45,000 MW. The additionalcapacity scheduled for commissioning during this period is shown in moredetail in Table 1.2. Furthermore, the construction of some 15,000 km of400 kV transmission lines is planned to enable full integration of theregional systems and the evacuation of the output from the proposed largethermal power stations.
Table 1.2: SCHEDULE OF PLANNED ADDITIONS TO CAPACITY DURINGTHE PERIOD 1979/80-1983/84 /a
ConventionalThermal Nuclear Hydro Total
-(-______W)___----- (mw) --------------
Northern 2,900 455 1,300 4,655Western 5,270 - 521 5,791Southern 2,100 470 2,310 4,880Eastern 2,710 - 305 3,015
North-eastern 298 - 261 559
Total 13,278 925 4,697 18,900
/a Excludes non-utility capacity.
Source: CEA.
1.26 Table 1.3 shows the planned annual installed capacity aggregatingabout 45,600 MW in 1983/84, the available capacity, the peak load and theforecast of energy requirements and availability (not taking into accountdiversity). The data referring to the peak load and energy requirement in1978/79 show that demand was constrained by supply. The estimated unsuppressedpower and energy demand would have been about 10% higher (see para 1.21). Theforecasts of peak load and energy requirements are based upon continuous mon-itoring of development trends during the preparation of the annual electricpower surveys of India. If the program of generation development can beachieved on time, the present shortage of energy would be eliminated from1982/83 on, but there would still be a capacity deficit through the five-yearperiod due to a low availability factor of generating plants. The peak avail-ability in India under present operating conditions, is around 60% of installedcapacity. This availability factor is expected to improve gradually as a
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result of the development of system interconnection and the improvement ofmaintenance practices.
Table 1.3: INSTALLED CAPACITY, PEAK AVAILABILITY, PEAK LOAD,ENERGY AVAILABILITY, AND ENERGY REQUIREMENT
ALL-INDIA 1978/79-1983/84
1978/79 1979/80 1980/81 1981/82 1982/83 1983/84
Installed Capacity (MW) /a 26,741 29,734 33,009 35,585 40,804 45,590Peak Availability (MW) 16,268 18,566 20,968 22,171 25,443 28,822Peak AvailabilityFactor (%) 61 62 64 62 /c 62 63
Peak Load (MW) 16,268 /b 20,348 22,443 24,717 27,334 30,068Surplus (Deficit) (MW) - (1,782) (1,475) (2,546) (1,891) (1,246)Energy Availability (GWh) 97,376 103,549 117,855 131,496 151,036 171,949Energy Requirement (GWh) 97,376 /b 112,700 124,408 137,089 150,819 166,298Surplus/(Deficit) (GWh) - (9,151) (6,553) (5,593) 217 5,651
/a Excludes non-utility capacity./b Demand constrained by supply.Tc Reduction in availability factor due to commissioning of hydro plant.
Source: CEA.
1.27 Table 1.3 also indicates that both peak load and energy requirementare estimated to grow at an average annual rate of around 10% during the fiveyear period 1978/79-1983/84. The forecast capacity deficit decreases fromaround 10% of the system load in 1979/80 to 4% in 1983/84 and the energyavailability exceeds energy demand by some 3% in 1983/84. These are varia-tions which are less than the accuracy of any of the forecast data inputs, butthey demonstrate that, if anything, a case could be made for sanctioning morecapacity than presently planned for commissioning during the five-year periodending 1983/84, particularly since all-India data mask shortages in specificregions, which may develop due to insufficient interconnection.
Regional Demand and Supply - Eastern Region
1.28 The major Eastern Region supplying authorities are the Bihar StateElectricity Board (BSEB), the West Bengal State Electricity Board (WBSEB), theOrissa State Electricity Board (OSEB), the Damodar Valley Corporation (DVC),the Calcutta Electricity Supply Corporation (CESC), and Durgapur ProductsLimited (DPL). Each of these authorities (publicly owned boards and corpora-tions with the exception of CESC) has generating facilities and supplieselectricity to final consumers.
1.29 The three SEBs and CESC supply all final consumers of all categoriesin their areas of jurisdiction. DVC's supply to final consumers is limitedmainly to industrial consumers in the Damodar Valley. OSEB usually suppliessurplus energy from its hydro generation to BSEB and some to Andhra Pradesh.Of the total energy flows in the region, about 20% are accounted for byinter-authority exchanges. Similarly, about one-third of total capacity demand
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at peak is made available between authorities (Annex 2). Total energy supplied(and consumed) in the region in 1978/79 was 12,800 GWh; maximum regional coin-cident peak demand covered during the same fiscal year was 2,342 MW. Thisrepresents only a minimal increase in terms of energy, and a decrease by almost100 MW in terms of availability over the previous year. This disappointingperformance is mainly due to significantly lower availability of firm capacityin West Bengal in spite of an increase in installed capacity, and has led torestrictions on demand. At present, WBSEB (including CESC) and DVC are theauthorities with the largest available capacity in the region, togetheraccounting for more than 50% at peak. BSEB and OSEB together account forabout one-third of peak capacity in the region. In 1978/79, the net importfrom outside the region was negligible. In effect, the region operates as aself-contained system.
1.30 In March 1979, 81% of installed regional capacity consisted of
thermal plant, the remainder being hydro. Orissa, with its higher developedhydroelectric resources, had a thermal capacity of only 18% but the otherSEBs rely almost entirely on thermal plant. The high dependence on thermalplant makes the region vulnerable to unplanned outages of thermal equipment,a situation that arose frequently in West Bengal in 1978/79. No change inthis regional pattern is expected to take place in the short term.
1.31 The pattern of electricity consumption in the region shows a pre-dominance of industrial use accounting for about 70% of total consumption(about 62% nationwide). Railway traction takes a larger share than nationally.Overall, therefore, the region is even more industrially oriented than theIndian average (Annex 3). No major changes in the shares of individual con-sumer groups are expected in the future.
1.32 During the five years 1975-79, installed capacity in the regionincreased by about 4.5% per year to reach 4,750 MW in March 1979. The avail-able capacity, however, deteriorated in absolute terms during 1977/78 and1978/79, falling from 55% of installed capacity to about 49%. An increasein this percentage is expected in coming years, after expected correction ofpresent difficulties. Energy consumption has been growing at approximately7.5% per year for the five years up to 1978/79, with particularly high growthin Bihar and Orissa. West Bengal recorded an annual growth of consumption ofonly 4.5% per year, again due to the drop in available energy in the WBSEBsystem in recent years (Annex 4).
1.33 By 1983/84, an additional 3,015 MW (increase of 64%) is expected tobe added. About 50% of this increase will be accounted for by WBSEB and CESCtogether. Presently available information indicates that a further 1,975 MWof new capacity has been approved to come onstream between 1984 and 1988, about30% of this increase being attributable to the proposed project. About 53%of this increase beyond 1984 will be thermal capacity. The basis for thiscapacity extension plan is the demand forecast conducted in the form of theperiodical comprehensive power surveys (Annual Power Surveys-APS) by the CEA,and amended by deliberations of the Planning Commission, SEBs, and the NationalDevelopment Council. At the time of publication of the Tenth APS in 1977, itwas envisaged that about 3,140 MW of an unconstrained potential peak demand
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of more than 3,300 MW in 1978/79 would be met. However, preliminary data onpeak availability in 1978/79 indicate that it was only 2,342 MW. The demandforecasts have been scaled down subsequently by the CEA and the Planning Com-mission's Working Group: unconstrained potential peak demand in 1983/84 isnow estimated to be about 4,850 MW (a reduction by 10% from the Tenth APSestimate), 4,463 MW of which is expected to be met by available plant. Theestimated capacity shortfall in the years until 1984 will reach almost 650 MWin 1981/82, then decrease to about 400 MW in 1984/85. GOI general policy withrespect to this deficit is to resort to demand restrictions rather than tomeet demand by installing thermal capacity with short gestation periods (e.g.gas turbines).
1.34 Tentative projections of demand beyond 1984/85 indicate a growthof potential peak demand in the region by about 9% per year to reach anestimated 7,480 MW by 1988/89. Similarly, the potential energy requirementis expected to grow by 9% per year to about 43,170 GWh (Annex 5). Expectedresource constraints and possible slippage in project implementation make itdoubtful that these requirements can be met. It is likely, therefore, thatpersistent shortages at peak will continue well beyond 1984, even underconservative assumptions of demand growth.
Future Integrated System Operation
1.35 With the increasing size of the power sector in India and its far-reaching impact on the country's economy, annual surveys and Five-Year Plansat the State level have become insufficient as a basis for power developmentplanning. The larger size of power plants, their consequent longer construc-tion period--in average six to eight years for thermal plants and eight toten years for hydro plants--as well as their gradual interconnection requirea long-range perspective for investment decisions on a regional and nationallevel.
1.36 Recognizing the need for coordinated power development throughoutthe country, provision was made in Credit 604-IN to help finance the cost ofconsultants to study the technical, financial and economic aspects of a long-term national plan for the sector. Such a plan should include, inter alia,detailed demand forecasts, investigation of power generation schemes to meetload growth requirements for a 15-20 year period (indicating costs and sequenc-ing of investments to optimize resources), development of primary grid confi-gurations, including the 400 kV system study which CEA has started but whichhas come to a temporary standstill mainly due to lack of overall planning,coordination of power plans with plans for other sectors (determining resourcerequirements), and recommendations on responsibilities and needed operationalpolicies at the State, regional and national levels. Such a study is anessential prerequisite for formulating sound policies for future developmentof the sector and GOI has indicated its intention to complete such a study byApril 1982, based on the terms of reference suggested by the Association (seepara 1.47).
1.37 The operation of regional systems, which will be integrated in thefuture into a national grid, requires large numbers of personnel who would haveto be trained in the use of sophisticated load dispatch equipment and inter-connected systems operation. A UNDP project designed to assist CEA in devel-oping programs for training staff to operate the future load dispatch centers
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came to a halt in 1977, primarily because of personnel problems, and lack ofcounterpart staff. However, GOI plans to reactivate the project during thefirst half of 1980, and is currently finalizing proposals for program imple-mentation for submission to UNDP. The Association will be kept informed aboutthe development of the program.
Bank Group's Strategy in the Sector
1.38 The Bank Group's strategy in its involvement in the Indian powersector, has been one of cooperation with GOI in seeking solutions to the manydifficult and politically sensitive problems which have confronted the Indianelectricity supply industry since Independence. The sensitivity of Center-State relations, because of concurrent jurisdiction over the electricitysupply industry, has dictated that a policy of persuasion rather than oneof explicit leverage would produce better results.
1.39 The Bank Group's main objectives in the sector are:
(a) assistance in accelerating the installation of gene-rating and transmission capacity and promoting measuresto improve the operation and maintenance of existingplant, in order to gradually eliminate the prevailingpower shortages in the country;
(b) assistance in introducing long-range system plan-ning on a nationwide basis which would assure imple-mentation of a least-cost power development program;
(c) promotion of appropriate measures with respect toimproving the sector organization and training; and
(d) strengthening of the finances of the institutionsinvolved in the sector, particularly of the StateElectricity Boards (SEBs), through setting of rate-of-return targets or levels of self-financing andadvising in designing of appropriate tariff systems.
1.40 Progress'towards achieving the above goals has been hindered by con-stitutional factors. Under the Electricity (Supply) Act 1948, power supplyis a "concurrent" subject. This means that the responsibility for supplyingelectricity is shared between the Central Government and the State Governments,requiring full agreement between the Center and the States for the implement-ation of most actions. The States operate, and develop, through their Elec-tricity Boards, most of the power facilities. The consequence of this arrange-ment in many instances has been a parochial approach where a national or atleast regional approach would have been more beneficial. On the other hand,it is debatable whether Central initiative could have been taken much furtherin the time available. The radical proposal that would have enabled powersystem generation and bulk supply to be exclusively a Central responsibility,would have meant a considerable upheaval and would have raised fundamentalpolitical and constitutional issues going well beyond efficiency considerations.
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1.41 Given these difficulties, results achieved so far have beenencouraging. They are the following:
(a) with the establishment of the Regional Electricity Boards(REBs, para 1.15) and later of NTPC and NHPC, the firstimportant steps towards an improved organizational structureof the power sector have been made. GOI intends to graduallystrengthen the authority of the REBs and to increase theirrole of coordinating the SEBs in matters of power developmentand operations;
(b) CEA was reorganized and had its powers enlarged through theamendment in 1976 of the Electricity (Supply) Act 1948 (paras1.12 and 1.13);
(c) a recent amendment of the financial provisions of the Elec-tricity (Supply) Act 1948 requires that tariffs be set atlevels sufficient to enable the SEBs to finance a reason-able proportion of their investment program from internalsources;
(d) recently, SEBs in the Eastern Region have been developingand partially implementing plans designed to improve theirfinancial performance. These plans consist of tariffincreases, rationalization of manpower requirements andother cost effective measures;
(e) with a view to the reassessment of tariff policies, the major-ity of the SEBs have recently completed tariff studies basedon marginal cost pricing principles. The Bank Group's reviewof these studies recommended the standardization of certainassumptions so as to produce a uniform methodology for generalapplication by all SEBs. To assist in this standardizationprocess, CEA is establishing a specialist department to inter-act with the SEBs and to keep the Bank Group advised of futuredevelopments;
(f) NTPC's generation/transmission construction program (paras 3.01and 3.02), which is in the process of staged implementationwith Bank Group assistance, will make an important contributionto the gradual elimination of the present deficit in the coun-try's power balance and is planned in the national interest,a move away from the provincial as was present in the past withState/SEB operations. The proposed project would help to con-tinue this program.
1.42 Going beyond these achievements, Indian authorities have recognizedthat with the rapidly expanding power sector in the country, all aspects ofthe sector have to be reviewed and that satisfactory solutions have to befound for the various sector problems. Consequently, GOI established ahigh-level committee in November 1978, called the "Committee on Power" under
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the chairmanship of V.G. Rajadhyaksha, former member of the Planning Comr-mission. This committee has been assigned the task to examine and makerecommendations for improvement of the following aspects of the powersector:
(a) power planning;
(b) project formulation and implementation;
(c) operation and maintenance;
(d) organization and management;
(e) finance, financial management and tariffs;
(f) rural electrification; and
(g) research and development.
Draft reports by the seven expert panels assembled for this purpose have beencompleted and have been reviewed by the committee. The committee is expectedto submit its findings to GOI in May 1980. The Bank Group will continue totake an active interest in the committee's progress.
1.43 There are two specific remaining areas which have been the cause ofconcern to the Bank Group and also have been the subject of continuing dia-logue with GOI. They are:
(a) the weakness of nationwide long-range planning for powerdevelopment; and
(b) the weak financial position of some SEBs which, forinstance, have not always been able to achieve thecovenanted rate of return of 9-1/2%.
1.44 The growing recognition by GOI of the high priority which needsto be accorded to the power sector has been reflected in a rising share ofinvestment resources being allocated to power generation and transmission--from 16% of total public sector outlays during the Fourth Plan to 19% inthe Fifth Plan and an estimated 23% tentatively earmarked in the draftSixth Plan.
1.45 More realistic planning and improved construction monitoring pro-moted by CEA has already led to quicker gestation of power projects. Duringthe Fourth Plan (1969-74) installed capacity rose from 14,300 MW to 18,500MW, involving a shortfall of some 50% against targets set. By contrast, theFifth Plan (1974-78) witnessed an increase from 18,500 MW to 26,000 MW, ashortfall of only 18% against the target. Standardized layouts and stream-lined construction procedures have already brought down implementation timefor new thermal projects from an average of 71 months in 1974-75 to 53 monthsin 1978-79. Further progress in accelerating the generation program shouldresult from the installation of larger thermal units (200 MW and 500 MW).
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1.46 Better capacity utilization is another major sectoral planningobjective. Poor coal quality has imposed design constraints which aregradually being mastered. A daily monitoring system has been established byCEA to monitor generation from 150 major and medium power stations. Measuresare in hand to accelerate the stabilization of newly installed thermal powerunits, to better monitor breakdowns, to ensure adequate supplies of sparesand to initiate rehabilitation programs for units which require it. Train-ing programs at all levels are being strengthened with the assistance ofthe Central Electricity Generation Board (UK) and the VGB of West Germany.
1.47 In the continued effort of the Bank Group in dealing with the long-range problems of the power sector in India, it was decided to concentrateon the two areas at para 1.43 above. During appraisal of this project andnegotiations for the Second Singrauli Thermal Project discussions were heldwith CEA, NTPC and NHPC on the content of a long-range power development studydesigned to prepare a least-cost power development program as well as CEA'scapability to undertake such study with its own staff. GOI agreed with theterms of reference suggested by IDA. The study has been commenced and is tobe completed by April 1982 (para 1.36).
1.48 From a commercial point of view, the financial performance of severalSEBs, the sole customers of NTPC, has been marginal (for detailed explanationsee Annex 6) and even in years where 9-1/2% rates of return were achieved, anumber of SEBs were not able to meet their debt service requirements. 1/ Thereare several reasons for this unsatisfactory performance, such as insufficientgenerating capacity which does not permit utilization of the market potentialto the fullest extent, less than efficient operating of existing plant, lackof monsoon rains leading to severe load shedding and blackouts, railroad andcoal mine strikes resulting in insufficient coal supply, and low tariff levels.Overall, sector institutions have been contributing less than 10% towardssector investment. Interest bearing loans 2/ from State Governments have upto now provided about 80% of investment requirements with the balance of fundscoming from outside borrowing sources such as, public subscriptions, REC, ARDCand LICI.
1.49 In the context of this project, special attention was directed tothe Eastern States, the beneficiaries of Farakka power. The Eastern Regionpower sector comprises the States of Bihar, Orissa and West Bengal. It ischaracterized by many important and sensitive load centers, involving majorinfrastructure industries, such as steel and coal mining. About 40% of the
installed capacity is operated by the Damodar Valley Corporation (DVC), aGOI statutory body. Another 10% is operated by a private license (CESC) inthe Calcutta metropolitan area. The balance is shared by the SEBs of the
1/ However, in all States except one, duties are levied on electricitysales. Including such taxes as a benefit to the States/SEBs increasesthe returns by up to 5 percentage points. Furthermore, a recentlyenacted GOI tax on kWh generated is also equivalent to a return ofabout 2-3 percentage points. The total return in economic terms istherefore substantially higher than the commercial return to the SEBs.
2/ Onlending of State electricity duties, Central excise tax on electricitygeneration and other budget allocations.
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three States concerned. With State duties and Central excise tax on powerviewed as integral part of power revenues, the rates of return for the publicpower agencies of the Eastern Region are estimated at the following levels(1980): West Bengal, 11.4%; Orissa, 12.1%; Bihar, 4% and DVC, 25.2%. In allcases, there is scope for improvement in finances of the agencies concernedthrough increased generation and sales, reduced auxiliary consumption andlower transmission losses. There is also scope for more stringent cost con-trols and more effective management, particularly in Bihar. Recognizing theneed to enhance financial performance of the Eastern Region SEBs, GOI throughCEA held discussions with the State Governments concerned in late 1979 andagreement was reached about enhanced monitoring and improved accountabilityto achieve improved financial management of the SEBs.
II. THE BENEFICIARY - NATIONAL THERMAL POWER CORPORATION LIMITED
Legal Status and Authorities
2.01 NTPC, the beneficiary of the proposed credit was established in1975 under the Companies Act, 1956. The Electricity (Supply) Act, 1948, hasbeen amended to give the Corporation statutory recognition. NTPC is a companywholly owned by GOI under the general supervision of the Ministry of Energy.Its initial authorized share capital of Rs 1,250 million (US$149 million) wasincreased in May 1979 to Rs 3,000 (US$357 million). The Corporation has aBoard of Directors which should consist of not less than four and not morethan fifteen, some of whom are part-time. At present there are seven Directors.
2.02 The Companies Act, 1956, confers broad powers on NTPC to carry outits work. However, the tariffs to be applied as well as any changes in suchtariffs, its investment plans and annual capital budgets, have to be approvedby the Government. NTPC is also subject to periodic examination by theCommittee on Public Undertakings--a body established by GOI to monitor theperformance 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 projects; and
(ii) to transmit and sell the power generated.
NTPC will initially own and operate the associated 400 kV transmission systemover which power will be distributed from each plant and sold in bulk to StateElectricity Boards. Later these systems will be part of the 400 kV intercon-nected regional systems which, still later, will-be integrated into thenational grid.
2.04 NTPC's present program provides for the construction of four thermalpower stations (Singrauli, Korba, Ramagundam and Farakka). It is also possi-ble that NTPC might ultimately take over the 510 MW Badarpur station nearDelhi (ultimate planned capacity 720 MW). Presently, NTPC is in charge of theoperation of Badarpur on a management fee basis.
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Organization and Management
2.05 NTPC's organization which at present is necessarily constructionoriented is shown in Annex 7, page 1. The complete range of management systems
for all disciplines now under formulation are shown in Annex 7, pages 2 and
3. These are based on the philosophies explained in the NTPC publication
"Framework for Project Management" which was first discussed with NTPC during
negotiations for the Ramagundam project and further reviewed by the mission
during appraisal. The organization is adequate.
2.06 NTPC has adopted a two-tier organizational structure: one at the
central/corporate level and the other for the projects. In addition to normalcorporate level responsibilities, activities such as the development and form-
ulation of policies, and other services relevant to the projects, have beencentralized. These are Technical Services, Contract and Procurement Services,Quality Assurance and Expediting, and Project Management Services. Otherdepartments at the central level are Corporate Planning and Marketing,Corporate Finance, Personnel and Administration.
2.07 The second tier, which embraces project activities, consists of aproject organization for each of the four power plants under construction.Each project organization is headed by a General Manager who is entrustedwith total responsibility for implementation of all aspects of the project'sconstruction program.
2.08 Good progress has been made in building up the organization since1975 when NTPC was established. The Chairman and Managing Director wasappointed in early 1976 and the number of staff appointed by February 29,1980, was 2,658 comprising 521 executives, 131 executives in training and2,006 non-executives. These include 17 executives and 35 non-executives
for the Farakka power station. NTPC has also taken over the majority ofthe employees of the Badarpur Project and Power Station (see para 2.04).
2.09 Present indications are that NTPC is developing along sound lines.It has a Chairman and Managing Director who is a competent administrator withan established reputation in the formation and development of large industrialundertakings. He has taken a great personal interest in developing a compre-hensive project management system as well as designing the organization andprocedures, while building up an establishment of highly motivated engineersand staff. Remarkable progress has been made in all activities in the fouryears since his appointment and providing this impetus can be maintained withno deterioration in management, NTPC should, with the assistance of consultants,be capable of handling the present large development program. Site organiza-tions are effectively functioning at the Singrauli, Korba and Ramagundam proj-ects. The centralized functions which, in addition to the corporate personnel,are planning and finance, provide the engineering, contracting and projectmanagement input. They are organized to meet the project requirements andto ensure an effective coordination of the projects under construction.
Training
2.10 NTPC is a young organization which is growing rapidly to meet thedemands of its large construction program. The next phase of expansion will
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involve the need to recruit and train operating staff. When all currentdevelopments have been completed and commissioned, NTPC's establishment willhave grown from a present 2,658 to a figure in the neighborhood of 10,000.The importance, therefore, of implementing training programs for the variousexpertises required during the construction and operational phases cannotbe too highly stressed.
2.11 Fortunately, NTPC has placed special importance on this aspect ofits organization, and training programs are being developed by the Corporationwhich will, in due course, be backed by a training school equipped with simu-lators, financed both from the proceeds of Credit 793-IN and from the proposedloan and credit, and other modern facilities for instructing and training theoperating staff.
2.12 NTPC's training programs which so far have concentrated on pre-operational spheres of activity such as Planning, Design, Construction andManagement, are now additionally being aimed at its operational sphere. Someof the current major activities are:
(a) Professional engineering training for Executive Trainees(Engineering).
(b) Professional engineering training for Supervisory Trainees(Engineering).
(c) Management development programs.
(d) Seminars and lectures on selected topics.
(e) Familiarization courses for both accounting and managerialstaff on the accounting systems and procedures being imple-mented by NTPC's consultants.
Recruitment of young executive trainees is mainly from engineering graduatesbelonging to mechanical, electrical and civil disciplines on appointment,who are inducted into a one-year training program. The first group of youngexecutive trainees was recruited in February 1977, the second in December1977 and the third by mid-1978 comprising 35, 45 and 84 members respectively.The fourth group comprising 131 trainees was recruited in 1979 and trainingcommenced on November 25, 1979. The training programs have been well designedto provide exposure to power stations under construction and operation, equip-ment manufacturing plants, engineering descriptions and project managementservices. For these purposes, assistance is taken from a large faculty ofexperienced engineers and managers selected from all over the country.
2.13 With the first 200 MW generating unit scheduled to commence commer-cial operation in FY1982, NTPC has finalized comprehensive plans for trainingoperational staff, particularly the non-supervisory staff in the various tech-nical and non-technical trades, to provide foremen for the first two units atSingrauli. The manpower for these is being drawn from experienced staff aswell as from fresh recruitment. Recruitment of manpower has commenced and keypersonnel, such as the station superintendent, are already in position.
2.14 On-the-job training has high priority. The methodology includesclassroom lectures, participation in group exercises and discussions supported
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by direct reading, audio-visual presentations and plant visits. Overalltraining plans and arrangements at this time are satisfactory.
Sale of Power from the Project
2.15 As in the case of NTPC's other projects being financed with BankGroup assistance, GOI has undertaken to allocate at least 85% of Farakka'spower to the Eastern Region States, the remaining 15% will be sold in accord-ance with priorities to be determined by CEA to States with the greatest need.During negotiations, GOI confirmed that allocation of 85% of the output ofpower from the project to the SEBs of Bihar, West Bengal and Orissa and theDVC had been agreed in principle. Undertakings to this effect from theseorganizations would be forwarded to the Bank Group by October 10, 1980.
Accounting Organization and Systems
2.16 NTPC and its management consultants report good progress in theplanning of NTPC's finance and accounting organization (Annex 8) and in thedesign and implementation of accounting systems and procedures. The designof accounting systems for both the construction and operational phases ofNTPC's activities has been completed. Implementation of systems for theconstruction phase is either complete or at an advanced stage both at thecorporate center at headquarters, and also at the sites, while the consul-tants' proposals for the operational phase are at an advanced stage ofdiscussion with management. To familiarize staff with the systems andprocedures, training courses are being conducted by the consultants inconjunction with staff members from NTPC's corporate center.
Audit
2.17 The audit of NTPC's accounts and records is undertaken by a profes-sional auditor appointed by the Company Law Audit Board, on the recommendationof the Comptroller and Auditor General of India. The auditor is normally amember of the Indian Institute of Chartered Accountants, and his audit reporton NTPC's financial statements is subject to comment by the Auditor General.The current auditor Messrs. V. K. Mehta and Company, Chartered Accountants,Delhi, has audited NTPC's accounts since its incorporation and their auditreports have expressed satisfaction at the state of the company's affairsduring this period. It should be borne in mind that NTPC's activities willcover only project construction until FY1982 when power will be sold for thefirst time. NTPC has already undertaken in connection with previous credits(and loan) to submit to the Association/Bank audited financial statementswithin seven months of the end of the fiscal year to which they relate, to-gether with a certified report by the auditor, and a review of the accountsby the Director of Commercial Audits. This has been restated in connectionwith the proposed loan and credit.
III. THE PROGRAM AND THE PROJECT
The Program
3.01 NTPC's present development program comprising the four centralthermal power stations Singrauli, Korba, Ramagundam and Farakka, with asso-ciated 400 kV transmission, is part of India's power development program
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which is described in paragraphs 1.24 through 1.27. The four power plants,totalling 7,300 MW, have been located at coal fields, since it is more eco-nomical to transport electricity than coal to the load centers.
3.02 The first stages of the four central power stations consisting in
each case of three 200 MW generating units and associated transmission areunder construction. The commissioning of the power plant units is scheduledbetween February 1982 (first 200 MW unit at Singrauli) and July 1989 (last500 MW unit at Ramagundam).
The Project
3.03 The project represents the first stage of the Farakka developmentcomprising three 200 MW units with associated transmission totalling about410 km of 400 kV lines.
3.04 Farakka is NTPC's fourth plant in the series of large thermalpower stations to be constructed by NTPC, to feed into a 400 kV system andsupply bulk power to the SEBs. The present planned capacity of Farakkais 1,100 MW; however GOI is considering its extension to a final capacityof 2,100 MW.
3.05 The proposed site of the Farakka power station is in the MurshidabadDistrict of West Bengal. The station is to be located on the west bank of theFarakka feeder canal and will utilize coal from the Hurra block of mines ofthe Rajmahal coal fields in Bihar.
3.06 The unit size of 200 MW rather than 500 MW was adopted for the firststage of the power plant so that each unit would represent only about 4% of theexpected peak load in the Eastern Regional grid at the time of commissioning.A 500 MW unit would represent over 10% and would limit the flexibility ofoperation of the power grid. In addition, with the regional 400 kV networknot yet being fully developed by that time, the sudden outage of a 500 MW unitcould create system stability problems. The second stage would be designedfor three 500 MW generating units although only one such unit is planned atthis time.
3.07 The main criteria for site selection were availability of coal andcooling water. The Hurra basin of the Rajmahal coal fields contains an areaearmarked for open-cast mining with about 340 million tonnes of proven mine-able coal reserves. The mines would have a productive life of about 85 years,supplying the amount of coal needed by the power plant with a capacity of1,100 MW. The present production program for the new mines to supply theproject envisages a build up from 1.1 million tonnes per year in 1983/84 to4.2 million tonnes per year by 1985/86 and 5 million tonnes from 1986/87onwards. The mine will be operated by Eastern Coalfields Ltd., GOI's miningcompany for the Eastern Region, an experienced company which has developedand operates a substantial number of other mines. During negotiations GOIagreed that necessary steps will be taken to ensure adequate coal supplies forthe efficient operation of the project. Coal will be transported from theHurra mines some 50 km from the power station by a captive rail transportationsystem which is to be installed for this purpose. As in the case of NTPC's
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other three power plants under construction, a merry-go-round system would beconstructed, in this case with a total length of 87 km. The rail system willbe owned and operated by NTPC.
3.08 The power station's cooling water requirements would be met fromthe Farakka feeder canal where an abundance of water is available. The mini-mum flow in the canal is estimated at over 25,000 cu. ft./sec, and the esti-mated requirements of cooling water for the 1,100 MW power station is lessthan 8% of the canals minimum flow. The cooling water will be returned tothe canal some 1.5 km below the intake point. The Farakka Barrage Authorityhas given gn undertaking, confirmed by the Central Water Commission, to supplyup to 84 m (3,000 cu. ft.)/sec for consumptive use. Availability of waterfor the project should therefore present no problems.
3.09 The operation of the Farakka power station will be integratedwith the Eastern Regional System and its power output will be allocated tothe States in the Eastern Region. For the first 600 MW phase the associatedtransmission to evacuate power from the power station will comprise 400 kVsingle circuit transmission lines between Farakka and Durgapur and Farakka-and Jeerhat aggregating 410 km. In the second phase, an additional 230 kmof 400 kV line will be added between Farakka and Mokamah.
3.10 The project consists of:
(a) acquisition of land, civil works comprised of roads, cul-verts and other miscellaneous preliminary works, powerstation and residential buildings, plant foundations,railways, canals, ducts and other works associated withthe circulating water systems;
(b) three 680 tonnes/hour boilers and three 200 MW turbo-generating units complete with all auxiliaries andancillary electrical and mechanical equipment includingthe switchyard; and
(c) the 400 kV transmission lines comprising one 165 km singlecircuit line from Farakka to Durgapur and one 245 km singlecircuit line from Farakka to Jeerhat.
(d) a training simulator.
The project is described in greater detail in Annex 9.
Estimated Cost
3.11 The estimated cost of the project, excluding interest during con-struction and duties and taxes, is about Rs 4,119 million (US$490 million).On the assumption that most of the contracts will be won by Indian suppliers,the direct and indirect foreign currency costs are estimated at about Rs 521million (US$62 million) and the local currency costs at Rs 3,598 million(US$428 million). The estimated cost of the project is set out in Annex 10and summarized in Table 3.1 below:
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Table 3.1: ESTIMATED COSTS
Local Foreign Total Local Foreign Total------Rs million…------ U$ million equivalent
Preliminary Works 98.0 - 98.0 11.6 - 11.6Civil Works 509.7 8.8 518.5 60.7 1.0 61.7Electrical and MechanicalPlant 1,361.0 265.8 1,626.8 162.0 31.7 193.7
Coal Handling & Transportation 183.8 32.4 216.2 21.9 3.9 25.8Transmission (400 kV) 222.6 29.0 251.6 26.5 3.5 30.0Training Simulator 0.8 24.4 25.2 0.1 2.9 3.0
Sub-Total 2,375.9 360.4 2,736.3 282.8 43.0 325.8Physical Contingencies 139.5 20.9 160.4 16.6 2.5 19.1Price Contingencies 829.5 139.8 969.3 98.8 16.6 115.4
Total 3,344.9 521.1 3,866.0 398.2 62.1 460.3Engineering & Administration 252.0 1.3 253.3 30.0 0.2 30.2Project Cost (before Duties& Taxes) 3,596.9 522.4 4,119.3 428.2 62.3 490.5
Duties & Taxes 75.0 - 75.0 8.9 - 8.9Total Project Cost 3,671.9 522.4 4,194.3 437.1 62.3 499.4Interest during Construction 233.0 - 233.0 27.7 - 27.7Total Financing Required 3,904.9 522.4 4,427.3 464.8 62.3 527.1
3.12 The estimates for the main items of equipment are based on the quota-tions received during 1977 and 1978 for similar types of plant and equipmentfor the first stage of the Singrauli, Korba and Ramagundam developments withprices escalated to 1979 levels. Transmission costs are also based on esti-mates received for the 400 kV transmission associated with the three powerplants mentioned above and on the costs of 400 kV construction at variouslocations in India. Physical contingencies of 10% on civil works, and of 5%on plant and transmission costs have been allowed to provide for unforeseeablefactors. In assessing price contingencies, it has been assumed that contractswill be fixed price or with ceilings on price inflation for turbo-generatorsand boilers (as was the case of NTPC's three other power plants under con-struction). Costs for equipment and erection have been escalated at 6% for1979, 10% for 1980, 7% for the years 1981-1983 and 5% for the years after 1983.These assumptions have resulted in price contingencies of 37% for civil works,22% for the turbogenerator and boiler package, 48% for other electrical andmechanical equipment, 49% for the coal handling and transportation equipmentand 32% for the transmission component.
Project Financing
3.13 The proposed loan and credit aggregating US$250 million, represent-ing about 51% of the cost of the project (excluding duties and taxes andinterest during construction), would be applied to the CIF and/or ex-factorycosts of plant and equip-, ment. Civil works, plant erection costs, inlandtransportation costs, interest during construction, duties and taxes and anyother costs not financed from the credit, aggregating about US$277 million,would be financed by GOI in the form of loan and equity capital.
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Engineering and Construction
3.14 The desirability of obtaining technical advisory services from
consultants was discussed during negotiations and it was agreed that sincethe basic designs for the Farakka project would be largely of a repetitivenature, a retainer consultant satisfactory to the Bank Group, would beengaged to (i) review deviations from earlier power station designs and(ii) assist NTPC as necessary in the design of and preparation of speci-fications for the power station. NTPC will also use sub-consultants asrequired. A total of 100 man months at US$10,000 per man month with anaggregate cost of US$1,000,000 of which US$200,000 would be foreign exchange,would be provided under the proposed loan and credit.
3.15 NTPC, under its competent chairman, has developed a comprehensiveproject management system, including program coordination and supervisionof construction of the power stations. However, in view of the magnitude ofits construction program, NTPC agreed under the Second Singrauli ThermalPower Project to conclude not later than October 15, 1980 all contractualarrangements for the engagement of consultants to review its project manage-ment and information systems and their initial implementation. A similarcovenent to this effect has also been included for this proposed loan andcredit.
Procurement
3.16 Procurement of all equipment to be financed from the proposed loanand credit, would be on the basis of international competitive bidding inaccordance with the Bank Group's guidelines. Documents for individual con-tracts above US$1,500,000 equivalent (estimated to be at least 95% of theCredit) would be subject to prior review by the Bank Group. Bidding documentsfor equipment, including tender analyses and recommendations for award of con-tracts, would be prepared by NTPC and approved by the Bank Group. To facilitatecontract coordination, the invitation to tender for major plant contracts wouldbe on a supply, deliver and erect basis. This could include civil works incertain cases where these cannot be disassociated from the plant contract--i.e., coal handling, substation structures, transmission lines, but such civilworks would not be financed from the proposed credit. Local manufacturerswould be expected to bid for all categories of equipment. A domestic pre-ference of 15% or the import duty, whichever is less, would be applied in bidcomparison for equipment contracts. To prevent administrative procurementdelays, in case the lowest evaluated bidder is a foreign manufacturer, GOI,as in previous loans and credits, agreed during negotiations that it wouldgrant import permission for such items without further review by any agency ofthe Government. There are competent local contracting firms in India and alsomanufacturing facilities covering most of the equipment for the project. Allitems not financed from the proposed loan and credit will be subject to localprocurement procedures, which are satisfactory.
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Disbursements
3.17 Disbursements from the proposed loan and credit would be madeagainst 100% of the cost of technical advisory services of the retainerconsultants appointed by NTPC (see para 3.14) the and against cost of theequipment to be financed from the proposed loan and credit on the followingbasis:
(a) 100% of the ex-factory cost of equipment procured in Indiaafter international competitive bidding; and
(b) 100% of the foreign cost of equipment procured fromabroad.
The estimated disbursement schedule is given in Annex 12.
Ecological Aspects
3.18 The Indian National Committee on Environmental Planning and Coordina-tion of the Department of Science and Technology, has indicated no objectionto the Farakka Project on environmental grounds, and NTPC will comply withall environmental quality standards prescribed by that committee in the design,construction and operation of the project. Appropriate action should be takenduring the Farakka design stage to deal with the principal environmentalproblems which are:
(a) Location. The proposed Farakka power station is a pit headstation and is situated far from any urban area. Accordingly,there are no problems other than the need to ensure the healthand environment of the operating staff who will be housed ina residential area to be constructed some 4 or 5 km fromthe power station.
(b) Stack Emission. Electrostatic precipitators with an efficiencyof 99% will be installed to take care of the high ash contentof the coal. The stack will be of such a height as to ensurethat particulate matter is dispersed in the atmosphere to reducepollutant fall out concentrations to acceptable levels. Thecoal is of low sulfur content (0.3-1.5%) and sulfur dioxidelevels in the gas are within permissable limits.
(c) Heat Dissipation. The power station's requirement of coolingwater will be met from the Farakka feeder canal, and willbe returned to the same canal through a discharge channelto a point about 1.5 km downstream, where a suitable dif-fusion device will be provided. After leaving the powerhouse there will be some heat dissipation in the dischargechannel. The maximum temperature rise in the feeder canaldue to the return of cooling water is estimated to be2-3 C. Water in the canal will gradually return to itsnormal temperature as it flows downstream.
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(d) Ash Disposal. The ash will be pumped as a slurry, througha pipeline, to an ash dump area located some 6.5 km from thepower station. Skimmers would be provided to obtain rela-tively ash free water from the disposal area before goingto natural drainage.
3.19 With regard to the safety and occupational health of employees,safety regulations for power stations, to which all operating personnel mustconform, will be strictly enforced. The turbine hall of a modern steam tur-bine power station, which is the noisiest area of the plant, has a soundpressure level of less than 90 decibels which is well below the maximumacceptable threshold for the normal 8 hour/day shift worker.
Project Risks
3.20 The project represents one segment of an overall development programcomprised of 7,300 MW of generating plant and some 7,000 km of 400 kV trans-mission. It is part of a tightly designed program with plant and transmissioncoming in at phased intervals throughout the period 1982 through 1989. Main-taining this program on schedule requires careful coordination and expertsupervision at all levels. The principal risk is the possibility of slippagewhich could give rise to delayed commissioning of plant and loss of benefits.With a program of construction of this magnitude, there is no guarantee thatsome delays will not occur, but these should be kept to a minimum throughcareful coordination and supervision during construction and careful attention,when placing contracts, to the capability of manufacturers to meet the deliveryschedules.
3.21 Other risk areas are in engineering design, cost overruns and prob-lems in commissioning and operation during the early operational stage withresultant loss of revenues. There is also the risk of damage due to fire,explosion, etc, but this is covered by insurance provided by the respectivecontractors during the construction stage and by GOI through its self-insurancepolicy after commissioning.
3.22 These risks have been carefully assessed and the following safe-guards taken:
(a) NTPC is being assisted by consultants, and this should minimizeproblems as regards engineering and design;
(b) Plant and equipment costs are based on similar works currentlyin progress in India; provision has been made for cost escala-tion and there should be little risk of any substantial costoverrun unless inflation exceeds estimates; and
Cc) a number of 200 MW generating units will have been in opera-tion for some years before the project is commissioned, thus,providing experience and trained manpower for the project.
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IV. FINANCIAL ANALYSIS
Introduction
4.01 Financial forecasts of NTPC's annual operations through FY1991(Annexes 13 through 15) are based on a capital investment program (Annex 14,page 2) which envisages the construction of four large thermal power stationswith a combined capacity of 7,300 MW, together with almost 7,000 circuitkilometers of 400 kV transmission lines at a latest estimated cost of Rs 48billion (US$5,714 million equivalent). The power stations and transmissionlines will be commissioned on a phased basis during the period February 1982to July 1989.
4.02 Concurrently with this construction program, NTPC is responsiblefor the operation and development of the Badarpur power station in Delhi.This involves directing operations of the 510 MW thermal generating plant(initially 300 MW plus a 210 MW extension constructed and commissioned byNTPC), and for construction of a further 210 MW extension already sanctionedand due for commissioning in September 1981.
Future Earnings
4.03 NTPC will become operational in February 1982 when its first 200 MWgenerating unit at Singrauli is expected to be commissioned. Additional gene-rating capacity scheduled for commercial operation during the succeeding sevenyear period, is set out in Annex 16, page 1, paragraph 2(a). NTPC's projectedearnings are based on the assumption that NTPC would supply bulk power at 400kV to State Electricity Boards at a tariff level which would enable it to earna reasonable return on its investment. This was defined in connection withprevious credits and loan as being a tariff level sufficient to produce a rateof return of not less than 9.5% on the book value of the average net fixedassets in service in FY1989 1/, and applied from the time of commissioning ofthe first generating unit in Singrauli in 1981/82 2/.
4.04 Several changes were necessary in a number of assumptions underlyingNTPC's financial projections, because of: slippage in the commissioning datesof operating plant, release of GOI funds as equity capital in the earlier years,followed by loan capital in later years and cost revisions in the overallinvestment program. The effects of these changes are to:
(a) increase the bulk selling price by 12% over the level esti-mated at the Ramagundam appraisal, bringing it to just over29 paise/kWh;
1/ The first fiscal year in which all generating units at Singrauli wereprojected to operate at 5,500 hours a year.
2/ There are no requirements within India either statutorily or for commer-cial accounting purposes, to note fixed asset and depreciation data atcurrent price levels. The equivalent in real terms of a 9.5% rate ofreturn on an historic rate base in FY1989 is about 7.5% (Annex 17).
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(b) eliminate losses during the initial years of operation; and
(c) reduce by some 5% the overall cost of the investment program.
4.05 The income statement (Annex 13) shows the projected earnings perfor-mance for FY1982 through FY1991. Mainly because of a substantially reducedinterest charge, resulting from the revised financing arrangement referred toin paragraph 4.04, NTPC will become profitable in its first year of commercialoperation, FY1982. Earnings will rise rapidly thereafter, following the rapidcommissioning of plant from FY1984 through FY1989, and will reach the stipu-lated rate of return of 9.5% in FY1989, rising to 11.4% by FY1991. Internalresources will generously cover debt service requirements in the initial yearsFY1982-FY1986 and adequately thereafter.
4.06 Regulating NTPC's annual earnings is a function imposed on GOI bythe amendment to Section 75A of the Electricity (Supply) Act, 1948. Underthe amendment, GOI is required to specify the quantum of annual surplus whichshould be earned so as to provide from internal resources a reasonable contri-bution to capital investment, and to pay dividends on the equity capital.Under present assumptions, NTPC's internal resources would not be adequateto meet these commitments until FY1988. At the negotiations of the SecondSingrauli Project, GOI confirmed that while NTPC's surplus would be regulatedfrom the time NTPC became revenue earning (FY1982), the appropriate amount ofsurplus would depend, in part, upon NTPC's future investment program at thattime. It was thus premature to specify a surplus at this stage. However,the 9.5% rate of return would be retained as a minimum requirement in FY1989and thereafter.
4.07 As in earlier credits and loan, it has been restated for the pro-posed loan and credit that NTPC would achieve in FY1989 and maintain there-after a rate of return not less than 9.5% on net fixed assets in operation,and to set tariffs from the time the first generating unit at Singrauli iscommissioned, at levels not lower than estimated to achieve the required9.5% rate of return in FY1989.
Taxation
4.08 NTPC is liable for income tax under the Indian Income Tax Acts.Because of the large capital expenditure program between FY1979 and FY1988liability to tax will not arise in the foreseeable future and a tax equaliza-tion reserve is not necessary.
Financing Plan FY1977-FY1986
4.09 The following table sets out the financing plan for the ten-yearperiod FY1977 through FY1986 (the year during which the project is scheduledfor completion).
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Table 4.1
TotalTotal US$ Million
Rs Million Equivalent _
Source of FundsInternal Cash Generation 3,795 452 9
Less: Debt Service (1,494) (178) (4)Deferred Charges (11) (1) -
Working Capital Increase (443) (53) (1)Net Internal Cash Generation 1,847 220 4Capital Raised
GOI Equity 21,959 2,614 52GOI Loans 8,791 1,061 21IDA Credits/IBRD Loans onlent /a 9,780 1,150 23Total 40,530 4,825 96
Total Sources 42,377 5,045 100
To Finance:Investment Program(including interest duringconstruction) 42,377 5,045 100
/a Includes the following:
Singrauli (Credit 685-IN) 1,290 150 3Korba (Credit 793-IN) 1,720 200 4Ramagundam (Credit 874-IN) 1,720 200 4Ramagundam (Loan 1648-IN) 430 50 1Second Singrauli (Credit 1027-IN) 2,520 300 6Farakka Proposed Loan 210 25 -Farakka Proposed Credit 1,890 225 5
9,780 1,150 23
4.10 The financing plan covers the proposed project construction periodand provides for construction of the ongoing Singrauli, Korba, and RamagundamProjects, the Second Singrauli Project, and the proposed Farakka Project,together with the balance of the generation and transmission constructionprogram, discussed at paras 3.01 and 3.02. GOI is expected to request addi-tional financial assistance for the balance of the program. The cost of theproposed Farakka Project represents almost 10% of construction expendituresin the financing plan. GOI would provide the capital required by NTPC in theform of debt and equity in a ratio not exceeding 1:1.
4.11 The proposed loan and credit aggregating US$250 million would berelent to NTPC in accordance with an acceptable onlending agreement, as acondition of effectiveness of both the loan and credit. As in previousoperations, the terms of the on-lending agreement would provide for finalmaturity in 20 years, including a grace period of 5 years, and repayment of
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principal in equal semiannual installments, with interest payable on out-standing loans at 10.25% per annum. This is the rate of interest at whichGOI currently lends to industrial and commercial undertakings in the publicsector, and compares with about 16% charged by domestic lending institutionsfor similar types of lending. The foreign exchange risk would be borne bythe Government. Assurances were obtained during negotiations that GOI willprovide the balance of funds required to complete the project on terms satis-factory to the Bank Group and to provide any additional funds which might berequired due to cost overruns or other unforeseeable factors.
4.12 Bank Group financing of the proposed Farakka Project, US$250 mil-lion, together with Bank Group financing of the total Singrauli developmentand the first stage developments of the Korba and Ramagundam stations, inaggregate US$1,150 million, represents some 42% of the total costs involved,excluding duties, taxes, and interest charged to construction.
Internal Cash Generation
4.13 The Source and Application of Funds Statement presented in Annex14 shows the rapid buildup of internally generated funds from the time NTPCbecomes revenue earning in February 1982. An unusually high debt servicecoverage of 9 times and 6 times in FYs 1982 and 1983, respectively, is causedby the mainly equity financing in those years. Financing by means of loancapital in succeeding years reduces the coverage ratio to a more balancedlevel reaching 1.3 times in FY1989, when the total Farakka development wouldbe commissioned.
4.14 The level of internal cash generated is determined by the assump-tions made in the financial projections (Annex 16). Surplus funds arise inFY1988 and accelerate rapidly thereafter. It is reasonable to assume that,having reached a satisfactory level of financial viability, NTPC would beexpected to commence paying dividends on its equity share capital. Thisis a decision which will have to be made by GOI in due course, and will beinfluenced by decisions on whether or not to expand the activities of NTPCbeyond the current investment program. A decision could also be made topay off GOI loans in advance of their maturity, thereby saving interest andimproving NTPC's profit-ability.
Future Finances
4.15 Forecast condensed balance sheets through FY1991 are presented inAnnex 15. The balance sheets reflect the build-up of the construction pro-gram, the commencement of commercial operations in February 1982, and thefinancing of NTPC's capital requirements by GOI through a combination oflong-term borrowing and equity capital, so as not to exceed a debt/equityratio of 1:1, with equity being released initially followed by loan capitallater. Table 4.2 below shows NTPC's projected financial position at threesignificant points in its development:
(a) at March 31, 1982 - end of year when NTPC becomes revenueearning;
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(b) at March 31, 1986 - end of year following commissioning ofthe proposed Farakka Project; and
(c) at March 31, 1990 - end of year in which the last unit inthe investment program would be commissioned.
Table 4.2
As at March 31 FY1982 FY1986 FY1990--------Rs Million…------
Fixed Assets at Cost 2,453 23,749 48,275Less: Depreciation 1 1,165 5,280
Net Fixed Assets in Service 2,452 22,584 42,995Work-in-Progress 11,589 18,629 -
Total Net Fixed Assets 14,041 41,213 42,995
Short Term Deposits - - 2,451Working Capital 27 442 1,074Deferred Expenses 11 - -
Total Net Assets 14,079 41,655 46,520
Financed by:Equity Capital 13,812 21,959 21,959Retained Earnings 7 1,125 6,907
Total Equity 13,819 23,084 28,866
Long Term Debt 260 18,571 17,654
Total Capitalization 14,079 41,655 46,520
Debt/Equity Ratio 2/98 45/55 38/62
4.16 The above table shows that by March 31, 1982, just after the pointat which NTPC becomes revenue earning, total capitalization would be aboutRs 14,000 million (US$1,667 million), with a debt/equity ratio of 2/98. Fouryears later - end of FY1986, after the Farakka Project would be commissioned -
total capitalization would have almost tripled to about Rs 42,000 million(US$5,000 million) with a debt/equity ratio of 45/55. Over 60% of the con-struction program will have been completed at this time. By March 31, 1990,when the balance of the construction program would be completed, capitaliza-tion would be about Rs 47,000 million (US$5,600 million) with an improvementin the debt/equity ratio to 38/62. The improvement in the debt/equity ratiobetween FY1986 and FY1990 reflects the assumed cessation of expansion and itsassociated financing, combined with significant increases in the level ofretained earnings, caused by improved profit volume. NTPC's authorized sharecapital would be raised progressively during the period FY1980 through FY1984(Annex 15) to reach a figure of about Rs 22,000 million (US$2,620 million).It is currently RS 3,000 million (US$357 million).
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4.17 The level of working capital in NTPC's balance sheet assumes thatits customers (SEBs) would have credit terms of 30 days. Monthly billingsfor energy sold would be running at the rate of almost US$3 million in FY1982.US$47 million in FY1987 and US$116 million in FY1991. Accordingly, delayin payment of accounts by SEBs would adversely affect NTPC finances. Thisis not regarded by NTPC as a serious problem because, under existing circum-stances in India, credit terms of less than 30 days for interstate transfersare common. In addition, penalties for late payment of accounts would beimposed. Further reference to this subject will be made during dialogue withGOI and NTPC on the bulk tariff issue (para 4.19).
Borrowing Powers
4.18 The Companies Act 1956 (Section 293.1(d)) restricts borrowing byNTPC to less than the aggregate of the paid up share capital and the "freereserves" (i.e., those not set apart for a specific purpose) except with theconsent of the corporation in general meeting. During negotiations NTPCagreed to inform the Bank Group beforehand of any proposal to alter or modifyexisting limitations on the borrowing powers of its Board of Directors.
NTPC's Bulk Tariff
4.19 This is a matter which was first discussed during the appraisal andnegotiation of the First Singrauli Project (Credit 685-IN). Since the first200 MW unit was not scheduled to come into commercial operation until earlyin calendar year 1982, this matter has awaited the formulation by GOI and NTPCof the strategy for the sale of power from the central thermal power stations.The dialogue was resumed at negotiations of the Ramagundam Project (Credit874-IN and Loan 1648-IN) and continued during appraisal and negotiation ofthe Second Singrauli and Farakka Projects. Subjects discussed included theregionalization of the bulk tariff; the form of contract with SEBs and REBs,covering operating practices, financial requirements, arrangements for settle-ment of disputes; and the structure of proposed tariff. These matters arediscussed in more detail in the following paragraphs.
Regional Tariffs
4.20 There appears to be a valid case for regionalizing NTPC's bulktariff to better reflect the nature of the individual NTPC thermal powerstations as integral parts of regional power systems, at. least until a nationalpower grid is established. This could be achieved in a manner compatible withNTPC's tariff covenant with the Bank Group (para 4.07). If the total capitalbase at FY1989 was broken down over each of the four stations and operatingcosts and revenues for the various years similarly allocated, a bulk tarifffor each station in each region would emerge. This exercise was undertakenduring appraisal and produced the following approximate bulk tariffs:
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Paise/kWh 1/
Singrauli (Northern Region) 23Korba (Western Region) 31Ramagundam (Southern Region) 34Farakka (Eastern Region) 32Average (All Regions) 29
A comparison of the Farakka bulk tariff with bulk exchange tariffs in theEaster Region is contained in Annex 18.
Commercial Arrangements for Sale of NTPC Power
4.21 NTPC has prepared a draft contract for the sale of power to itscustomers in the Northern Region (mostly SEBs). The draft explains themanner in which power (including NTPC's) would be distributed to individualcustomers in the region through the Regional Load Dispatch Centers, the com-mercial and financial arrangements for the sale of NTPC's power, and thearrangements for the settlement of disputes. During negotiations of theSecond Singrauli Project, GOI confirmed that NTPC's draft contract wasbeing examined in the context of a proposal to study the feasibility of acommon agency selling power from all central projects in a region to SEBsat a common rate, so as to optimize operation of regional systems. Thefeasibility and the several technical, operational, commercial and institu-tional aspects of this proposal needed examination. Once a view had beentaken on the concept of a pooled tariff for central generation in a region,NTPC's commercial arrangements for the sale of its power would be finalized.During negotiations, GOI agreed to finalize these arrangements at leastsix months before the start of commercial operation of the first Farakkaunit currently scheduled for December 1984. Continuing dialogue would bemaintained with the Bank Group on this subject.
Tariff Level and Marginal Cost
4.22 At the present time, while no output will be sold by NTPC for sev-eral years to come, it is irrelevant to talk of marginal cost-based tariffsat 1979 levels. NTPC is not an existing expanding system, but has to betreated as the beginning of such a supply system. By definition, practicallyall costs of the system known in 1979 are future, marginal costs of supplyingincremental demand. In order to arrive at marginal costs in future years whenpower is actually sold, assumptions about the future expansion and operationof the system, and about inflation expectations have to be made (Annex 19).
1/ While interest during construction has been calculated on a "totalcompany" basis, some inequities may emerge in allocating the interestto individual stations, due to the fact that loans as distinct fromequity finance may have been allocated to specific plants, on a "firstin-first out" basis, whereas it might be more equitable to allocateinterest on an "average cost of capital basis". The figures above wouldrequire some adjustment if this were the assumption. Nevertheless theyare useful for purposes of illustration.
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4.23 Assuming that capacity expansion investment will continue for the
foreseeable future in line with growing demand, and that, ultimately, NTPCwill be operating at the limit of its capacity, the estimates of marginal-cost-based tariffs for 1984/85, the first year of operation of all four stationsrange from 35 to 37 paise/kWh (US44.2-4.4) as a one-part tariff, and Rs 935-1,022/kW/year (US$111-122) plus 9.1-11.2 paise/kWh (USJ1.1-1.3) as a two-part
tariff (Annex 19). The discrepancy between these figures and the financiallydetermined tariff levels (para 4.20) is, of course, attributable to the factthat present financial projections are based on investment tapering off in
the later years, while the marginal cost concept allocates full marginal costof additional capacity to incremental demand if this demand occurs at fullcapacity utilization.
4.24 Notwithstanding the limitations of the marginal cost approach, itwill be necessary to consider it as an input into tariff construction in later
years, when marginal cost will start exceeding the financial tariff that isplanned to remain fixed in absolute terms throughout the projection period.Any intention to expand NTPC operations after the late 1980's or an integra-
tion of NTPC capacity into a future national generating authority will haveto take into account the need to provide for future investment and to postproper price signals to SEBs and consumers.
4.25 The Bank Group has been encouraging SEBs to carry out marginal costbased tariff studies aimed at establishing tariff levels based on economicconsiderations. Ten major SEBs have so far completed their studies while afurther three SEBs are expected to complete their studies shortly. Duringnegotiations the Bank Group received an undertaking from Orissa SEB to carryout a similar study which would be completed by May 1981.
V. JUSTIFICATION
Project Definition
5.01 The proposed project 1/ is justified as the least-cost solutionavailable to meet part of forecast demand in the Eastern Region within theforeseeable future.
Comparison of Alternatives
5.02 Given the existing and forecast power shortages in the Easternregion, the need for additional capacity is urgent. Capacity of the requiredamount can only be provided by thermal plant with a sufficiently short gesta-tion period. Possible hydro sites require extensive engineering studies,
and those hydro projects that can be constructed within a reasonable timewill be undertaken as parts of concurrent SEB investment plans. The nuclearalternative was excluded because of the long gestation period.
1/ For purposes of justification, the project is defined as the full
Farakka program at time of appraisal of 1,100 MW generating capacity,
thus properly allocating all initial infrastructure expenditure to thetotal final capacity.
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5.03 Although the theoretically most attractive solution to providethermal capacity quickly might be the expansion of existing coal-fired gener-
ating stations, the expansion potential of existing stations in the region islimited and sufficient capacity could not be brought on stream by using thishypothetical solution. The only realistic alternatives are, therefore, either
the proposed project (a coal-fired station near the pithead supplying the wholeregion), or a series of smaller stations near load centers that would be thenatural choice of the SEBs in the absence of a large centrally operatedproject.
5.04 The alternative consisting of smaller stations at the load centersmight encompass three new sites (in Orissa, Northern Bihar and near Calcutta)and the expansion of an existing station in the Damodar Valley area with anaggregate capacity equal to that of the proposed project. With the exceptionof the Orissa site, all locations would require transport of coal over sub-stantial distances. The largest station (420 MW) would supply Calcutta, andthe second largest (330 MW), Northern Bihar load centers (Annex 20).
5.05 As the transmission facilities included in the proposed project are
designed to serve not only for the evacuation of Farakka power, but also forother energy flows in the region, an allowance for some additional transmis-sion investment has been made in the cost of the alternative solution. Thisincludes not only the transmission necessary for the evacuation of power fromthe Orissa pithead station, but also the "regional" element (Annex 21).
5.06 The costs of both the project and its alternative have been phasedto provide capacity and energy in the same pattern (Annex 22). All costs areexpressed in economic terms, i.e. in CIF/FOB prices where available and ad-justed by the appropriate conversion factors to border prices where necessary.Unskilled labor has been shadow priced at 75% of the market wage, skilledlabor at full market wage. The economic cost of coal has been derived fromproduction cost expressed in border prices (Annexes 23 and 24).
5.07 The project constitutes the least cost solution for satisfying1,100 MW of demand in the Eastern Region gradually from 1985 onwards. Annex25 shows the present values of the cost streams of the project and of thealternative assuming opportunity cost at capital at 10%, with a sensitivitytest at a discount rate of 13%. The results show the advantage of the projectover its alternative of Rs 633 million (US$75 million) at the 10% discountrate, and Rs 443 million (US$53 million) at the 13% discount rate. The proj-ect is more attractive than the alternative at discount rates up to about 35%.The cost advantage of the project rises with higher fuel cost and is slightlyless if the cost of capital goods increases.
Benefits
5.08 Quantification of economic benefits arising from the implementationof an expansion of generating plant integrated into a existing and growingsystem is not easily established. A two-stage approximation approach hasbeen adopted for the proposed project: (a) average retail tariffs in theregion have been assumed to represent a proxy for the minimum observed will-ingness of consumers to pay for power; and (b) in order to quantify some addi-tional consumer surplus beyond this minimum, the cost incurred by industry
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in maintaining and operating standby generating sets has been assumed torepresent a proxy for industrial consumers' willingness to pay for continuo-sspower supply (Annex 26).
5.09 Corresponding to the definition of benefits as willingness to payat the retail level, additional costs of transmission and distribution invest-ment as well as for operation and maintenance have been allocated to projectcost in line with the general regional incremental investment pattern. Thisadditional cost is net of the transmission element already included in theproject cost. The incremental amount of energy sold has been adjusted toaccount for system losses typical for the region (Annex 21).
5.10 The weighted average of tariff revenue at retail level in the East-ern Region has been established at 27.8 paise/kWh in 1979 prices, and convertedto border prices for purposes of the comparison with economic cost. The indus-trial tariff revenue is replaced by the observed average willingness to pay forcontinuous power supply 1/. The minimum economic internal rate of returnquantified in this way is 13%, increasing to 15% if more frequent outages occur,resulting in a higher utilization of standby sets.
5.11 The internal economic rate of return is likely to be considerablyhigher than the minimum quantifiable estimate of 13%, if the derived consumers'and producers' surplus of industrial, agricultural and commercial output madepossible by the alleviation of shortages is taken into account, and if indirectbenefits accruing to the Indian economy would be fully considered. Benefitsaccruing to domestic consumers are also understated by the use of the tariffas benefit. Were retail tariffs alone used as the proxy for benefits, itwould be noted that tariffs charged final consumers are inadequate to recoverthe incremental cost of the project.
VI. AGREEMENTS REACHED AND RECOMMENDATION
6.01 During negotiations the following issues were raised with GOI andsatisfactory agreement or assurances were obtained with regard to:
(a) The status of the action programs of the Eastern Region SEBsto improve their operational efficiency and financial per-formance (paras 1.46 and 1.49);
(b) provision of adequate coal supplies (para 3.07);
l/ The average cost of grid supply together with the operation of dieselstandby generating sets during power outages has been established asabout 38 paise/kWh as opposed to the weighted average regional industrialtariff of 27 paisa/kWh (23 paisa in economic terms), given typicalutilization rates of standby sets (Annex 26).
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(c) import permission without Government review (para 3.16);
(d) provision of the balance of capital to complete the projecttogether with any additional funds which might be neededdue to cost overruns or other unforeseeable factors(para 4.11); and
(e) preparation by Orissa SEB of a marginal cost based tariffstudy (para 4.25).
6.02 During negotiations the following issues were raised with GOI andNTPC and satisfactory agreement or assurances were obtained with regard to:
(a) undertakings from the SEBs of Bihar, West Bengal andOrissa and the DVC, of their willingness to take powerin accordance with agreed allocations (para 2.15);
(b) audit (para 2.17);
(c) appointment of project management and information systemsconsultants (para 3.15);
(d) tariffs (para 4.07);
(e) the conclusion of an onlending arrangement between GOI andNTPC (para 4.11);
(f) borrowing (para 4.18); and
(g) bulk supply contracts (para 4.21).
6.03 Subject to the foregoing, the project forms a suitable basis forBank Group finance of US$250 million, comprising a loan of US$25 millionand a credit of US$225 million.
INDIA
FARAKA THERMAL POWER PROJECT
All-India-Sales and E-nergy Data for 1969/70, 1974/75. 1975/76, 976/77 1977/bS and 1978/79
1969/70 1974/75 1975/76 1976/77 1977/78 1978/79
(Estimated)
lntal-loid C-Pacity (excl.non-utility plant (MW) 14,102 18,317 20,117 21,814 23,770 26,743
t'leetri ity Generated (MW) 57,988 70,191 79,231 88,333 91,206 97,376
Electricity sold GW14 41,061 52,682 60,246 66,608 68,593 78,321
7iectricity Gerneration per capita kWh 96.Z 119.2 132.5 147.2 146.7 156.4
Klect.icitv Consumption per capita kWh \ 76.0 89.9 100.3 ]11.0 110.9 118.7
Propor-ion of Sales (%)
Agricul!tura' and Irrigation 9.2 14.5 14.5 14.4 14.5 15.1
.aiwic-y TractIcn 3.5 2.9 3.1 3.3 3.5 3.2
! ndu st rv 69.1 62.1 62.4 62.5 61.6 61.8
Coam 2erce and G5overnment 6.5 8.5 7.3 7.3 7.3 7.0
L',s,C iC c8. 6 8.5 9.7 9.5 10.0 10.-
Other (Public Lighting, Watervorks etc.) 3.1 3.5 3.2 3.0 3.0 2.7
Average Annual Growtlh o' Sales (%) 9.9 5.3 14.5 10.5 3.2 14.0
Losses as percentage of kTVh sent out 16.8 20.5 19.4 19.7 19.6 19.9
X
- 37 -ANNEX 2Page 1 of 5 pages
INDIA
FARAKKA THERMAL POWER PROJECT
Regional Demand and Supply - Eastern Region
Shortages and Restrictions
1. During 1978/79, Orissa SEB was the only supply authority in theregion with a comfortable power supply position, supporting neighboring Biharduring times of capacity and energy shortage. No officially notified restric-tions were in force in Bihar, but ad hoc load shedding procedures were usedwhen available peak capacity was insufficient. Similarly, DVC had to resortto temporary restrictions for its industrial consumers and for the supplyto CESC, due to unscheduled outages at some generating units.
2. WBSEB's official restrictions on consumption and load have been inforce since July 1976. The main provisions are (i) a 15% cut in the potentialunrestricted maximum demand of industrial consumers, (ii) one day of the weekwithout supply for industrial consumers, (iii) availability of evening peaksupply for domestic and most large industrial consumers only. These rathersevere cuts have been intensified during 1979. Low plant availability appearsto be one of the primary reasons for the shortages; it is expected that thecuts in supply will have to be maintained for several years to come.
The Project in the Regional Context
3. At the time of appraisal, the allocation of generating capacity fromthe proposed project to individual supply authorities in the region had notbeen decided on. It is, however, expected that allocations will be roughlyin line with the present relative capacities of the participating authorities.In 1984/85, the first 400 MW of project capacity are to be made availableto the region. From 1985/86 onwards, the full 600 MW of the project willform part of regional capacity. At that time, this will be the equivalentof about 10% of unrestricted potential peak demand in the region, a significantcontribution to the easing of shortages.
4. In terms of energy supplied to the Eastern region grid from theproject, the following annual availability is projected:
1984/85 750 GWh1985/86 1,950 GWh1986/87 2,850 GWh
beyond 1987/88 3,300 GWh
At the maximum, this will represent about 8% of total regional unrestrictedenergy demand.
INDIA
FARAKKA THERMAL POWER PROJECT
Eastern Region
Inter System Exchange of Energy - 1978/79
(energy in Million kWh)
From BSEB DVC OSEB WBSEB DPL CESC APSEB UPSEB NEPAL TOTAL/To
BSEB - 196.95 62.73 25.30 - - - 14.28 7.68 306.94
DVC 146.16 - - 0.28 61.45 518.84 - - - 726.73
OSEB 379.03 - - - 11.33 - - 390.36
WBSEB - - - - 14.57 1,272.43 - - - 1,287.00
DPL - 84.74 - 266.47 - - - - - 351.21
APSEB - - 9.92 - - - - - - 9.92
UPSEB 32.80 - - - - - - - - 32.80
TOTAL 557.99 281.69 72.65 292.05 76.02 1,791.27 11.33 14.28 7.68 3,104.96
Source: EREB Reports
June 1979
OQ
ro
0 m-T
INDIA
FARAKKA THERMAL POWER PROJECT
Eastern Region
Non-simultaneous Maximum Peak Capacity Provided Between Authorities__(estimated) 1978/79 (MW)
\ ~~~~~~~~~~~~~~~~~~~~~~Total\ ~~To: Regional Outside
\ WSEB OSEB BSEB ~~~ ~~DVC CESC DPL Utilities Region
Provided by:
WBSEB n.a. - - - 280 60 340 -
OSEB - n.a. 230 - - - 230 20
BSEB - 80 n.a. 160 - - 240 10
DVC - - 120 n.a. 100 90 310 _
CESC - -- - - -
DPL 140 - - 100 - n.a. 240
Outside Region - 20 50 - - - 70 n.a.
n.a. = not applicable |
Source: EREB Reports Li
0June 1979
U,
In
Eastern RegionSchedule of Yearly Additions to Thermal Generating Capacity
From 1979-80 to 1987-88
(All figures in MW)State Projects Installed Additions to Installed Capacity 1984-85-
Capacity 1979-80 1980-81 1981-82 1982-83 1983-84 Total 1987-88
Bihar Pathratu-IV 2x110 - - - 220 - 220 -(Units 9, 10)
Barauni (Units 2x110 - - 110 110 - 220 -6, 7)
Muzaffarpur 2x110 - - - 220 220 -Tenughat 2x210 - - - - - - 420
DVC Durgapur (Unit 4) lx210 - 210 - - - 210 -Bokaro 'B' lx210 - - - - 210 210 -
Orissa Talcher 2x110 - 110 110 - - 220 -West Bengal Santaldih lx120 - 120 - - - 120 -
Bandel lx210 - 210 - - - 210 -Kolaghat 3x210 - - 210 420 - 630 -DPL Extn. lx11O - - - 110 - 110 -CESC 4x60 - - 120 120 240 -Gas Turbines 5x20 100 - - - - 100 -
Central Farakka 3x210 - - - - - 630Grand Total 100 650 430 980 550 2,710 1,050 9)
x
o I'sIhSource: CEA
April 1980 X
INDIA
FARAKKA THERMAL POWER PROJECT
Eastern Region
Schedule of Yearly Additions to Hydro Generating Capacity (approved as of March 1980)
Tr-o-M-197-80 to 1987-88
(All figures in MW)*
State Projects Type Installed Additions to Installed Capacity 1984-85-Capacity 1979-80 1980-81 1981-82 1982-83 1983-84 Total 1987-88
Bihar Subernarekha R lx65 - .65 - - - 65 -
(Unit 2)
DVC Panchet Hill R 1x40 - - - - 40 40 -
(Unit 2)
Orissa Rengali R 2x50 - - - - 100 100 -
Upper Kolab R 3x80 - - - - 80 80 160
Upper Indravati R 5x120 - - - - - - 600
West Jaldhaka, ROR 2x4 - - 8 - _ 8 -
Bengal St. II
Raman, St. II ROR 4x12.5 - - - - - 50
Central Koel Karo R 1x115 - - - - - - 115
Lower Lagyap ROR 2x6 12 - - - - 12 -
Grand Total 12 65 8 - 220 305 925
R - Reservoir 0
ROR - Run of the river U'
Source: CEAoQ
INDIA
FARAKKA THERMAL POWER PROJECT
Eastern RegionSales and Energy Data - 1974-75 to 1978-79
BIHAR
1974-75 1975-76 1976-77 1977-78 1978-79(Provisional)
Electricity Sold (GWh) 2,881 3,765 4,095 4,210 4,342
Proportion of Sales (%):
Agriculture & Irrigation 2.6 12.1 10.8 7.1 4.8
Railway Traction 11.8 10.6 9.8 10.2 8.8
Industry 76.0 69.0 71.3 73.5 77.0
Commercial & Government 3.7 3.0 2.8 3.1 3.1
Public Lighting 0.2 0.2 0.1 0.1 0.1
Domestic 3.9 3.4 3.6 4.0 4.1
Public Waterworks, Drainage etc. 1.8 1.7 1.6 2.0 2.1
Average Annual Growth of Sales (%) 7.2 30.7 8.8 2.8 3.1
Losses as % of the units sent out 25.1 18.4 19.8 18.0 n.a.
n.a. = not available >x
ooSource: Commercial Directorate, CEA
mw
Eastern RegionSales and Energy Data - 1974-75 to 1978-79
ORISSA
1974-75 1975-76 1976-77 1977-78 1978-79(Provisional)
Electricity Sold (GWh) 1,630 2,095 2,147 2,278 2,425
Proportion of Sales (%):
Agriculture & Irrigation 0.5 0.4 0.7 1.0 2.0 1
Railway Traction 3.3 3.4 3.7 3.5 3.3 L
Industry 87.5 88.0 86.4 86.1 84.8
Commercial & Government 2.7 2.7 2.6 3.0 3.4
Public Lighting 0.4 0.4 0.4 0.4 0.3
Domestic 3.0 3.0 3.4 3.7 4.0
Public Waterworks, Drainage etc. 2.6 2.1 2.8 2.3 2.2
Average Annual Growth of Sales (%) 4.6 28.5 2.5 6.1 6.5
Losses as % of the units sent out 11.4 13.9 15.4 14.4 n.a.
Source: Commercial Directorate, CEA
N
o
IDh
(D
Eastern RegionSales and Energy Data - 1974-75 to 1978-79
WEST BENGAL
1974-75 1975-76 1976-77 1977-78 1978-79(Provisional)
Electricity Sold (GWh) 5,095 5,503 5,857 5,729 5,969
Proportion of Sales (%):
Agriculture & Irrigation 0.8 0.9 1.7 1.1 1.7
Railway Traction 6.6 6.8 6.8 7.2 7.5
Industry 67.1 66.9 66.2 66.0 66.1
Commercial & Government 6.1 7.2 10.2 9.8 8.0
Public Lighting 0.8 0.8 0.7 0.8 0.8
Domestic 14.9 13.8 11.2 11.6 11.7
Public Waterworks, Drainage etc. 3.7 3.6 3.2 3.5 4.2
Average Annual Growth of Sales (%) 0.6 8.0 6.4 -2.2 4.2
Losses as % of the units sent out 9.0 11.9 11.2 12.7 n.a.
(D M
Source: Commercial Directorate, CEA0fh
April 1980
md
ANNEX A- 45 -
INDIA
FARAKKA THERMAL POWER PROJECT
Eastern Region
Power Supply Position
1976-77 1977-78 1978-79 1979-80(Actual) (Actual) (Provisional)
Installed capacity (MW) 4,395 4,505 4,747 5,254
Peak availability (MW) 2,440 2,435 2,342 3,024
Peak Load (MW) 2,440 2,435 2,342 3,441
Surplus/Deficit (MW) - - - (-)417
Energy availability (GWh) 15,148 15,270 15,281 17,564
Energy requirement (GWh) 15,148 15,270 15,281 19,895
Surplus/Deficit (GWh) - - - (-)2,331
1980-81 1981-82 1982-83 1983-84 1984-85
Installed capacity (MW) 5,794 6,014 6,994 7,763 8,393
Peak availability (MW) 3,271 3,459 3,839 4,463 4,911
Peak Load (MW) 3,763 4,105 4,450 4,850 5,318
Surplus/Deficit (MW) (-)492 (-)646 (-)611 (-)387 (-)407
Energy availability (GWh) 20,009 21,957 24,204 29,063 32,539
Energy requirement (GWh) 21,742 23,695 25,754 28,128 30,716
Surplus/Deficit (GWh) (-)1,733 (-)1,738 1,550 935 1,823
Source: CEA
* demand constrained by supply.
April 1980
ANNEX 5
- 46 -
INDIA
FARAKKA THERMAL POWER PROJECT
Eastern Region
Tentative Demand Forecasts 1984/85 - 1988/89
Peak Load (MW) Energy Requirement (GWh)
Region 1 Bihar West Bengal Orissa eagsiotnn Bihar West Bengal Orissa
1984/85 5,318 2,044 2,247 1,014 30,717 11,943 12,519 6,220
1985/86 5,800 2,250 2,419 1,117 33,502 13,157 13,457 6,848
1986/87 6,320 2,475 2,602 1,227 36,495 14,475 14,449 7,526
1987/88 6,878 2,718 2,795 1,347 39,712 15,907 15,498 8,257
1988/89 7,478 2,984 3,000 1,475 43,168 17,459 16,607 9,047
Source: Provisional CEA estimates
1/ Incl. Sikkim
April 1980
- 47 - ANNEX 6Page 1 of 4 Pages
INDIA
FARAKKA THERMAL POWER PROJECT
Financial Position of the State Electricity Boards and DVC
1. The problems associated with the SEBs' financial position have beenthe subject of continuing dialogue with GOI. Under previous transmissionCredits/Loan, the beneficiary SEBs undertook to achieve and maintain rates ofreturn after tax of 9.5% (on a rate base stated at actual cost), in some caseson a graduated basis, in order to take account of particular circumstances(see Attachment 1). In all cases the 9.5% rate was to be achieved by FY1979.Results have been moderately successful, with a wide variation in performancebetween SEBs. By FY1977, seven out of the sixteen major SEBs achievedtheir target rates of return, with a further two SEBs reaching their targetsin FY1978 with the help of rural electrification subsidies from their StateGovernments under the conditions of eligibility for the Second Rural Electri-fication Project (Credit 911-IN). Uttar Pradesh SEB expects to reach 9.5%in FY1979 mainly due to State Government rural electrification subsidizationcommencing in that year, again under eligibility criteria of Credit 911-IN.The other six SEBs, while not reaching the stipulated return, showed improvingtrends through FY1977. However, the situation generally deteriorated duringFYs 1978 and 1979 to leave seven out of the sixteen major SEBs with theirrates of return below the stipulated target. This group included two EasternRegion SEBs, Orissa and Bihar (which along with West Bengal SEB and the DVCwill be the recipients of Farakka power).
2. The main reason for the poor financial performance of some of theSEBs was that tariffs have not kept pace with increases in operating costs,thus not ensuring that a healthy ratio between operating income and capitalbase is maintained during periods of expansion. Other factors which haveadversely affected financial performance were: low availability of plant andof power imports from neighboring State systems, and increased cost of theseimports because of a higher proportion of expensive thermal power where pre-viously cheaper hydro power was available. It can be justifiably argued thatthe situation faced by some SEBs did not constitute "normal circumstances" andthat the achievement of covenanted rates of return could not realistically beexpected.
3. The financial performance of the Eastern Region SEBs and the DVC 1/was discussed with GOI and CEA officials during appraisal. The performance of
1/ Overall responsibility for power supply in the Damodar Valley area isvested in the DVC, a statutory body set up under the Damodar ValleyAct of 1948. The DVC operates power plants to meet the load demandsof the Damodar Valley area and also supplies bulk power to Bihar andWest Bengal SEBs and the Calcutta Electric Supply Corporation (CESC)to meet part of the power requirements outside the valley area.
- 48 - ANNEX 6Page 2 of 4 Pages
the DVC was an exception to the general trend. Over recent years, rates of
return (including duties and taxes) in excess if 20% were achieved, a credit-
able performance which is expected to be maintained in the immediate future.
It was pointed out to the mission that there were special problems associated
with the power industry in the Eastern Region which required special treatment.
This region was the most vulnerable area in India as regards power availability.
Installation of additional capacity lagged behind the performance of States in
other regions primarily because of a lack of financial resources. Some of
these States have contributed up to 40% of their expansion programs. The
States in the Eastern Region, particularly Bihar, have, in the past, lacked
the financial resources for larger investment in power facilities and Bihar
has its own particular problems in organizing its electricity industry to meetthe growing demand.
4. Bihar has one of the lowest per capita incomes in the whole country
and a high unemployment rate. Projections received from the Bihar SEB for the
three years up to March 31, 1983 (Annex 6, Attachment 2) indicate that a rate
of return of less than 2% will be achieved. This performance has been viewedwith great concern both at Center and State levels. The matter has been taken
up with the Bihar State authorities at the highest levels to see how improve-
ments can be introduced. It is recognized that the conditions in the Bihar
SEB are somewhat different from most other Boards in the country. Generating
stations have had operational problems which have curtailed electricity output.
The Bihar SEB, as well as the State Government, have been advised and assistedby the Center in studying these problems further. In addition, CEA has been
made responsible for monitoring the progress of these studies with a view
to the introduction of an action plan for overall improvement. A number of
problem areas requiring special attention have already been identified, more
particularly those relating to professional management, procurement of spare
parts, training and project implementation. In the circumstances, the imme-
diate restoration of the covenanted rate of return of 9.5% cannot realisticallybe expected. Indeed, the introduction of any financial rehabilitation program
must first await the outcome of the investigations currently going on in Bihar.
In the meantime, CEA will keep the Bank Group advised of developments in these
endeavors. A formal report on the position of the Bihar SEB will be sent to
the Bank Group within the next six months.
5. The following is the position with regard to the other two SEBsin the Eastern Region:
Orissa: The rate of State electricity duty charged to con-sumers is extremely high in comparison to the generalnorm, being equivalent to as much as 5% of capital base,as against a target of 1.5%. Consequently, if the
gross economic return is compared with the target of11% (including duties) the annual projections through
FY1983 (Annex 6, Attachment 2) show that the targetwill be exceeded by 1.9 percentage points in FY1981,3.0 percentage points in FY1982 (when the covenantedrate of return of at least 9.5% will also be achieved)
and 2.5 percentage points in FY1983. This performanceis considered as satisfactory, considering the periodic
- 49 - ANNEX 6Page 3 of 4 Pages
low availability of hydro power in recent years inwhat is a predominantly hydro system, coupled withchronic low availability of some thermal plant--acombination of events which led to low generation andconsequently reduced sales and revenues.
WestBengal: The Board achieved its covenanted rate of return (un-
audited) of 9.5% in FY1979. However, because of thedoubling of installed capacity projected during thethree years to March 1983 and the phased build up tostabilised generation of the new plant, additionalrevenues will not be received in proportion to increasesin capital base. Consequently, rates of return projectedfor the four years ended March 1983 (Annex 6, Attachments1 and 2) of from 7.0% rising to 9.3% must be regarded asreasonable. The mission was informed that efforts arebeing made to complete modifications and improvementsin existing installed capacity in order to improve avail-ability factors and boost revenues. The Bank Group willbe kept advised of developments.
6. Recognizing the need to improve the financial performance of theEastern Region SEBs in a comprehensive manner, GOI, through CEA, held dis-cussions with the State Governments and their SEBs in November 1979. Therewas general consensus that concerted efforts were necessary to improve thefinances of the Boards. Agreement was reached on the introduction of thefollowing measures:
(i) SEBs would prepare accounts half yearly, the results to bemonitored by both the Sate Government at higher levels andalso by CEA;
(ii) a monthly reporting system by SEBs and Central agencies onproject implementation would be reactivated;
(iii) targets for reducing transmission end distribution lossesand auxiliary consumption;
(iv) a system of accountability would be enforced for non-performance of targets; and
(v) CEA would issue guidelines and would review financialperformance every six months.
The introduction of the above measures would go a long way towards bringinggreater control over the financial management of SEBs. CEA will keep theBank Group advised of progress in their implementation.
- 50 -
ANNEX 6Page 4 of 4 Pages
7. The financial provisions of the Electricity (Supply) Act, 1948, wererecently amended to put the operations of the SEBs on a more commercial basisby enabling them to generate internally a reasonable contribution to theircapital investments. Under the Amendments (Section 59(1)), the State Govern-ments are now required to specify the level of annual surplus which should beearned by their SEBs to enable them to comply with the amended legislation.The manner in which this will be achieved is a subject which has been underevaluation by both the State Governments in conjunction with their SEBs, andby the finance panel of the Rajadhyaksha Committee. Complex issues are involvedwhich will require "tailoring" by each State Government to meet the particularcircumstances of its SEB, while at the same time giving due consideration toState resources and impact on consumers. CEA has issued guidelines to theState Governments and the SEBs explaining these issues and pointing out themeasures that need to be taken by each of them and the options which areavailable.
8. The guidelines emphasize the following aspects:
(i) special steps to increase sales volume;
(ii) economies in both operating costs and capital expenditure;
(iii) more efficient asset utilization;
(iv) timely commissioning of new projects;
(v) reduction in line losses;
(vi) improved financial management;
(vii) tariff revisions to reflect cost of supply;
(viii) capital structure adjustments - SEBs may now receive funds fromthe State Government in the form of share capital, and StateGovernment loans may now be converted into share capital;
(ix) disposal of arrears of State Government loan interest; and
(x) basis for charging depreciation of fixed assets.
9. Because of the far reaching consequences of the above measures, theState Governments and their SEBs are awaiting the findings of the RajadhyakshaCommittee before implementing financial policies to give effect to the financialamendments of the Electricity (Supply) Act, 1948. The Committee's report isexpected to be presented to the Government in May 1980.
INDIA
Farakka Thermal Power Project
I/Rates of Return-/ of SEBs FY 1976 - FY 1980
FY 197t FY 1977 FY 1978 FY 1979 FY 1980(Actual) (Actual) (Actual) (Estimated) (Expectation)
Return to Return incl. Return to Return incl. Return to Return incl.| Return to Return incl. Return to Return incl.SEBs SEB State Duties SEB State Duties SEB State DutiesJ SEa State Duties SEB State Duties
Andhra Pradesh 7.7 7.7 9.0 9.0 9.5 9.5 9.5 9.5 9.5 9.5
Assai 6.4 7.4 12.3 13.9 10J.)F 11.5F 2.0 3.4 NA NA
Bihar 7.0 8.5 8.1 9.5 8.0 9.4 1.4 2.6 1.4 2. 4
Guharat 7.9 11.0 9.7 13.9 9.5 13.5 9.5 13.5 9.5 13.3
Haryania 7.2 11.4 6.4 10.9 6.6 10.6 lO.OA 14.4A 9.5 13.5
Maharashtra 10.0 11.5 13.0 14.5 -15.3 16.8 14.2A 15.7A 9.5 11.0
Punjab 7.4 10.1 8.2 11.4 9.5 11.9 9.5A 11.9A 9.5 11.6
Rajasthan 8.7 9.9 9.2 10.5 7.9 9.0 j 8.6 9.6 9.5 10.5
Uttar Pradesh 4.6 5.4 5.8 6.6 0.9 1.6 9.5 10.1 9.5 10.1
West Bengal 6.0 8.0 9.5 11.1 9.4 11.0 9.5 11.1 7.0 8.5
Delhi ESU (14.7) (9.6) 7.6 12.9 7.6 14.7 4.6 14.5 9.5 15.4
Kerala 5.9 8.1 8.5 10.5 8.0 9.9 7.5 9.5 8.7 10.7
Madhya Pradesh 12.8 15.4 13.1 15.3 14.7 16.7 11.2 13.2 9.5 11.5
Karnataka 10.0 14.9 15.8 20.7 8.3F 12.6F 7.1 11.0 NA NA
Orissa 5.8 9.1 6.3 9.9 4.8 9.1 4.9 9.9 4.9 9.7
Tamil Nadu 9.7 10.4 9.5 10.3 9.5 10.3 9.5 10.2 9.5 10.2
INDEX
F -Forecast
A =ActualNA =Not Available
1/ Target rate of return in general is 9.5%. When this was established in 1964, it was also conceived that an average excise taxor duty equiivalent to a return of 1.5% would be applied, making the total expected return 11%. Effective March 1978, GOI has
levied an additional excise tax of 2 paise/kWh of generation which is not included above. This would add an estimated 2-3percentage points to the returns noted.
INDIA
FARAKKA THERMAL POWER PROJECT
Projected Rates of Return of Eastern Region SEBs and the DVC for FYs 1981 through FY1983
FY1981 FY1982 FY1983
SEBs Return to Return incl. Return to Return incl. Return to Return incl.SEB State Duties SEB State Duties SEB State Duties
& Central & Central & CentralExcise Tax Excise Tax Excise Tax
Bihar 1.5 3.4 1.6 3.4 1.2 2.8
Orissa 8.2 15.6 9.9 17.1 9.5 - 16.3 I/
West Bengal 7.1 10.5 8.0 11.2 9.3 12.3
DVC 18.3 23.6 19.2 23.9 16.5 - 20.6
-/ Reduction in return is due to a large increase in capital base for that year because of the commissioning ofnew plant, not compensated by increased revenues until the plant is fully stabilized (normally takes 3/4 years).
- High return due to relatively low capital base and because of the impact of additional revenue earning activities.
rr Mrt
rt
INDIAFARAKKA THERMAL POWER PROJECT
NATIONAL THERMAL POWER CORPORATiON LIMITEDOrganization Chart
CHAIRMAN&
MANAGINGDIRECTOR
MANAGEMENT COMMITTEE
PROJECT REVIEW TEAMS
_ _ ~~CORPORATf COHPORATE'
P LANN ING COMPAN Y ADMNISRASOINNELMARKETING SEcReTARY & TRAINING
'TECHNICAL OTRCSERVICES SRIE
DIVISION
OIUALITY
CONTRACTS ASSURANCE &.___ ____ _ I EXPEDITING
eADARiPtfl SINGH RAUI IKURBA RAMAGU;NDAM FARAKKA TRANSMISSION
THIERMAL POWER THERMAL TIIERMAL THEHAMAL THEfMAL SYSIEMS o
SI ATION/PROJECT POWER PROJECT WOWER PROJECT POWER PVtEJI( T POWtR PIROJECI DIVISION j
Wolid Bi&uik 206&J9In
INDIAFARAKKA THERMAL POWER PROJECT'
NATIONAL THERMAL POWER CORPOiRATION LIMITEDProject Organization
GENERAL
MANAGER
4~~GIN~PANNNG SYTM
MATEIL SERVICES CIVIL fINANCE & EQUIPMUENT PRONNELiMANAGEMET _ CONSTRUCTION ACCOUNTS ERECTION 6 ADMIN.
FIELD ENGINEEHING
1_ -1 _ f IELi) ENGINE~~~~~~~~ERING
POWER C. SYSTEM OFF-SITES TOWNSECONTHVIL
H_ _
FW i | It 7 I CONTRCOL| COALT| @L
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Wadid Diank 20640
INDIAFARAKKA THERMAL 'OWER PROJECT
NATIONAL TIHERMAL POWER CORPORATION LIMITEDTechinical Sorvices Division
G( NERALMANAGEl1
(UNG N E NE NNG)
SEliVICESVICE
11GMT. , ~~~~~~~~~CO -ORDOS.
2~~~~~~~~~~~~~" Xr- mm &; 1= > @
CONTfillVAITCtESN A L v Xl e v 1 IAIANSMISSION ' m M CONSTIICTIONSEfRVICES DESIGN TIN LS;IGN COORDINATION DL;IGN ENGINELNtINGJ SEVI
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FARARK THER1AL POWER PROJECTNATIONAL THERMAL POWER CORPDRATION LIMITED
ORGANIZATION CHART 1979-RDC- -IIA FflimCRCOT,
0
X X ' ouRsos~~~~~~~~~~~~~~~~~~~
W W D~~~~~~~~~~~~~~~~~~~~
|| I~~~~~
EWl E ~~~~~~~~~~~~~~~~~
101 11 , 10 1 0 E O
ANNEX 8_57 - Page 2 of 2 pages
INDIAFARAKKA THERMAL POWER PROJECT
NATIONAL THERMAL POWER CORPORATION LIMITEDORGANIZATION CHART 1979-80
Finance and Accounts Department Farakka Thermal Power Station Site
NUMBERSCFM
and
Accounts
0~~~~~~~~~~
.~~~~~~~~~~~0Sr A=
and B anddBooksI|
LIE ~ ~ ~ ~~~i
S,AO Sl,o A-Ot O|ie P.,. AAO.,
Fiance | Bills lConcurrence Ac-cc-t
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Acce r Il
and PFerc 0iClaeinrs_
INOEX NON-SUPER\/ISORY STAFF
CFM. Chief Finance Manager nsraAcian 1SrAO- Senior Accocots Officer 5 ;o is:c 2(i
Sr Acne: Senior Accounce,'t Assistant 1Acer: Accounantnennet TTL-1 Jr Acct Junior Accountant
World eank -20646
- 58 - ANNEX 9Page 1 of 3 Pages
INDIA
FARAKKA THERMAL POWER PROJECT
Description of the Farakka Development
1. The Farakka development is one of a series of large thermal powerstations planned by the Government of India, to feed into a 400 kV inter-connected transmission system and supply bulk power to the State ElectricityBoards (SEBs).
2. The Farakka 1,100 MW power station is to be installed on the WestBank of the Farakka feeder canal and will utilize coal from the Hurra blockof mines of the Rajmahal coal fields in Bihar.
3. The plant will consist of three 200 MW and one 500 MW generatingunits with boiler plant, ancilliary electrical and mechanical equipment andassociated 400 kV transmission. The Project, which represents the first stageof the development, will consist of the three 200 MW installations.
4. The 200 MW turbines will be thre2 cylinder, tandem compound type
with initial steam conditions of 150 kg/cm and 535 0 C. The generators willbe hydrogen cooled and will each be rated at 235,300 kVA. The boilers willbe natural circulation, pulverized fuel fired, balanced draft type using thedirect firing system. Each boiler will have a continuous evlporation rating
of 670 t/h with a superheater outlet pressure of 155.5 kg/cm and temperatureof 540 C. Each 200 MW generating unit will be connected to a 250 MVA trans-former and will feed power into the 400 kV system.
4. The 500 MW turbine will be three cylinder reheat condensing typehaving one HP cylinder, one double flow IP cylinder and one double flow LPcylinder with initial steam parameters of 168 kg/cm and 538 0C/538 C. Thegenerators will be water and hydrogen cooled, each rated at 588 MVA. Theboiler will be controlled circulation, pulverised fuel fired, balanced drafttype using the direct firing system. The boiler will have a continuousevaporati n rating of 1,700 t/h with a superheater outlet pressure of178 kg/cm and temperature of 540 0C. Each generating unit would have 4 singlephase 200 MVA 21/400 kV transformers and will feed power into the 400 kV system.
5. The salient features of the development are shown below: -
- 59 - ANNEX 9Page 2 of 3 Pages
POWER STATION
Capacity - 1,100 MW (3x200 MW + lx500 MW)
Fuel - Coal from the Hurra Block of Rajmahalcoalfields, located about 50 km fromthe power station. Consumption of the1,100 MW power station at 5,500 h of oper-ation per year is about 4 million t/year.The average calorific value of the coal is3,600 kcal/kg; moisture 3.7-10.1%; ash 19.7-44.5%; sulfur 0.3-1.5%.
Transport - Unit train continuous system with bottomof Coal discharging wagons.
Cooling System - The power station's requirements of coolingwater are proposed to be met from the Fasakka
feeder canal with a flow exceeding 575 m(20,500 cu ft)/sec. As there is an abundanceof water available from the canal compared tocooling water requirements, the power stationwould be designed for once-through cooling.The estimated requirements of cogling waterfor the 1,100 MW station is 45 m (1,600 cuft)/sec, almost all of which would be re-turned to the canal. The consumptive waterrequirements for boiler make-up and townshipwould be comparatively small. Water willflow from the feeder canal through a channelup to a pump house where it will be pumpedto the power house. Provision is allowedfor a second stage pump house, in line withthe first stage, which may be constructedlater. After cooling the condensers, thewater will be discharged into a channelthrough a discharge duct and lead back intothe feeder canal at a point approximately1.5 km downstream of the intake, where asuitable diffusion device will be provided.Temperature of the water in the feeder canal,will rise 2-30C as a result of this, but itwill gradually cool down to about its orig-inal temperature as it flows from there.
- 60 - ANNEX 9Page 3 of 3 Pages
Ash Disposal - The ash disposal area is available approxi-mately 6.5 km from the power station site.Ash would be pumped as a slurry through apipeline. Skimmers would be provided toobtain relatively ash free water from thedisposal area which would overflow tonatural drainage.
Land - A total area of approximately 1,175 ha(2,900 acres), excluding land for the coaltransportation system, is required for theproject. This includes about 290 ha (720acres) for the power station, switchyard,coal storage etc. and 120 ha (300 acres) forthe residential colony. An area of about750 ha (1850 acres) would be acquired forash disposal.
TRANSMISSION
400 kV lines first stage - (Farakka-Durgapur : 165 circuit kmrequired (600 MW) (Farakka-Jeerhat : 245 " "
second stage Farakka-Mokamah : 230 " iAlso associated switchgear, telemetry andmetering equipment, land, buildings andother miscellaneous works.
- 61 - ANNEX 10Page 1 of 2 pages
INDIA
FARAKKA THERMAL POWER PROJECT(3 x 200 MW)
Project Cost Estimates
Rupee million US$ million equivalentLocal Foreign Total Local Foreign Total
1. Preliminary WorksLand 13.8 - 13.8 1.6 - 1.6Land Development 59.3 - 59.3 7.1 - 7.1Road and Railway 23.9 - 23.9 2.8 - 2.8Miscellaneous 1.0 - 1.0 0.1 - 0.1
Total 98.0 - 98.0 11.6 - 11.6
2. Civil WorksBuildings, Foundation, etc. 346.9 8.8 355.7 41.3 1.0 42.3Residential and others, etc. 162.8 - 162.8 19.4 - 19.4
Sub-total 509.7 8.8 518.5 60.7 1.0 61.7Physical Contingencies 51.0 0.9 51.9 6.1 0.1 6.2Price Contingencies 208.6 3.5 212.1 24.8 0.4 25.2
Total 769.3 13.2 782.5 91.6 1.5 93.1
3. Electrical & MechanicalTurbogerators andBoilers 900.5 173.9 1,074.4 107.2 20.7 127.9
Other Equipment 189.8 36.6 226.4 22.6 4.4 27.0Electrical Equipment 258.1 50.0 308.1 30.7 6.0 36.7Miscellaneous Tools
& Plant 12.6 5.3 7.9 1.5 0.6 2.1Sub-total 1,361.0 265.8 1,626.8 162.0 31.7 193.7
Physical Contin-gencies 68.1 15.3 83.4 8.1 1.8 9.9
Price Contingencies-Turbogenerators &
Boilers 221.5 50.3 271.8 26.4 6.0 32.4-Other Equipment 222.4 51.5 273.9 26.5 6.1 32.6
Total 1,873.0 382.9 2,255.9 223.0 45.6 268.6
4. Coal Handling &Transportation
Wagons 17.4 6.7 25.1 2.1 0.8 2.9Locomotives 26.6 6.8 33.4 3.2 0.8 4.0Coal HandlingEquipment 116.9 7.2 124.1 13.9 0.9 14.8
Workshop andMiscellaneous 22.9 11.7 34.6 2.7 1.4 4.1
Sub-total 183.8 32.4 216.2 21.9 3.9 25.8Physical Contingencies 9.2 1.6 10.8 1.1 0.2 1.3Price Contingencies 98.7 10.6 109.3 11.8 1.2 13.0
Total 291.7 44.6 336.3 34.8 5.3 40.1
- 62 - ANNEX 10Page 2 of 2 pages
Rupee million US$ millionLocal Foreign Total Local Foreign Total
5. TransmissionFarakka-Durgapur 78.3 10.3 88.6 9.3 1.2 10.5Farakka-Jeerhat 111.0 14.5 125.2 13.2 1.8 15.0Associated SubstationEquipment 29.1 4.2 33.3 3.5 0.5 4.0
Tools & Miscellaneous 4.2 - 4.2 0.5 - 0.5Subtotal 222.6 29.0 251.6 26.5 3.5 30.0
Physical Contin-gencies 11.1 1.5 12.6 1.3 0.2 1.5
Price Contin-gencies 77.5 9.6 87.1 9.2 1.2 10.4
Total 311.2 40.1 351.3 37.0 4.9 41.9
6. Training Simulator 0.8 24.4 25.2 0.1 2.9 3.0Physical Contingencies 0.1 1.6 1.7 - 0.2 0.2Price Contingencies 0.8 14.3 15.1 0.1 1.7 1.8
Total 1.7 40.3 42.0 0.2 4.8 5.0
7. Engineering & Administration 252.0 1.3 253.3 30.0 0.2 30.2
8. Total Project Costbefore duties & taxes) 3,595.2 482.1 4,077.3 428.2 62.3 490.5Duties & Taxes 75.0 - 75.0 8.9 - 8.9
9. Total Project Cost 3,670.2 482.1 4,152.3 437.1 62.3 499.4Interest DuringConstruction 233.0 - 233.0 27.7 - 27.7
10. Total FinancingRequired 3,903.2 482.1 4,385.3 464.8 62.3 527.1
Notes: Physical Contingencies: 10% on civil works5% on plant and transmission costs
Price Contingencies: 6% for 1979, 10% for 1980, 7% for the years1981-83 and 5% for the years after 1983.
INDIARAKADA 7IIDTM.AL RIAWI PAOJAEr
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VESI"N h FNKALN SATION RAnoIllARy 20% STUBTgNDgB0INO _ __ / SURVEY SYTTINGO
hPit FILING .EOIERRS4 _____
AWARD OF CONTRACT STRSNIIRI~~~~~~~~~~~~~PPIVA O ERT
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OONLUOCTUR WI>f REFAhT &iR -- TN F PROVWAL OFCNUCO FRmH WIRE
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AWARD LONCT ~~~~~~~~~~~~~~~INSPECTINTlSO. lINPFACTURE & RENPT. & APPROVAL INSALA J
OF INSUSTDRS 0 R_ OF _
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IN
- 65 -
ANNEX 12
INDIA
FARAKKA THERMAL POWER PROJECT
ESTIMATED SCHEDULE OF DISBURSEMENTS
DisbursementsIDA Fiscal Year Cumulative US$and Half-Year million equivalent % Undisbursed
1980
December 31, 1980 - 100June 30, 1981 20 92
1981
December 31, 1981 35 86June 30, 1982 85 66
1982
December 31, 1982 140 44June 30, 1983 170 32
1983
December 31, 1983 180 28June 30, 1984 185 26
1984
December 31, 1984 190 24June 30, 1985 210 16
1985
December 31, 1985 220 12June 30, 1986 235 6
1986
December 31, 1986 240 4June 30, 1987 250 0
INDIA
FARAKKA TH ;'MAL POWER PROJECT
National Thermal Power Corporaticn Limited
Incom Statement Covering Operations - FY1982 through FY1991 (Forecast)
(in millions of rupees except where otherwise stated)
Year to March 31 1982 1983 1584 1985 1986 1987 1988 1989 1990 199-
Total Sales of &Eergy (GWh) 73.0 969.0 3,298.0 6,683.0 10,349.0 14,380.0 19,340.0 25,304.0 30,446.0 33,618.0Average Revenue - Bulk Supply
- Paise per kWh 29.08 29.08 29.08 29.08 29.08 29.08 29.08 29.08 25.08 29.08- Fuel Surcharge (paise per kWh sold) - 0.350 0.712 1.116 1.397 1.773 2.175 2.615 3.197 3.750- Central Olcise (paise per kWh sentout) 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0
Operating Revenue:Sales - Bulk Supply 21.2 281.8 959.0 1,943.1 3,005.4 4,181.7 5,624.1 7,358.4 8,853.7 '.,776.1Sales - Fuel Surcharge - 3.4 23.5 71.6 141.6 255.0 421.4 661.7 973.5 1,260.9Central Excise 1.5 19.9 67.6 137.1 212.3 295.0 356.7 519.1 621.6 689.8
Total Operating Revenue 22.7 305.1 1,050.1 2,155.1 3,366.3 4,731.7 6,442.2 8,535.2 10,451.8 11,726.8
Opeati Eenses:Generation - Singrauli - Fuel 4.2 49.0 127.5 212.8 271.3 375.5 406.1 508.9 541.5 552.4
- Fuel Surcharge - 3.4 18.5 47.9 77.7 125.0 169.8 236.5 305.1 3541.- 0 & M 6.0 61.o 93.0 107.0 117.0 175.0 215.0 215.0 219.0 219.0- Depreciation - 63.0 99.0 132.0 132.0 223.0 395.0 305.0 305.0 305.0
Korba - Fuel - 8.1 71.9 141.8 191.9 252.2 355.1 197.5 621.1 695.3- Fuel Surcharge - - 5.0 20.6 3':.4 66.2 115.6 154.9 287.9 371.6- 0 & M - 11.0 70.0 81.0 81.0 111.0 167.0 232.0 268.0 26 8.0 - Depreciation - - 68.o 105.0 105.0 105.0 189.0 278.0 391.0 351.0
Ramagundam - Fuel - - 7.1 87.4 189.6 266.4 381.1 542.1 752.9 908.1- Fuel Surcharge - - - 6.1 23.4 47.9 102.8 163.0 279.9 399.9- 0 & M - - 8.0 66.o 90.0 90.0 132.0 185.0 2h8.0 264.0- Depreciation - - - 62.0 112.0 112.0 112.( 199.0 280.0 383.8
Farakka - Fuel - - - 11.5 81.6 155.1 210.2 312.1 363.0 396.8- Fuel Surcharge - - - - 1.1 15.9 33.2 67.3 100.3 135.0- 0 & M - - - 19.0 87.0 97.0 97.0 167.0 167.0 167.0- Depreciation - - - - 72.0 119.0 119.0 228.0 228.0 228.0
Transmission - 0 & M 1.9 2.9 8.5 17.5 25.2 28.7 31.5 32.1 32.1 32.1- Depreciation 1.2 10.6 26.9 65.2 111.0 112.0 153.1 160.8 160.8 160.8
Central ERcise ( 2 Paise/kWh of EnergySent Out 1.5 19.9 67.6 137.1 212.3 2c5.o 396.7 519.1 621.6 685.8
Total Operating Expenses 11.8 231.9 671.0 1,322.9 2,022.5 2,801.9 3,695.8 5,047.3 6,178.5 6,921.2
Operating Income (before interest) 7.9 70.2 379.1 832.2 1,310.8 1,2 1 .8 2,746.1 3,191.5 4,272.9 1,805.6
Less: Interest on Loans 13.0 132.0 501.0 1,101.0 1,718.0 2,067.0 2,210.0 2,162.0 2,072.0 1,851.0Deduct: Interest Capitalized 12.0 108.0 327.0 630.0 894.o 878.0 663.0 219.0 62.0
Net Interest Chargeable to Operations 1 21 171 471 821 1,189 1,597 1,513 2,010 1,851
Profit 6.9 46.2 205.1 361.2 516.8 740.8 1,199.4 1,578.5 2,262.9 2,995.6
Write off Deferred Ehpenses - 6.o 5.0 - _ _
Farnings 6.5 10.2 200.1 361.2 516.8 740.8 1,199.1 1,578.9 2,262.5 2,554.6
Averaae Rate i3ase5- 1,105.0 9,188.0 14,7i590 19,9"7.0 25,124.0 30,058.0 36,753.( I,2,021.t) 42,261.0Rate o(Retum tOperating Income before
Interest as % of Average Rate Base) - 1.6 5.1 5 .7 6.7 7.7 ' .1 9.5 10.2 11.1Operating Ratio (Operating Expenses as %
of Operating Revenue) 65.1 77.0 63.9 61.4 60.1 59.2 57.1 59.] 59.1 55.o
Source; NTPC March 1980
I!DIA
FARAKXA THM1,AL POWSi PROJECT
NIational Thenral Power Corporation Limited
Statement Showing Canacity of Plant, Generation and Sales of lhergy
Year to March 31 1982 1983 19814 1985 19.86 1587 1988 1989 1990 1991 1992 1993 1994
Capacity - Singrauli MW 200 600 1,000 1,000 1,500 2,000 2,000 2,000 2,000 2,000 2,000 2,000 2,000- Korba MW - 200 60c 600 600 1,100 1,600 2,100 2,100 2,100 2,100 2,100 2,100- Ramagundam MW - - 200 600 600 600 1,100 1,600 2,100 2,100 2,100 2,100 2,100- Farakka MW - - - 200 600 600 600 1,100 1,100 1,100 1,100 1,100 1,100
Total MW 200 800 1,800 2,400 3,300 4,300 5,300 6,800 7,300 7,300 7,300 7,300 7,300
Generation - Singrauli GWh 83 967 2,516 4,199 5,357 7,083 8,959 10,125 10,791 11,000 11,000 11,000 11,000- Korba adn - 125 1,117 2,200 3,025 3,925 5,550 7,800 9,800 10,925 11,425 11,650 11,550- Raagundam GWh - - 83 967 2,099 2,949 4,238 6,050 8,425 10,175 11,113 11,488 11,550- Farakka GWh - - - 167 1,184 2,250 3,o50 1,550 5,300 5,800 6,050 6,o50 6,050
Total OWh 83 1,092 3,716 7,533 11,665 16,207 21,797 28,525 34,316 37,900 39,588 40,088 40,150
Station Use - Singrauli GWh 8 87 226 378 482 637 806 Cll 971 S90 990 990 990- Korba GWh - 11 100 158 272 353 500 702 882 983 1,028 1,040 1,0140- Ramagundam GWh - - 8 87 189 266 381 545 758 916 1,000 1,034 1,040- Farakka GWh - - - 15 107 203 275 410 477 522 54 515 545
Total GWh 8 C8 334 678 1,050 1,1455 1,962 2,568 3,088 3,411 3,563 3,605 3,615
Energy Sent Out - Singrauli GWh 75 880 2,290 3,821 4,875 6,14146 8,153 9,214 9,820 10,010 10,010 10,010 10,010- Korba GWh - 114 1,017 2,002 2,753 3,572 5,050 7,o94 8,918 9,942 10,3S7 10,510 10,510- Ramagundam GWh - - 75 880 1,910 2,683 3,857 5,5o5 7,667 9,259 10,113 10,454 10,510- Farakka GWh - - - 152 1,077 2,o47 2,775 14, 10 4,823 5,278 5,505 5,505 5,505
Total GWh 75 9SI, 3,382 6,855 10,615 14,748 15,835 25,953 31,228 34,489 36,025 36,1479 36,535
Transmission - Singrauli GWh 2 22 57 96 122 161 204 230 246 253 250 256 250Losses - Korba GWh - 3 25 50 69 89 126 177 223 251 259 262 262
- Ramagundam GWh _ _ 2 22 48 67 96 138 192 234 253 261 262- Farakka GWh - - - 4 27 51 69 104 121 133 138 138 138
Total GWh 2 25 84 172 266 368 495 6149 782 871 900 911 912
&lergy Sales - Singrauli GWh 73 858 2,233 3,725 4,753 6,285 7,945 8,981, 5,574 9,757 9,760 9,760 9,760- Korba GWh - 111 992 1,952 2,6814 3,483 4,924 6,917 8,695 9,691 10,138 10,248 10,248- Ramagundan GWh - - 73 858 1,862 2,616 3,761 5,367 7,475 5,025 9,860 10,193 10,2148- Farakka GWh - - - 148 1,050 1,996 2,706 4,036 4,702 5,145 5,367 5,367 5,367 a si
Total GWh 73 969 3,298 6,683 10,349 14,380 19,31,0 25,304 30,446 33,618 35,125 35,568 35,623__
Station use as % of generation 9 9 9 9 9 9 9 9 9 9 S 9 9Transmission losses as % of generation 2.3 2.3 2.3 2.3 2.3 2.3 2.3 2.3 2.3 2.3 2.3 2.3 2.3
Source: NTPC March 1980
INDIA
FARAIKA ThEMSAL POWER PROJECT
National Thermal Power Corporation Limited
Source and Application of Funds for FY1977 through Fi1979 (Actual) and for FY1980 through Ff1991 (Forecast)( in millions of rupees)
h ------- A C T U A L-F---- 0__R____C__A_S___------------------------------ 0 R Z C A S T-Year to March 3 1977 1978 1979 1°80 1981 1S82 1983 1584 1985 1986 1587 1588 1989 1950 1991
Source of FtindsInternal Cash Generation
Operating Income (before Interest) - - - - - 7.9 70.2 379.1 832.2 1,340.8 1,929.8 2,746.4 3,4901.9 14,272.5 146807.6Depreciation - -_ _ _ 1.2 73.6 193.9 364.2 532.0 701.0 878.84 15170.8 1.364.8 1467.8
Total - - - - - S.1 143.8 573.0 1,196.4 1,872.8 2,630.8 3,624.8 4,662.7 5,637.7 6,273.4
LoansODI Loans _ _ _ _ 260.0 2,108.0 5,198.0 6,492.8 4,512.5 2,521.2 1,028.2 - _ _
EAuity0II Subscriptions 34.3 224.3 702.4 1,622.0 3,227.0 8,002.0 5,675.6 2,471.4 - - - - - -
Total Sources 34.3 224.3 702.4 1,622.0 3,227.0 8,271.1 7,S27.4 8,242.4 7,685.2 6,385.3 5,152.0 4,653.-0 4,662.7 5,637.7 7,273.4
Aoolici of FunidsCapit Ecpenditure (including interest
during construction) 7.1 225.1 658.6 1,622.0 3,227.0 8,262.0 7,895.0 7,962.0 7,095.0 5,434.0 3,427.0 1,591.0 657.0 222.2 -Debt Service:
Interest Chargeable to Revenue - - - - - 1.0 24.0 174.0 471.0 82).0 1,189.0 1,547.0 1,913.0 2,010.0 1,891.0Amortization of Loans - - - - --OO.0 858.( 1.558.0 1.611.0 1,611.0
Total - 1.0 2)4.0 174.0 L71.0 824.0 1,589.0 2,105.0 3,511.0 3,621.0 3,162.0
Preliminary Deferred Expenses 2.2 1.3 2.0 2.0 2.5 1.0 - - -Sho.t Term Deposits _- - 500.0 286.1 1,664.6 2,756.3Working Capital Increase/(Decrease) 25.0 (2.1) 1.8 (2.0) (2.5) 7.1 58.1, 106.1, 123.2 127.3 136.0 157.0 206.6 12'.9 55.1
Total Applications 3L.3 224.3 702.4 1,622.0 3,227.0 8,271.1 7,927.)4 8,2)2.2 7,68S.2 6,385.3 5,152.0 4,653.0 4,662.7 5,637.7 6.273.)
Debt Service Coverage _- - - 9.1 6.0 3.3 2.5 2.3 1.7 1.5 1.3 1.6 1.8
Source: NTPC March 1980
INDIA
FARAKKA IT31M3AO POWER PROJECT
National Thermal Power Corporation Limited
Investment Program Covering F1977 through FY1990(in millions oi' rupees)
Year to March 31 1977 1978 1979 1980 I981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1977-1990
Power Stations
Singrauli 7 197 296 714 1,271 2,297 1,955 1,575 752 496 280 - - - 9,840Korba - 15 281 301 802 2,468 1,915 2,229 1,873 1,309 751 414 223 - 12,576Ramagundam _ - 50 363 427 1,677 1,418 1,515 2,108 1,807 1,475 839 439 213 12,326Farakka - - 4 99 400 977 1,216 1,079 1,120 1,289 848 338 - - 7,360
Total Power Stations 7 212 631 1,472 2,900 7,419 6,504 6,393 5,853 4,896 3,354 1,591 657 213 42,102
TransmissionsAssociated with:
Singrauli - 13 73 115 119 282 476 532 916 123 - - - - 2,149
Korba - - - 31 139 265 372 313 290 113 - - - - 1,523
Ramagundam - _ _ 3 73 235 391 499 366 227 73 - - - 1,812Farakka - - - 1 - 61 152 230 170 75 - - - - 689
Total Transmission - 13 73 150 331 843 1,341 1,569 1,242 538 73 - - - 6,173
Total Construction Program 7 225 704 1,622 3,231 8,262 7,895 7,962 7,095 5,434 3,427 1,591 657 213 48,275
Source: NTPC March 1980
-ma
INDIA
FARAKKA ThERMAL POWER PROJECT
National Theemal Power Corporation Limited
Condensed Balance Sheets as at the end of FY1977 through F1979 (Actual) and FY1980 through FY1991 (Forecast)(in inllions of rb:pee)
Year to Mac 1----A C T U A L----- ------------------------ F 0 R E C A S TYear to March 31 A 1977 1978 1979 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991
ASSETS
Gross Fixed Assets (Historic Cost) 3.6 23.0 81.1 189.2 347.2 Z,4.53.0 6,5.33.o 12,287.0 18,044.0 23,7459.0 29,530.0 35,197.0 h4,968.o 148,275.0 48,275.0Less Depreciation - - - - - 1.2 74.8 268.7 632.9 1,164.5 1,865.9 2,744.3 3,915.1 5,279.9 6,747.7
Net Fixed Assets in Use 3.6 23.0 81.1 189.2 347.2 2,451.8 6,358.2 12,018.3 17,411.1 22,584.1 27,664.1 32,452.7 41,052.9 42,995.1 41,527.3Work-in-Progress 3.5 209.2 849.7 2,363.6 5,432.6 11,588.8 15,453.8 17,561.8 18,899.8 18,628.8 16,274.8 12,198.8 3,2814.8 - -
Total Net Fixed Assets 7.1 232.2 930.8 2,552.8 5,775.8 14,040.6 21,812.0 29,580.1 36,310.9 41,212.9 43,938.9 44,651.5 44,137.7 42,995.1 41,527.3
Short Term Deposits - - - - - - - - - - - 500.0 786.1 2,450.7 5,207.0Current Assets:
Cash 25.1. 31.2 47.8 .7.1. 2.9 1.2 3.2 6.1 9.0 11.9 14.8 17.6 22.5 2L.1 24.1Recoveries - - I- - 1. 25.1 87.5 179.6 280.5 394.3 536.8 711.6 871.0 977.2Inventories - - - - - 24.5 64..3 122.9 180.1 237.5 295.3 351.9 449.7 482.7 182.7Other Debtors - - - - - 1.0 1.0 2.0 2.0 2.0 3.0 3.0 4.0 5.0 1.0
Total Current Assets 25.4 31.2 47.8 147.4 42.9 28.6 93.5 218.5 371.0 531.9 707.4J 909.3 1,187.8 1,382.8 1,485.0
Deferred Expenses 2,2 3.5 5.5 7.5 10.0 11.0 5.0 - - - - - - - -
Total Net Assets 34.7 266.9 984.1 2,607.7 5,832.7 14,080.2 21,910.9 29,798.6 36,681.9 141,744.8 44,646.3 46,060.8 46,111.6 46,828.6 48,219.3
CAPITAL AND LIABILITIKE
EouityIssued Share Capital 12.3 258.6 961.0 2,583.o 5,810.0 13,812.0 19,487.6 21,959.0 21,959.0 21,959.0 21,959.0 21,959.0 21,959.0 21,955.0 21,959.0Share Capital Deposit 22.0 - - - - - - - - - -Retained Earnings - - - - - 6.9 17.1 247.2 608.4 1,125.2 1,866.0 3,065.4 4,644.3 6,907.2 9,861.8
Total Fquity 34.3 258.6 961.0 2,583.0 5,810.0 13,818.9 l-,534.7 22,206.2 22,567.4 23,084.2 23,825.0 25,024.4 26,603.3 28,866.2 31,820.8
DebtGOI Loans - - - - - 260.0 2,368.0 7,566.0 14,058.8 18,571.3 20,692.5 20,862.7 19,264.7 17,653.7 16,042.7
Current Liabilities 0.4 8.3 23.1 241.7 22.7 1.3 8.2 26.4 55.7 89.3 128.8 173.7 243.6 308.7 355.8
TOTAL CAPITAL AND LIABILITIES 34.7 266.9 984.1 2,607.7 5,832.7 14,080.2 21,910.9 29,798.6 36,681.9 141,741..8 44.,646.3 4.6.060.8 46,111.6 46,828.6 48,219.3 VDebt/Equity Ratio - - - - 2/98 11/89 25/75 38/62 15/55 16/51. 16/54 42/58 38/62 34/66 -
Source: NTPC March 1980
- 71 -
ANNEX 16Page 1 of 5 pages
INDIA
FARAKKA THERMAL POWER PROJECT
National Thermal Power Corporation Limited
Assumptions on Financial Projections
1. The financial statements in this report display NTPC's financialoperations for the period FY1979 through FY1991. They comprise income state-ments, with a supporting statement showing the capacity of plant, energygenerated and sold (Annex 13), source and application of funds, withsupporting investment program (Annex 14) and condensed balance sheets as atMarch 31 each year (Annex 15).
2. The following assumptions are made:
(a) Schedule of Commissioning Operating Plant
Units Singrauli Korba Ramagundam Farakka
200 MW Unit 1 February 1, 1982 January 1, 1983 February 1, 1984 December 1, 1984200 MW Unit 2 August 1, 1982 July 1, 1983 August 1, 1984 June 1, 1985200 MW Unit 3 February 1, 1983 January 1, 1984 February 1, 1985 December 1, 1985200 MW Unit 4 August 1, 1983200 MW Unit 5 February 1, 1984 -
500 MW Unit 1 February 1, 1986 October 1, 1986 July 1, 1987 April 1, 1988500 MW Unit 2 February 1, 1987 October 1, 1987 July 1, 1988 -500 MW Unit 3 - October 1, 1988 July 1, 1989
(b) Energy Output
200 MW Units - First year - 2,500 hrs. operation- Second year - 4,000 hrs. operation- Third year - 5,500 hrs. operation
500 MW Units - First year - 2,500 hrs. operation- Second year - 4,000 hrs. operation- Third year - 5,000 hrs. operation- Fourth year - 5,500 hrs. operation
- 72 -
ANNEX 16Page 2 of 5 pages
(c) Fuel Cost Escalation
Singrauli - Based on 0.600 kg/kWh and 0.589 )kg/kWh for 200 and 500 MW )respectively and Rs 69/ton in )FY1980 )
)Based on 0.685 kg/kWh and 0.673 )kg/kWh for 200 and 500 MW )respectively and Rs 71.81/ton ) 10% FY1981in FY1980 ) 7% FYs 1982,
) 1983, 1984) 5% FY1985) onwards
Based on 0.588 kg/kWh and 0.548 )kg/kWh for 200 and 500 MW )respectively and Rs 115.51/ton )in FY1980 )
)Based on 0.666 kg/kWh and 0.655 )kg/kWh for 200 and 500 MW )respectively and Rs 69/ton in )FY1980 )
An additional 5% cost is added for the fuel oil needed for starting and low loadoperation plus tax of Rs 5 per ton.
(d) Calorific Value of Coal
Singrauli - 4,000 Kcal/kgKorba - 3,500 Kcal/kgRamagundam - 4,300 Kcal/kgFarakka - 3,600 Kcal/kg
(e) O&M Expenses
Power Station - 2.5% on original cost of 200 MW plant- 2.0% on original cost of 500 MW plant
Transmission - 0.5% of original cost
(f) Depreciation
Power Station - 3.1% of original costTransmission - 2.6% of original cost
NOTE: Section XVII(8) of the 6th Schedule of the Electricity
- 73 -
ANNEX 16Page 3 of 5 pages
(Supply) Act 1948, provides for depreciation "from thebeginning of the year of account next following that inwhich the particular asset became available for use inthe business". Under the recently enacted financial amend-ments to the Act, in the future depreciation is to becharged in accordance with the directions to be issued byGOI. GOI has issued a notification covering FY1979 whichmakes no change in the 1948 Act provisions. Notificationscovering future years will be issued in due course.
(g) Tariffs. NTPC has an obligation to achieve a rate of returnof not less than 9.5% on the forecast average net fixed assetsin service by FY1989, and from the commencement of its commer-cial operations in FY1982 to set tariffs at levels not lowerthan those required to achieve a 9.5% rate of return on theforecast data for FY1989. On this basis, and bearing in mindthe time it takes for the generating plant to reach an operatinglevel of 5,500 hours a year, the average price of 29.08 paise/kWhcalculated on the FY1989 estimates, is assumed as the averageprice for all sales from February 1982.
(h) Fuel. Fuel costs are based on the prices per ton shown inparagraph 2(c) and escalated until FY1982. Thereafter a fuelclause is assumed in the bulk supply contract, to permitadjustment to meet any further variation in fuel costs. Theeffect of any fuel price variation is shown separately in theforecast expenses and recovered by means of a fuel surcharge.
(i) Rate Base
(i) Singrauli. Construction costs are based on 1979 pricesescalated at rates given in schedule below except whereorders have been placed when escalation is applied fromaward date onwards. The main plant equipment costs forthe three 200 MW phase are, however, based on the awardmade in 1978.
(ii) Korba. Construction costs are based on 1979 pricesescalated at rates given in the schedule below.
(iii) Ramagundam. Construction costs are based on 1978 pricesescalated at rates given in the schedule below; however,the main plant equipment value for the three 200 MW unitsis based on the actual awarded value in 1980.
(iv) Farakka. Construction costs are based on 1978 pricesescalated at rates given in schedule below.
(v) Escalation Schedule
Price escalation:
- 74 - ANNEX 16Page 4 of 5 pages
a. 6% per annum for the year 1979-80
b. 10% per annum for the year 1980-81
c. 7% per annum for the years 1981-82 through 1983-84
d. 5% for year 1984-85 and onwards
The turbine generators and steam generators are, however,subject to the following maximum price escalation from thedate of order:
Singrauli 200 MW units - 25%
Korba, Ramagundam &Farakka 200 MW units - 20%
500 MW units for allprojects - 15% turbine generators
20% steam generators
Physical Escalation:
Civil works - 10% of construction cost
Equipment - 5% of equipment cost
(j) Capital Requirements
(i) The proposed loan and credit would be relent by the GOIto NTPC for a period of 20 years from the date of with-drawal of the first installment including a 5 year initialgrace period, and repayable in equal semi-annual install-ments of principal, together with interest at the rate of10.25% per annum on unpaid balances.
(ii) Other capital requirements would be advanced by GOI inthe form of debt and fully paid up equity capital, pro-vided that the unpaid debt at the end of each year wouldnot exceed the sum of the issued share capital and the"free" reserves, that is to say those which are notrequired for specific purposes. Advances would initiallybe in the form of equity capital (up to FY1984) and loancapital thereafter.
(iii) GOI loans (including the onlending of both the proposedloan and credit and also previously approved credits andloan) are assumed to finance either defined projects orindividual generating units and transmission linesincluded in NTPC's investment program. Interest on theloans up to the date of commissioning of each unit ofplant would be charged to construction, and subsequent
- 75 -
ANNEX 16Page 5 of 5 pages
interest accruals would be charged to revenue. Repay-ment of principal is assumed in 30 semi-annual installmentscommencing on the first anniversary following the end ofthe five year grace period.
(k) Working Capital. Variations in working capital representthe differences between the sums of the individual itemsmaking up current assets less current liabilities at thebeginning and at the end of the year.
(1) Balance Sheets (Annex 15)
Current Assets
(i) Receivables are assumed at a level equivalent to one-twelfth of the revenue for the year; and
(ii) Inventories are assumed at 1% of gross assets at theend of the year.
Current Liabilities
Current liabilities are assumed at a level of one month's fuel cost,plus 4% of the annual operating and maintenance expenses.
- 76 -
ANNEX 17
INDIA
FARAKKA THERMAL POWER PROJECT
National Thermal Power Corporation Limited
Annual Rates of Return in Real Terms
Rate of Return on Rate of Return on /aYear to March 31 Historic Rate Base Revalued Rate Base
1982 0.6% 0.5%1983 1.6% 1.3%1984 4.1% 3.6%1985 5.7% 4.9%1986 6.7% 5.7%1987 7.7% 6.3%1988 9.1% 7.3%1989 9.5% 7.5%1990 10.2% 7.7%1991 11.4% 8.1%
/a The following inflation rates have been used:
FY1981 10%FYs 1982, 1983 and 1984 7%FY1985 forward 5%
- 77 -
ANNEX 18Page 1 of 2 Pages
INDIA
FARAKKA THERMAL POWER PROJECT
NTPC's Bulk Tariff (Eastern Region) andBulk Exchange Tariffs in the Eastern Region
1. The proposed regional financial bulk tariff of about 32 paise/kWhfor supply from Farakka to the Eastern Region should be considered in thegeneral context of "bulk" tariffs and costs obtaining in the Region. Tariffscharged between supply authorities for energy exchanges in 1978/79 were asfollows:
Paise/kWh
- BSEB purchase from OSEB 21-28
- DVC purchase from OSEB 28
- Emergency exchange 11
2. These exchange tariffs at voltages similar to that proposed forFarakka are arrived at after reaching a compromise on opposing views. Intheory, an elaborate system of guidelines exists in the Eastern Region,defining the method of calculating cost-related tariffs. In reality, however,the tariff is often agreed on only after lengthy negotiations.
3. It should be borne in mind that the present exchange tariffs, ifregularly adjusted for general inflation, could reach a range of 18-46 paise/kWhby 1985, when the first Farakka energy will be supplied, and a level of 22-56paise/kWh by the late 1980's: at that time the Farakka tariff is still projectedto be at 32 paise, thus falling behind the general average regional exchangetariff level.
4. The cost of energy supply at high voltage levels in the Regioncan be estimated by using the following samples of average financial cost ascalculated by SEBs:
Paise/kWh (1979) /a
OSEB 10
WBSEB 18
Weighted average 16
/a Including cost of purchases.
- 78 - ANNEX 18Page 2 of 2 Pages
5. Again assuming adjustment for inflation, the average SEB costof supply at voltage levels comparable to NTPC's would be 24 paise/kWh in1985, and would rise to about 29 paise/kWh by 1989. NTPC power is likely tobe more expensive than the SEB's accounting estimate of the cost of their owngeneration in part because depreciation is less on the old assets owned by theSEBs and in part because some SEB energy comes from hydro plant with very lowoperating cost. Particularly for SEBs such as Orissa, (or any SEB relying onhydro power to a large extent), NTPC power will appear to be a costly purchase.
- 79 -
ANNEX 19Page 1 of 6 Pages
INDIA
FARAKKA THERMAL POWER PROJECT
Regional Marginal Cost Analysis of NTPC Operations
1. The following assumptions are necessary to make marginal costanalysis for NTPC a relevant exercise that can enter as an input into tariffconsiderations:
(i) each station is reviewed as an independent systemselling power in bulk to the Region concerned.
(ii) Whether or not there will be additional investment by NTPCin each Region beyond the presently planned program, NTPC ateach of its regional stations will ultimately operate at itscapacity limit. This implies that any incremental demand willhave to be satisfied by further investment, and justifiesthe inclusion of representative marginal capacity cost in thetariff.
(iii) All sales of energy will be at the level of 400 kV.
(iv) There will be no seasonal and only minor daily variation inNTPC's load demand: all stations will be operated as baseload for the participating SEBs, thus eliminating any peaksin NTPC operations.
(v) For each station, the program of commissioning of units andannual hours of operation is taken as planned by NTPC.
2. The method used for the computation of an approximation of long-runmarginal cost is the concept of Average Incremental Cost (AIC), smoothingout any fluctuations by averaging over the entire known investment program.The results are expressed in terms of both (i) a uniform energy charge perRegion, incorporating both marginal capacity and energy costs; and (ii) atwo-part tariff consisting of a capacity charge and an energy charge, recover-ing marginal capacity and energy costs, respectively.
3. The basic computation is performed in terms of constant 1979 costs.In order to arrive at marginal cost in future years when energy will be soldto SEBs, it is assumed (in the absence of a longer-term investment plan) thatany investment necessary to satisfy incremental demand beyond NTPC capacity atthat time will have the same pattern as the investment envisaged for the late1970's and 1980's. For this purpose, marginal cost for future years isarrived at by updating the 1979 marginal cost by a projected inflation rateof 10% per year initially, decreasing to 5% in 1984. All marginal costs areexpressed in constant market prices of the year in question, and discounted at10% p.a.
ANNEX 19- 80 - Page 2 of 6 pages
NORTHERN REGION MARGINAL COST
(Second Singrauli 2,000 MW) (1979 constant Rs million)
Sales ofCapital Cost Recurrent Cost Total Incremental Incremental
Year (Plant & Transmission) (O&M and Fuel) Cost GWh Mw
1 35 - 35 - -
2 211 - 211 - -
3 380 - 380 - -
4 986 - 986 - -
5 1,972 - 1,972 - -
6 1,669 12 1,681 73 +200
7 1,899 102 2,001 859 +400
8 1,306 196 1,502 2,233 +400
9 485 284 769 3,725 -
10 181 401 582 5,492 +500
11 111 535 646 7,468 +500
12 - 599 599 8,687
13 - 631 631 9,427
14 - 645 645 7,723
15-25 - 647 647 9,760
PV at 10% 5,230 2,108 7,338 29,727 873
ANNEX 19
Page 3 of 6 pages
EASTERN REGION MARGINAL COST
(Farakka 1,100 MW) (1979 constant Rs million)
Sales ofCapital Cost Recurrent Cost Total Incremental Incremental
Year (Plant & Transmission) (O&M and Fuel) Cost OWh MW
1 8 8
2 66 - 66 -
3 801 - 801 -
4 1,056 - 1,056 -
5 1,361 - 1,361 -
6 1,172 - 1,172 -
7 587 85 672 665 +400
8 229 150 379 1,730 +200
9 113 264 377 3,638 +500
10 - 301 301 4,702
11 - 317 317 5,146
12-25 - 325 325 5,367
PV at 10% 3,347 1,188 4,535 18,455 511
ANNEX 19
- 82 - Page 4 of 6 pages
WESTERN REGION MARGINAL COST(Korba 2,100 MW) (1979 constant Rs million)
Sales ofCapital Cost Recurrent Cost Total Incremental Incremental
Year (Plant & Transmission) (O&M and Fuel) Cost GWh MW
1 16 - 16 -
2 276 - 276 -
3 489 - 489 -
4 1,611 - 1,611 -
5 1,903 - 1,903 -
6 1,867 22 1,889 111 +200
7 1,855 120 1,975 954 +400
8 1,230 177 1,407 1,930 -
9 607 255 862 3,308 +500
10 254 365 619 5,072 +500
11 114 490 604 7,105 +500
12 - 575 575 8,806
13 - 611 611 9,749
14 - 626 626 10,156
15-25 - 630 630 10,247
PV at 10% 5,867 2,029 7,896 30,678 898
ANNEX 19. -83 - Page 5 of 6 pages
SOUTHERN REGION MARGINAL COST
(Ramagundam 2,100 MW) (1979 constant Rs million)
Sales ofCapital Cost Recurrent Cost Total Incremental Incremental
Year (Plant & Transmission) (O&M and Fuel) Cost GWh MW
1 45 - 45
2 457 - 457
3 1,075 - 1,075
4 1,772 - 1,772 -
5 1,696 - 1,696 - -
6 1,774 37 1,811 222 +200
7 1,513 147 1,660. 1,242 +400
8 881 239 1,120 2,794 +500
9 350 390 740 4,736 +500
10 167 542 709 6,754 +500
11 99 682 781 8,363 -
12 - 745 745 9,478 -
13 776 776 10,081 -
14-25 - 785 785 10,247 -
PV at 10% 5,926 2,626 8,552 33,076 956
ANNEX 29
- 84 - Page 6 of 6 pages
SUMMARY: MARGINAL COST - BASED TARIFFS
North: East: West: South:Singrauli Farakka Korba Ramagundam
Marginal Cost 1979
1. One-part tariff: paise/kWh 24.7 24.6 25.7 25.9
2. Two-part tariff: RsikW/year 661 722 720 683
plus paise/kWh 7.1 6.4 6.6 7.9
Marginal Cost in First Yearof Energy Sales 1/ 2/
1. One-part tariff: paise/kwh 29.1 34.8 32.4 34.9
2. Two-part tariff: Rs/kW/year 778 1,022 907 920
plus paise/kWh 8.4 9.1 8.3 10.7
Marginal Cost 1984/85-/
1. One-part tariff: paise/kWh 35.0 34.8 36.4 36.4
2. Two-part tariff: Rs/kW/year 935 1,022 1,019 966
plus paise/kWh 10.1 9.1 9.3 11.2
1/ Singrauli 1981/82, Farakka 1984/85, Korba 1982/83, Ramagundam 1983/84.
2/ Inflation 10% p.a., declining to 5% p.a.
April 1980
ANNEX 20
- 85 -
INDIA
FARAKKA THERMAL POWER PROJECT
Definition and Cost of Alternatives to the Project
Capital Cost(Rs million in constant 1979 market prices)
Capacity Boiler & Other Civil TotalLocation MW TG Equipment Works Others Cost
Bihar - North 3x110 750 442 243 147 1,582
Orissa(pithead site) 2x110 500 452 160 96 1,208
West Bengal- Damodar lxllO 250 147 81 50 528valley
- Calcutta 2x210 868 542 342 180 5,250
Sub-Total 2,368 1,569 908 405 5,250
AssociatedTransmission - - - - 244System* _
GRAND TOTAL 1,100 2,368 1,569 908 405 5,494
* This consists of: (a) 150 Kms of 220 kV transmission lines for thepithead station in Orissa.
(b) Certain incremental investment on transmissionlines for other stations. These lines would formpart of the integrated system
Source: NTPC
April 1980
-86 -
ANNEX 21
INDIA
FARAKKA THERMAL POWER PROJECT
Additional Transmission and Distribution Cost
1. The draft plan 1978-83 provides for about 58% of the expenditure tobe allocated to generation, the rest to transmission, distribution and ruralelectrification (i.e. rural distribution). Non-generation expenditure, there-fore, accounts for about 70% of generation expenditure.
2. The cost of the project already includes a transmission element whichaccounts for about 10% of the generating plant component. The difference tothe regional average is, therefore, allocated to the project to enable acomparison with tariff revenue at retail level: an additional investmentnecessary to serve final consumers.
3. Operating and maintenance expenditure on the additional transmissionand distribution facilities is assumed to be 2% of the cumulative value ofthe assets installed.
4. The split by cost components of the additional investment isassumed to be similar to that of the original transmission component includedin the project, and is expressed in identical economic terms.
5. The amount of energy sold to final consumers is arrived at byreducing the kWh sent out from the project (after auxiliary use) by theaverage regional system losses:
Share ofRegional
State /a Consumption System LossesM% (%.)
Bihar 34 19.8Orissa 19 15.4West Bengal 47 11.2Weighted average 14.9
/a Including DVC shares.
-87 - ANNEX 22Page 1 of 2 pages
INDIA
PARAU TlE21AL PowEI PROJECT
icoaomie C6ott FtrkiA Ptoleet 100 tM (IA million)
Item ~~~~~~~~~~~~~~~~~~~~~~~~~~1989-90-Item 1978-79 1979-80 1980-81 1981-82 1982-83 1983-84 1984-85 1985-46 1986-87 1987-88 198849 2002-03
Plant rapital goods- CIP 3.5 27 340 429 547 464 227 91 50 - - -
- dom. 0.8 6 73 93 118 100 49 20 11 - - -
Othar goods, freight, 0.6 5 61 77 98 83 41 16 9 - - -
ins.
Labor 1.2 10 121 153 195 165 81 33 18 - - -
Trans. Capital goods- CIF - 1.3 9 21 31 30 18 5 - -
- dom. - 2 14 34 50 48 30 a - - - -
Other goods, freight, - 0.2 1.2 3 4 4 3 0.7 - - - -
ins.
Labor - 0.9 6 15 21 21 13 4 - - -
O&M Spares, freight, ins. - - - - - 24 34 52 52 52 52 52
Labor _ - - - 26 37 57 57 57 57 57
Fuel - - - - - 40 105 219 283 310 323
Annual total 6.1 52.4 625.2 825 1,064 965 573 391.7 416 392 419 432
Additional transmission + - 22 151 365 530 515 320 89 - - - -
distribution investment
Additional transmission + - - - - - 32 38 40 40 40 40 40distribution 0&M
Benefit:
Incremental Kwh sold retail - - - - - - 508 1,508 3,171 4,100 4,488 4,680
(kKwh)
Tariff revenue 927.8 p/ kwh - - - - - - 161 419 882 14140 1,247 1,301(Res m.)
Economic cost of tariff - - - - - 140 365 767 992 1,085 1,132revenue at 0.87 SC}
Economic benefit (non- - - - - - - 203 603 1,268 1.640 .1794 1,872industrial tariff revenueplus industrial willingnessto pay for power)
ANNEX 2 2Page 2 of 2 pages
- 88 -
Bconmoic Cost: Alternative to Parakka 1100 kW (Rs mjiion)l
1989-90-Item 1978-79 1979-80 1980-81 1981-82 1982-83 1983-84 1984-85 1965-86 1986-B7 1987-88 198849 Y002-03
Plant Capital goods- CIF - - 145 435 599 675 541 200 45 - - -
- dom. - - 32 96 131 148 119 44 10 - - -
Other goods, freight, - - 29 88 121 136 109 40 9 - - -ins.
Labor - - 56 166 229 258 207 77 17 - - -
Trans. Capital goods- CIF - - 0.5 4 13 19 15 5 d.7 - - -
- don. - - 0.7 7 21 30 24 6 1 - - -
Other goods, freight, - - 0.1 0.5 2 3 2 0.5 0.1 - - -
ins.
Labor - - 0.3 3 9 13 11 4 0.5 - - -
O&M Spares, freight, ins. - - - - - - 36 47 51 52 52 52
Labor - - - - - - 41 52 57 58 58 58
Fuel Bihar - - - - - - - 36 93 136 157 157
Orissa - - - - - - - 6 28 43 54 54
West Bengal - - - - - - 58 111 178 202 202 202
Total Fuel - - - - - - 58 153 299 381 413 413
Annual Total - - 263.6 799.5 1,125 1,282 1,163 628.5 490.3 491 523 523
April 1980
- 89 - ANNEX 23Page 1 of 2 Pages
INDIA
FARAKKA THERMAL POWER PROJECT
Shadow Pricing of Costs and Benefits
1. Conversion Factors
Where CIF or FOB prices of tradeable goods (or tradeable inputsinto domestically manufactured goods) are not readily available, the followingfactors are used to convert domestic costs of non-traded goods to borderprices:
Standard conversion factor 0.87Capital goods conversion factor 0.78Local materials conversion factor 0.87
2. Shadow Wage Rate
Before converting labor cost to border prices, using the standardconversion factor, the following assumptions about the economic value of laborare made:
Skilled labor: 100% of market wage,
Unskilled labor: 75% of market wage.
Furthermore, about 60% of the total labor cost of the project in terms of1979 market prices are assumed to be attributable to skilled labor.
3. Aluminum Component of Transmission
The domestic aluminum price being subsidized, it is necessaryto use the higher CIF price to establish economic cost at a time of importnecessity. The aluminum content of the domestic ex-works cost of conductor(excluding the labor content) is about 50%. A CIF price of $1,800/ton isapplied to this cost element, increasing it by about 20%.
4. Economic Cost of Coal
Rather than using the domestic administered price of coal, itseconomic value is expressed by identifying the average production cost asfollows:
- 90 - ANNEX 23Page 2 of 2 Pages
Rupees per tonneCost Item (1979 market prices)
PrivateCoal India Collieries
Labor 50.27 48.91Stores 9.70 15.70Power 4.28 2.14Transport ation 2.12 1.48Capital goods annuity 13.31 15.16Other 7.63 2.68Conservation & safety 1.33 0.12
Total 88.64 86.19
Labor cost is assumed to consist of 50% skilled and 50% unskilledlabor; stores to consist of capital goods and local materials; capital goodscosts are converted to border prices at the capital goods conversion factor,other expenditure at the standard conversion factor. The economic cost ofcoal amounts to Rs 68-70/t. An average of Rs 69/t is used.
For the alternative to the project, the following cost of coal isassumed, reflecting transport from the closest location:
Economic TotalCost at Mine Economic
Stations (Rs/t) Freight (Rs/t) Cost (Rs/t)
Bihar 69 64 133
Orissa 69 - 69
West Bengal 69 47 116
5. Opportunity Cost of Capital
A range between 10 and 13% is assumed to reflect the rate of returnon public investment in the economy.
6. Benefits
The alternative use of consumers' expenditure for electricity isassumed to be expenditure on a basket of tradeable goods. Consequently, thestandard conversion factor is used to convert the benefit proxies to borderprices.
- 91 - ANNEX 24
INDIA
FARAKKA THERMAL POWER PROJECT
Structure of Operation and Maintenance Costs(in % of total O&M cost in 1979 constant market prices)
Domestic costex-works
(excluding labor) Labor Total
1. Spares 29.05 9.45 38.50
2. DM Plant Chemicals 6.50 1.20 7.70
3. Consumables, Lube Oil,Chemicals etc. 9.30 2.20 11.50
4. Direct Labor - 40.00 40.00
5. Other 2.30 - -
Total 47.15 52.85 100.00
Source: NTPC
April 1980
ANNEX 25
Page I C f 2 'f &e S
- 92 -
INDIA
FARAKKA THERMAL POWER PROJECT
Economic Justification: Results
1. Least-cost Analysis
Present value of cost streams(Rs million)
Discount Rate Project Alternative(%) (Farakka 1100 MW) (4 stations in
3 states)Base case 10% 4,354 4,987
13% 3,491 3,934
Cost of capital goods up
by 10% 10% 4,537 5,185
13% 3,651 4,104
Cost of capital goods down
by 10% 10% 4,171 4,790
13% 3,330 3,764
Cost of labor up
by 10% 10% 4,435 5,075
13% 3,557 4,005
Cost of fuel down
by 20% 10% 4,111 4,670
13% 3,326 3,718
Cost of alternative down
by 10% 10% 4,354 4,488
13% 3,491 3,541
ANNEX 25Page 2 of 2 pages
- 93 -
2. Benefits and internal rates of return of the project
Minimum internalrate of return (%)
a. Tariff revenue as proxy forminimum benefit
Base case 4.9
Cost of capital goods up by 10% 4.5
Cost of capital goods down by 10% 5.4
Cost of labor up by10% 4.7
Cost of fuel down by 20% 5.9
Tariff revenue up by 10% 6.5
b. Willingness to pay as proxy forminimum benefit
Base case 13.3
Benefits up by 101/1; 14.9
Costs up by 10% 11.7
1/ This can be attributable to one or more of the following:
(i) increased frequency of outages and use of standby capacity,(ii) decreased losses in distribution and higher Kwh sales,(iii) higher valuation by the consumer of the unit of energy.
April 1980
- 94 - ANNEX 26Page 1 of 2 Pages
INDIA
FARAKKA THERMAL POWER PROJECT
Economic Benefits
1. The approach used is one of identifying a proxy for the minimumbenefit that reflects the willingness of consumers to pay for incrementalpower supply. The traditional method is to use tariff revenue for thispurpose, bearing in mind that actual, non-quantified, benefits are consid-erably higher, both because of the existence of a consumers' surplus, andbecause of the non-market, subsidized level of power tariffs. Some of thissurplus is identifiable if the cost incurred by industrial consumers for thepurchase and operation of diesel standby generating sets is included in thebenefits instead of the industrial tariff revenue only. A further refinementwould be to express benefits in terms of industrial and agricultural outputgained by the project's alleviation of power outages that interrupt production.Other benefits such as greater work, leisure, and educational benefits accru-ing to domestic consumers are quantifiable only with difficulty.
Tariff Revenue
2. The minimum proxy for benefits in the region is arrived at asfollows:
Share of Regional Average Tariff 1979State Consumption (%) (paise/kWh)
Bihar 34 31.4
Orissa 19 16.6
West Bengal 47 29.6
Weighted average (financial) 27.8
Weighted average (economic) 24.2
Cost of Standby Generation
3. The following samples were used to establish the capital cost ofrecently purchased standby diesel sets:
- 95 - ANNEX 26Page 2 of 2 pages
Unit size (KVA) Cost of set (1978 Rs) Rs/KVA
244 284,000 2,869
200 600,000 3,000
315 1,000,000 3,174
244 700,000 2,869
Assuming an average 1979 purchase price of about Rs 3,000/kW, plus 10%installation charges, the total installed cost would be Rs 3,300/ kW. Powercost can be derived as follows:
Life of set: 15 years
Average utilization: 4,400 hours/year (50% load factor)
Annual Cost - Rs/kWh
Annual charge at 13% discount rate: Rs 510/kW Rs 0.12
Annual O&M cost: Rs 180 Rs 0.04
Fuel and lubricant cost at 0.25 l/kWh
@ Rs 1.50/1 (Rs 9/1 for lubricant): Rs 0.38
Total cost (financial): Rs 0.54
Total cost (border prices) about: Rs 0.52
4. The economic cost of Rs 0.52/ kWh (at the assumed load factor)represents the observed maximum willingness to pay for continuous powersupply. Combined with the average regional industrial tariff of 27 paise/kWh(Bihar: 34, West Bengal: 22, Orissa: 26) and its economic equivalent of 23paise/kWh, the resulting average benefit proxy for industrial consumers is 38paise/kWh in economic terms. 1/ It can be assumed that this represents theminimum willingness to pay.
1/ Assuming a sloping demand curve for industrial energy inputs.
- 96 - ANNEX 27
INDIA
FARAKKA THERMAL POWER PROJECT
National Thermal Power Corporation Limited
Documents Available in the Project File
A. General Reports and Studies Related to the Sector
A.1 Tenth Annual Electric Power Survey of India.A.2 Report on Power System Planning Studies - Phase I 1979-1984
System.A.3 Report of Working Group on Power Development 1979/80 to
1983/84.A.4 Uniform Heads of Accounts for State Electricity Boards.A.5 Forms for Compilation of Annual Accounts of State Electricity
Boards, approved by the Comptroller and Auditor General ofIndia on November 28, 1978.
A.6 Report on the Working Group in Energy Policy: GOI 1979.A.7 Power Supply Position in the Country: CEA September 1979.
B. Selected Reports and Working Papers Relating to the Project
B.1 Farakka Project Feasibility Report.B.2 Updated Cost Estimates for NTPC's Development Program;
Operating Plant Commissioning Schedule.B.3 Note on Rajamahal 'A' Opencast Coal Mine: Coal India Ltd.
July 6, 1979.B.4 Draft Report on Project Monitoring System: A.F. Ferguson
& Co., Delhi, Management Consultants.B.5 Dr. R.K. Pachouri - Discussion Paper on Approval to Power
Pricing by NTPC.B.6 Economic Costs of Project and Alternative.B.7 Power Supply Position 1976/77-1983/84 of SEBs in Eastern Region.B.8 Regional Diversity in Peak Demand - September 1978 to April 1979 -
Eastern Region.B.9 Schedule of Installed Capacity of Existing Thermal Stations
at end of March 1979 - Eastern Region.B.10 Miscellaneous Appraisal Data.
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