Document of The World Bank FOR OFFICIAL USE ONLY Report No. 3608b-IN INDIA SECOND RAMAGUNDAM THERMAL POWER PROJECT STAFF APPRAISAL REPORT November 30, 1981 Regional Projects Department South Asia Projects This document has a restricted distribution and may be used by recipients only in the performance of their official duties. Its contents may not otherwise be disclosed without World Bank authorization. CURRENCY EQUIVALENTS Currency Unit = Rupee (Rs) Rs 1 Paise 100 US$1 = Rs 8 l/ Rs 1 US$0.125 1/ Rs 1 million = US$125,000 1/ MEASURES AND EQUIVALENTS 1 Kilometer (km) = 1,000 meters (m) = 0.6214 miles (mi) 1 Meter (m) 3 39.37 inches (in) 1 Cubic meter (m ) = 1.31 cubic yard (cu yd) = 35.35 cubic feet (ft) 1 Hectare (ha) = 10,000 m = 2.471 acres (ac) 1 Kilogram (kg) = 2.2046 pounds (lb) 1 Ton (t) = 1 metric ton = 2,200 lbs 1 Kilocalorie (kcal) 3.968 British thermal unit (Btu) 1 Kilovolt (kV) = 1,000 volts (V) 1 Kilovolt-ampere (kVA) = 1,000 volt-amperes (VA) 1 Megawatt (MW) - 1,000 kilowatts (kW) = 1 million watts 1 Gigawatt hour (GWh) = 1,000,000 kilowatt hours ABBREVIATIONS AND ACRONYMS APS - Annual Power Survey BEST - Bombay Electric Supply and Transport Undertaking BHEL - Bharat Heavy Electricals Limited CIF - Cost Insurance Freight CEA - Central Electricity Authority CWPC - Central Water and Power Commission GOI - Government of India GDP - Gross Domestic Product IDA - International Development Association KfW - Kreditanstalt fuer Wiederaufbau MPC - Mysore Power Corporation NHPC - National Hydro Power Corporation NTPC - National Thermal Power Corporation PERT - Program Evaluation and Review Technique REC - Rural Electrification Corporation Limited REB - Regional Electricity Board SEB - State Electricity Board TDO - Thermal Design Organization KWU - Kraftwerk Union CESC - Calcutta Electric Supply Company NTPC's FISCAL YEAR (FY) April 1 - March 31 1/ The US$/Rs exchange rate is subject to change. Conversions in this report have been made at US$1 to Rs 8, which represents the projected exchange rate over the disbursement period. FOR OMCIAL USE ONLY nDLi SECON KORI THERML POWE PROJECT STA"F APPRAISAL RRORT Tael. of Contents Pase No. I. THE POWER SECTOR ........... ............................... 1 Background ................................ 1 Energy Resources.... 1 Past Bank Group Involvement in the Sector .... 4 Sector Institutions . . .- 6 Existing Facilities - All India .......... . . . .8 Power Supply/Deiand Balance - All India. 9 Puture Development - All India ....... 10 Southern Region Demand and Supply-Ramagundum Supply Area 12 Future Integrated System Operation . . 14 Bank Group's Strategy in the Sector . . . . 15 It. THE BENEFICIMY - NATIONAL THERMAL POWER CORPORATION =" | ~~~~21 LI1, ............................................ ........ . 2 Legal Status and Authorities ..21 Organization and Management ..22 Training ........................ ......... ................... 23 Sale of Power from the Project ..24 Accounting Organization and Syst .. .24 Audit . ...................... , .. .. ........... 25 III. T= gg AAN D THE PROJECT ..... . . . 26 The Program .......... ................ ... . ... 26 The Project . ... 26 Estimated Cost ....... . ....27 Project Financing ........................................... 29 Engineering and Construction.. 29 ProcurDewnt ...-------------..-----------... .............. 30 Disbursement -.. ................ 30 Ecological Aspects .............................. 31 Project Risks ................ 32 IV. FINMANCTL ANALYSIS ........................................... 34 Investment Program ..34 Future Earnings .. 35 Taxation . .............----.-.a.... ... ............ 36 This report has been prepared 'by Messrs. V. Antonescu, B.C. Davis and K.G. Jechoutek on the bais of an appraisal conducted in India during a mission in January/February 1981. This document si a restricted distribution and may be used by recipients only in the performance of their official duties. Its contents may not otherwise be disclosed without World Bank authorization. - ii - Table of Contents (continuation) Page No. Internal Cash Generation FY1977-FY1992 ........................ 36 NTPC's Financing Plan FY1982-FY1989 ........................... 37 Future Finances .............. 38 Borrowing Powers .40 Commercial Arrangements for Sale of NTPC Energy .40 V. JUSTIFICATION .42 General .42 Comparison of Alernatives .42 Cost-Benefit Analysis .43 Tariffs .44 VI. AGREEMENTS REACHED AND RECOMMENDATION .45 ANNEXES 1. All-India-Sales and Energy Data 1969/70 - 1979/80 .46 2. All-India Power Supply Position 1980 - 90 (Excluding non- utility) .47 3. CEA Norms for Estimating Capacity and Energy Availability 48 4. Inter-State and Inter-Regional Exchanges - Southern Region - 1979/80 .50 5. Southern Region Sales and Energy Data .51 - Tamil Nadu - Karnataka - Andhra Pradesh - Karala - Total Region 6. Southern Region: Installed Capacity, Peak Load and Energy Requirement .56 7. Southern Region Hydro Stations. 57 - Southern Region Thermal Stations 8. Southern Region Power Supply Restrictions .60 9. Southern Region Power Supply Position 1980/90 .61 10. Southern Region Summary of Capacity Additions During 1980/90 62 - Southern Region Additions to the Installed Capacity from Ongoing/Sanctioned Schemes During 1980/90 11. Financial Performance of the State Electricity Boards .66 - Rates of Return of SEBs FY1976 through FY1980 (Actual) and FY1981 (Forecast) - Rates of Return Forecasts for Five Years through FY1985 of Southern Region SEBs 12. Organization Chart of NTPC .71 - Project Organization of NTPC - Technical Services Division of NTPC - Proposed Organization Structure - iii - ANNEXES (continuation) Page No. 13. Organization Chart 1980/81 Corporate Finance ................. 75 14. Description of the Ramagundam Development .................... 76 15. Project Cost Estimates ....................................... 79 16. Estimated Construction Schedule .............................. 81 - Estimated Construction Schedule - Transmission Lines 17. Estimated Schedule of Disbursements .......................... 84 18. NTPC - Income Statement Covering Operations FY1982 - FY1994. . 85 19. NTPC - Investment Program for the Period FY1977 - FY1991 ..... 87 - Sources and Application of Funds Statement for the Period FY1977 through FY1994 20. NTPC - Balance Sheets FY1977 through FY1994 .................. 89 21. Assumptions for Financial Projections ........................ 90 22. Annual Rates of Return in Real Terms ......................... 95 23. Definition and Cost of. Alternative to the Project ............ 96 24. Shadow Pricing of Cost and Benefits .......................... 97 25. Economic Cost; Ramagundam Project ............................ 100 26. Economic Benefits ............................................ 102 27. Additional Transmission and Distribution Cost ................ 105 28. Economic Cost/Benefit Analysis ............................... 107 29. Economic Justification: Results .............................. 108 30. Regional Exchange Tariffs and Cost of Generation ............. 109 31. Economic Marginal Cost of NTPC Operations .................... 110 32. Documents Available in the Project File ...................... 112 MAPS IBRD - 15648R2 IBRD - 15649R I INDIA SECOND RAMAGUNDAM THERMAL POWER PROJECT I. THE POWER SECTOR Background 1.01 Economic growth and improvement of the standard of living in India depend critically on the development of the power sector. Over the last two decades, India's power demand has grown roughly twice as fast as the economy, and the power sector now takes the largest share of India's public investment resources. This is mainly due to the rapid industrial development in general and power-intensive industry in particular, and to the impressive expansion of rural electrification, especially for irrigation. 1.02 In spite of an almost five-fold increase in the country's generation capacity, from 5,600 MW in 1960 to about 33,000 MW at present, power shortages have been experienced in various parts of the country for a number of years, and continuing gaps between supply and demand will be a major constraining factor for the foreseeable future. 1.03 Before 1975, almost all power facilities in India were planned, constructed and operated by each State, each to meet its own needs. Because of the rapid growth of the power sector, the Government of India (GOI) decided to create new institutional structures in the power sector and to emphasize central planning of generation and high voltage transmission with the ultimate object of central control through a national grid. In 1975 GOI established two companies, the National Thermal Power Corporation (NTPC) and the National Hydro Power Corporation (NHPC), responsible for the design, construction and operation of large centrally-owned power stations and their associated transmission facilities. The Central Electricity Authority (CEA) performed studies of the national power system, and GOI decided to proceed with the construction of four large centrally-owned thermal power stations located adjacent to coal fields--the 2,000 MW Singrauli, the 2,100 MW Korba, the 2,100 MW Ramagundam, and the 2,100 MW Farakka stations--supplying bulk power to the States through an interconnected 400 kV transmission system. IDA/Bank has financed the first stage of 600 MW at each plant, and its associated transmission. In addition, IDA credits for the second stage of Singrauli (1,400 MW) and the second stage of Korba (1,500 MW) have been approved. The second stage of Ramagundam--comprising three additional 500 MW units with associated transmission facilities--is the subject of this report. A loan of US$300 million is proposed. Energy Resources 1.04 Commercial primary energy accounts for about 46% of total energy in India with the balance (54%) coming from non-commercial sources (mainly firewood, agricultural and animal waste). The main commercial energy resources are coal, oil, natural gas and hydro power. There are also resources of nuclear fuels, principally uranium and thorium. Some -2- geothermal energy sites have been identified, but the potential appears to be limited. Over the past ten years total energy consumption in India has grown at an annual rate of about 4%. Consumption of commercial energy has increased faster (about 5% p.a.) than that of non-commercial energy, thus resulting in a steady decline in the share of non-commercial energy in total energy consumption. This is mainly due to substitution of commercial energy for non-commercial forms of energy. 1.05 Coal and hydro power have an important role in meeting the country's commercial energy requirements, covering at present about 70% of total consumption. The consumption of petroleum is relatively low in India in comparison with other developing countries, and accounts for about 20% of total demand for commercial energy. Despite the low petroleum consumption, the extensive development of domestic energy resources such as coal and hydro power, and the recent development of offshore petroleum resources, the country has not attained energy self-sufficiency and remains dependent on imported oil to meet part of its primary energy requirements. Moreover, in recent years there has been a growing demand for petroleum products mainly because of difficulties in coal supply and inadequate coal production. The impact on India's balance of payments of the increase in world oil prices after 1973 is evident from the following: while oil imports have grown by 40% (6.9 million tons) between 1973/74 and 1980/81, the cost of imports rose by some 800% from US$719 million in 1973/74 to about US$6.5 billion in 1980/81, equivalent to more than 72% of India's merchandise exports. Domestic energy resources such as coal and hydro are large enough to supply most of India's future commercial energy requirements, particularly for industry and for power generation. However, known oil and gas resources would not be sufficient to meet the demand for oil in sectors (such as transportation and residential) where further substitution by other fuels is limited. Therefore, the exploration for new petroleum reserves and development of existing sources is one of India's most pressing priorities. 1.06 Coal constitutes the main domestic source of commercial energy in India. Coal reserves to a depth of 600 m and of seam thickness of more than 1.2 m are currently estimated at 85.4 billion tons, of which 17.9 billion tons are of the coking variety and 67.5 billion tons of the non-coking variety. The Geological Survey of India has recently estimated that an additional 26.1 billion tons of coal deposits exist at depths below 600 m. 1.07 From 1953/54 to 1970/71, the share of coal in commercial primary energy supply declined from 80% to about 60%, while production increased from 34 million tons to about 65 million tons per year. Since 1970/71, the share of coal has remained constant whereas production has grown at an average annual rate of 5.5% (to 114 million metric tons in 1980/81). Despite the production increases, shortages developed in 1977/78 and -3- reached an estimated 10 million tons in 1980/81. The main reasons for the shortfalls are poor capacity utilization, shortages of explosives, floods, labor problems, and bottlenecks in the transportation and distribution systems. 1.08 The economically exploitable hydroelectric potential of India is estimated at about 400,000 GWh of annual energy generation which might sustain an installed capacity of 100,000 MW at 45% load factor. About 11,000 MW (one third of the total installed generating capacity) of hydro potential is developed, 4,700 MW is scheduled for commissioning by 1984, and a further 23,000 MW is under study for development. Some 70% of the total hydroelectric potential is in the north and northeast, in remote areas difficult to access. 1.09 India also has sufficient reserves of uranium (34,000 tons equivalent of U308, of which 15,000 tons is considered economically exploitable at current international prices) and thorium to meet the foreseeable nuclear power program. The existing nuclear power plants have a total installed capacity of 860 MW, consisting of two boiling water reactor units at Tarapur (Maharashtra) and two pressurized heavy water reactor units at Kot (Rajasthan). In addition, two units of 235 MW are under construction at Kalpakkam (Tamil Nadu) and two units of the same size at Narora (Uttar Pradesh). It is planned to set up two new stations of two units of either 235 MW or 500 MW each. The construction of a prototype fast breeder reactor is in progress. It is expected that it will be possible to commission fast breeder reactors, as part of the power system, by the mid-nineties. Beyond the year 2000, the fast breeder reactors are expected to play a major role in the nuclear power generation. An installed nuclear capacity of 5,000 MW has been visualised by the year 2000. However, given the limited options available for meeting the growing power demands and the likely role that nuclear power may have to play beyond the year 2000, GOI considers that it may become necessary to accelerate the nuclear power development to achieve an installed capacity of 8,000 - 10,000 MW by the turn of the century.l/ 1.10 India's prognostic recoverable reserves of oil and gas are currently estimated at 6.5 billion tons of oil equivalent. Of this, proven recoverable reserves are about 360 million tons of oil equivalent, of which 294 million tons are oil and 66 million tons are gas. Over 60% of the recoverable oil reserves are offshore. 1.11 Domestic oil production has increased from 0.5 million tons in 1961 to 11.8 million tons in 1979 and currently meets about 40% of India's 1/ See "Report of the Working Group on Energy Policy", 1979, Government of India, Planning Commission. -.4- internal requirements. Gas production, now concentrated in the north-eastern region, is currently estimated at about 2 million tons of oil equivalent, of which about half is used as fuel or feedstock for fertilizer plants and about half is flared, mainly because there is no market for it within a reasonable distance from its dispersed production sites. At present, it does not appear practical to use the relatively small and dispersed amount of gas which is now flared, for power generation. The utilization of natural gas for power generation or alternatively as feedstock for fertilizer or petrochemical production is being examined in the long-range power development study which GOI has agreed to complete by April 1982 (see paras. 1.45 and 1.51) 1.12 In 1980/81 the power sector used about 44 million tons of coal equivalenti/ (representing about 40% of total consumption of commercial primary energy). Of power generated, 44% came from hydroelectric and nuclear plants, 50% from coal, and 6% from oil. Over the past ten years the share of coal in thermal generation has fluctuated between 85% and 90%, and this is expected to continue in the future. The share of primary (hydro and nuclear) electrical energy in total generation has varied between 43% and 50%. It is expected that by 1987/88 the power sector will no longer use oil for electricity generation. Past Bank Group Involvement in the Sector 1.13 The Bank has made ten loans to India for power projects amounting to US$358.5 million, and IDA fifteen credits totalling US$2,096 million, for an aggregate of US$2,454.5 million. Of this amount, US$1,820 million involved financing of generating plant, US$23 million the purchase of construction equipment for the Beas hydroelectric project, US$380 million the provision of high voltage transmission, and US$232 million the purchase of rural electrification equipment. Fourteen loans and credits have been completed including nine for generating plants, the Beas project (Credit 89-IN), the first three transmission projects (Loan 416-IN, Credits 242-IN and 377-IN) and the first rural electrification project (Credit 572-IN). The Fourth Transmission Project (Credit 604-IN) is in an advanced stage. The closing date of Credit 604-IN has been extended to December 31, 1982 to enable full utilization of the funds. The Third Trombay Thermal Power Project (Loan 1549-IN) was approved in April 1978 and is well underway. The Singrauli (Credit 685-IN), Korba (Credit 793-IN) and the Ramagundam Thermal Power Projects (Credit 874-IN and Loan 1648-IN) and the Second Rural Electrification Project (Credit 911-IN) are being implemented. The credit for the Second Singrauli Thermal Power 1/ The following conversion factors were used: 1 ton of coal equivalent (or 7 million kilocalories) is equivalent to 0.72 ton of crude oil and 3,030 kWh. -5- Project (Credit 1027-IN), the credit/loan for the first stage of the Farakka Thermal Power Project (Credit 1053-IN and Loan 1887-IN), and the credit for the Second Korba Thermal Power Project were approved in May 1980, June 1980 and July 1981, respectively. 1.14 The Singrauli, Korba and Trombay projects are on schedule. The Farakka and Ramagundam projects, and the Fourth Power Transmission Project are proceeding satisfactorily notwithstanding modest initial delays in implementation and a substantial delay in preparation of specifications and review of tenders for the more sophisticated load dispatch equipment for the transmission project. The Second Rural Electrification Corporation Project is well ahead of schedule. 1.15 A Project Performance Audit Report on the Second Power Transmission Project (Credit 242-IN) was issued on June 3, 1980. The Report stated that the project was successful in assisting the nine beneficiary SEBs in extending their transmission systems in order to help to meet their growing power requirements over the extended project period. Utilization of the generating capacity in the nine SEBs exceeded the appraisal forecast. Institutional objectives mainly concerned the rehabilitation of the finances of the SEBs, and while the results achieved by the time of project completion were modest, the improvement effort was continued by the Third and Fourth Power Transmission Projects (Credits 377-IN and 604-IN respectively). In FY 1980, seven of the nine SEBs reached their target rate of return of 9.5%. This compares with three in FY 1977 (the latest year by which all of the SEBs were to have earned a 9.5% rate of return). The conclusions of the Report pointed to: (a) the impossibility of adequately supervising the work on the project (other than the procurement aspects) which consisted of many sub-projects scattered all over India, and (b) the absence of a close working relationship between the Bank Group and the beneficiary SEBs, which denied opportunities for effecting institutional improvements. The Report suggested that a more direct involvement with the SEBs in projects of this nature would be beneficial. 1.16 Besides its involvement in the power industry, the Bank Group is also involved in India's oil and gas subsector. In 1977, the Bank made a loan of US$150 million (Loan 1473-IN) for Phase III of the Bombay High Offshore Development. This was followed in 1980 by a loan of US$400 million (Loan 1925-IN) for Phase IV of the same development. In view of the considerable impact on the economy of increasing oil prices, the acceleration of production from existing fields, primarily the Bombay High, remains an important priority. With regard to natural gas, the Bank Group is cooperating with GOI to ensure that the development of the South Bassein gas field, which is capable of producing 18 million Nm3/day of non-associated gas, is carried out in an optimal manner, and that a basis for a longer-term gas resource strategy is prepared in order to maximize the benefits of this new source of energy to the economy. -6- Sector Institutions 1.17 The principal agencies in the sector are: (i) the State Electricity Boards (SEBs); (ii) the Atomic Energy Commission; (iii) the Central Electricity Authority (CEA); (iv) the Regional Electricity Boards (REBs); (v) the two central power corporations, NTPC and NHPC; and (vi) the Rural Electrification Corporation Ltd., (REC). 1.1-8 The SEBs are constituted by the State Governments under the provisions of the Electricity (Supply) Act, 1948, to promote the coordinated development of the generation, transmission and distribution of electricity within their respective States in the most efficient and economical manner, and for the control and regulation of other supply undertakings which are private licensees. These comprise municipal utilities such as the Bombay Suburban Electric Supply Undertaking, and private utilities, the largest of which are the Tata Electric Companies (Bombay), the Calcutta Electric Supply Company (CESC), and the Ahmedabad Electric Supply Company. At the present time, the States effectively own or control well over 90% of electricity supply facilities. While the SEBs are corporate entities in their own right and enjoy some autonomy in the management of their day-to-day operations, they are under the control of their State Governments in such matters as policy, capital investment, tariff changes, borrowings, pay scales and personnel policies. 1.19 The CEA was formally created in 1950 with responsibility for developing a national policy for power development and coordinating the activities of the various agencies involved in electricity supply. At: that time, 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 was created to bring together ministerial responsibility for coal and power. This involved the transfer of the Power Wing of the former CWPC to the CEA, which now comes under the Department of Power of the Ministry of Energy and is responsible for developing a sound national policy for the electricity supply industry. The Department of Atomic Energy, which is directly responsible to the Prime Minister, deals with nuclear power generation. 1.20 CEA's powers were enlarged through amendments to the general provisions of the Electricity (Supply) Act, 1948, which were enacted on November 30, 1976. In addition to its general responsibilities for national power policies, it is now responsible for the formulation and coordination of plans for power development, optimization of investments in the power sector for the whole country, development of interconnected system operation, training of personnel, and research and development. It includes specialist engineering organizations which provide comprehensive project engineering services to the electricity supply industry. The Thermal Department also takes responsibility for monitoring the -7- performance and maintenance records of thermal power stations and for organizing the training of power station personnel. The Economic and Commercial Department accumulates data on economic, finance and accounting aspects of the power industry in India, both at Center and State levels, with particular reference to the operations of the SEBs. CEA is playing a leading role in advising State Governments and their SEBs on measures to be taken to implement the amendments to the financial provisions of the Electricity (Supply) Act 1948, which were enacted in June 1978, and which provide for the operation of SEBs on more commercial principles with a financial objective of achieving a reasonable level of self-financing. However, the introduction by the States of financial policies to give effect to these amendments has been delayed pending Central Government directives concerning implementation of improvement measures for the sector. The CEA has also embarked on a program of reform of SEB accounting practices and steps to introduce a standardized system of commercial accounting are now underway. It is expected that implementation of the new system would begin by April 1982. When implemented, this system will bring uniformity to the procedures relating to the preparation of accounts and will permit meaningful comparison of SEB financial results. 1.21 The SEBs and the other licensed electricity undertakings are required to submit their investment proposals to the CEA for technical and economic appraisal and to the Energy Division of the Planning Commission for inclusion in the Five Year Plan. The Planning Commission is responsible for the allocation of plan funds among the States and among sectors. Planning of generation, transmission, and distribution development has traditionally been undertaken by each SEB for its own State rather than on a regional or national basis. However, with the rapid growth of the power sector, GOI recognizes the necessity for an integrated national approach to sector development. 1.22 As a means of improving collaboration between the SEBs and establishing power systems on a regional rather than a State basis, Regional Electricity Boards (REBs) were set up for each of the Northern, North Eastern, Southern, Eastern and Western Regions. The chairmanship of each REB is assumed in rotation by the Chairmen of the SEBs within the Region and they are staffed by engineers seconded from their constituent SEBs. The general functions of the REBs are to plan integrated operation of the power systems in the Region for the maximum benefit of the Region as a whole, to coordinate overhaul and maintenance programs, to determine generation schedules to be followed and the power available for transfer between States, and to determine a suitable tariff structure for the transfer of power within the Region. At present, the Boards function mainly in an advisory role in relation to the SEBs. The REBs were established between 1964 and 1966 by common resolution of the State and Central Governments, to help develop integrated power systems in the respective Regions, and thus prepare for the transition from separate -8- power systems at State level to regional systems and finally to an interconnected national grid. 1.23 With most of their facilities under construction, currently NTPC and NHPC are not in a position to take a leading role in the generation and sale of power. At the present time, the construction of four large central thermal power stations has been started as mentioned in paragraph 1.03. NHPC is constructing several large hydroelectric projects. A transmission wing has also been established in NHPC to design and construct the 220 kV and 400 kV overhead transmission associated with hydro-projects, and any other transmission work which it might be commissioned to undertake. A new central organization may soon be formed. to assume ownership of these lines and to develop national or regional grids. In most States, the SEB will continue for some time to be the largest power undertaking. However, as future planning envisages a larger share of new capacity in central organizations, NTPC and NHPC shall be playing an increasing role in the power sector. 1.24 REC was incorporated in July 1969 under the Indian Companies Act, 1965, as a company wholly owned by GOI, under the general supervision of the then Ministry of Irrigation and Power (now under the Ministry of Energy). REC's chief objective is to finance rural electrification schemes throughout the country, acting as a financial intermediary with technical expertise, and administering funds received primarily from GOI. It is REC's function to ensure efficient allocation of these funds by establishing policies, procedures, and criteria for the formulation, approval and implementation of such schemes. In doing so, REC is directed to adopt a "project approach," coordinating electrification with other inputs in rural development in order to achieve increased agricultural production and overall economic development. Existing Facilities - All India 1.25 The total installed generating capacity in the whole of India as of March 31, 1981 was about 33,000 MW, including 2,736 MW of non-utility capacity, mostly thermal, which is owned by major industrial consumers to meet their own needs. The generating capacity is shown in Table 1.1 below: -9- Table 1.1: INSTALLED GENERATING CAPACITY AS OF MARCH 31, 1981 (MW) Region Conventional Thermal Nuclear Hydro Total Northern 4,318 440 4,033 8,791 Western 6,138 420 1,811 8,369 Southernl/ 2,824 - 4,828 7,652 Eastern2/ 4,080 - 972 5,052 North-Eastern 260 - 147 407 Total Utilities 17,620 860 11,791 30,271 Non-utility Capacity 2,733 3 2,736 Grand Total 20,353 860 11,794 33,007 1/ including Lakshadweep 2/ including Andaman & Nicobar Source: CEA. 1.26 Transmission is at 400 kV, 220 kV and 132 kV, and subtransmission at 33 kV. Distribution voltages are 11 kV and 415/240 V. The supply, in general, is reliable, but power shortages, especially during the summer months, necessitate load shedding, shutdowns and brownouts. System losses are still high, accounting for about 20% of units sent out. This subject has been examined by the "Committee on Power" (para. 1.55). Power Supply/Demand Balance - All India 1.27 India's installed power generating capacity increased at an annual rate of 10% during the 1950s and 1960s while gross electricity generation grew at just under 12% during this 20 year-period due to a better utilization of generating capacity. Although local and intermittent shortages did occur during this period, system failures did not present a major problem. However, by the early 1970s, the supply situation had grown more serious, and potential unconstrained demand consistently outpaced supply in a number of States. This situation was due to several factors such as: failure to implement projects in accordance with planned schedules, inadequate transmission development, operating and maintenance problems leading to a low plant availability at peak that at one point fell to about 64%, inadequate budget allocations -10- and the absence of adequate monsoon rains, particularly during the early 1970s, which led to lower hydro output. 1.28 The shortage situation was most serious in 1974/75, 1977/78 and 1979/80, particularly in the Eastern Region. The estimated deficit of energy throughout India (calculated as actual supply compared to potential unrestricted demand) during the 1970s ranged between 5% and 15%. Estimates for 1980/81 indicate that the deficit was of the order of 10%. 1.29 Power shortages, particularly in the industrial sector, have affected the output of the country, and the cost in terms of industrial production foregone has been substantial. Generally, energy restrictions fall on industry and there is relatively little loss to the economy on account of power shortages in either the residential or agricultural sectors. Lost value-added due to lost industrial production because of power restrictions has been estimated to be in the neighborhood of 3% of GDP.1/ 1.30 The growth of the power sector during the last 10 years and the pattern of consumption during this period is shown in Annex 1. Sales to agriculture and irrigation increased substantially during the 1970s, mainly because of the rural development programs. Industrial demand as a proportion of total demand has declined, and there has been a small but steady increase in domestic demand. It is expected that these trends in demand pattern will continue with a gradual improvement in the annual load factor. Future Development - All India 1.31 The countrywide peak demand supplied in 1980/81 was 19,080 MW (after supply restrictions); according to CEA's estimates, unconstrained demand is expected to increase to about 25,000 MW in 1981/82, 21,000 MW of which are expected to be met by available capacity. 1.32 India's tentative development program in the power sector anticipates an expansion of generating capacity during the 10-year period 1980/81-1989/90 by about 50,000 MW to eliminate supply shortfalls by the end of the decade; installed capacity by March 1990 would be about 80,000 MW. Only about 60% of this additional capacity has been approved by GOI at the time of appraisal; further approvals are expected as resource availability in future years becomes clearer. The additional capacity scheduled for commissioning during this period is shown in more detail in Table 1.2. Furthermore, the construction of some 15,000 km of 400 kV 1/ See: India, Economic Issues in the Power Sector, 1979 (World Bank Report No. 2335-IN, paragraph 68). -ll- transmission lines is planned to enable full integration of the regional systems and the evacuation of the output from the proposed new power stations. The Sixth Five Year Plan (1980-85), finalized in early 1981, provides for a capacity addition of 19,666 MW and identifies the need for an additional 30,000 MW during 1985-90. With the completion of the long-range power development study currently being undertaken by GOI, a detailed investment plan until 1990 will be finalized. Table 1.2: SCHEDULE OF PLANNED ADDITIONS TO CAPACITY DURING THE PERIOD 1980/81 - 1989/90 a/ Conventional Thermal Nuclear Hydro Total -_________________ -(MW) --------------___ Northern 9,010 690 5,899 15,599 Western 9,900 - 3,565 13,465 Southern 4,570 470 6,422 11,462 Eastern 5,760 - 3,035 8,795 North-Eastern 478 - 973 1,451 Total 29,718 1,160 19,894 50,772 a/ Excludes non-utility capacity; preliminary estimates. Source: CEA. 1.33 Annex 2 shows annual projections of planned installed capacity, available capacity, potential peak demand, and the forecast of energy requirements and availability (not taking into account diversity) until 1990. The data referring to the peak demand and energy requirement in 1979/80 and 1980/1981 show the demand constrained by supply; the estimated unsuppressed power and energy demand would have been higher (para. 1.28). The forecasts of peak load and energy requirements are based upon continuous monitoring of development trends during the preparation of the annual CEA electric power surveys of India. 1.34 Both unconstrained peak demand and annual energy requirements are projected by CEA to grow at an average annual rate of about 10% until 1990. If the program of generation development can be achieved on time, the present shortage of energy (about 10% of potential demand) would be -12- eliminated from 1984/1985 onwards, but there would still be a peak capacity deficit throughout the 1980s, only to be eliminated by 1990. The forecast capacity deficit decreases from the present 15% of potential demand to about 2-3% in the late 1980s, a margin which is smaller than the degree of accuracy of the forecast data input. In addition, the projections by CEA employ a low expected availability factor of generating plant. The peak availability in India under present operating conditions is about 65% of installed capacity; the norms used by CEA in establishing future availability of plant reflect this situation (Annex 3). An improvement in the availability factor, however, is likely because of the expected development of system interconnection and better maintenance practices; a small improvement after 1985 may have the effect of eliminating the capacity deficit even before 1990. In the short-run until 1985, little can be done to eliminate the present shortfall of capacity. 1.35 The All-India data of Annex 2 mask vast differences in shortages in different regions, which develop because of insufficient interconnection. The bulk of the aggregate deficit in the late 1980s is attributable to the Northern Region; its regional expected capacity deficit amounts to 10-15% of potential peak demand. In contrast, the remaining regions show an approximate balance of supply and demand after 1985. Southern Region Demand and Supply - Ramagundam Supply Area 1.36 The major authorities supplying the Southern Region are the Tamil Nadu, Andhra Pradesh, Karnataka and Kerala State Electricity Boards, and the Mysore Power Corporation (MPC). In addition, a number of small municipalities are engaged in power supply. All entities except MPC supply electricity to final consumers, but only the four SEBs and MPC own generation facilities. MPC supplies about 85% of the power made available to consumers by the Karnataka SEB. 1.37 The Southern Region is the only fully integrated electricity supply region in India, controlled by a Regional Load Dispatch Center at: Bangalore. Load frequency control equipment at Bangalore is now being tested and is expected to be operational soon. The large hydro component in the system allows energy to be transferred during the monsoon from SEBs with a reservoir-spilling surplus to others in the Region, while in the early summer months thermal generation is maximized to husband scarce water. In addition to its internal integration, the Region often operates in parallel with the Western Region, particularly In the States of Maharashtra and Gujarat. Maharashtra transfers off-peak energy to Karnataka and receives peak assistance. The Union Territory of Pondicherry receives power from Tamil Nadu. Annex 4 illustrates the inter-State and inter-Regional exchanges during 1979/80. -13- 1.38 The major Regional load centers are located in the State capitals of Hyderabad, Bangalore and Madras, and in major industrial locations such as Ramagundam in Andhra Pradesh and Belgaum in Karnataka. Regional consumption shows a distinct evening peak, and a sustained daytime plateau. Peaks in individual States do not occur at the same time: the diversity factor is about 1.1. In line with the national pattern, Regional consumption is heavily oriented towards industry: about 61% of total consumption are attributable to industrial consumers, about 18% to agricultural consumers for irrigation purposes, and about 11% to domestic consumers. This pattern masks significant differences among States. The share of agricultural consumption in Tamil Nadu and Andhra Pradesh is more than 20%, while 75% of Karnataka's and Kerala's supplies go to industry and only 5-8% to agriculture. Tamil Nadu is the dominant State in the Region with about 40% of total consumption (Annex 5). Sales in the Region have been growing at a steady rate of about 7% p.a. between 1970 and 1980, most of this in periods of supply restrictions. Generation and sales growth in 1979/80 was a minimal 2%, largely due to widespread supply difficulties and low reservoir levels (Annex 6). 1.39 System losses in the Region have been increasing during the last five years, but have not substantially exceeded the All-India loss level of about 20% of units sent out. Much of this may be due to rural electrification programs introducing a wider distribution system. This is particularly true of Andhra Pradesh and Karnataka, while Tamil Nadu and Kerala have already achieved almost 100% village electrification. There is evidence of some reduction of system losses in 1979/80. 1.40 As of March 1981, the total installed utility capacity in the Region was about 7,650 MW, consisting of 63% hydro, and 37% conventional thermal. Andhra Pradesh is the only State in the Region that has more than 50% thermal capacity; Kerala and Karnataka are purely hydro (Annex 7). In addition, about 490 MW of major captive industrial generating plant exist in the Region. While installed capacity has grown at about 6.5% p.a. between 1970 and 1980, actually available capacity at peak showed a growth rate of about 7.5%, resulting in a significant improvement in availability from about 65% to more than 70% (Annex 6). As energy consumption has been increasing at an annual rate of 6.5%, the system load factor decreased to about 57% in 1980, from more than 60% in the early 1970s, making the system peak more pronounced. 1.41 As in previous years, severe supply restrictions were imposed on consumers in 1980, ranging from 15% to 60% of potential demand or connected load (Annex 8). Overall, the Region experienced an estimated shortfall of about 13% of potential unrestricted demand. 1979/80 was a particularly poor year for supply because the hydro-dependent Region suffered from a poor monsoon. A satisfactory monsoon in 1980, however, significantly reduced the expected shortfall for 1980/81. The restrictions affected almost exclusively industrial consumers (reducing -14- their supply in absolute terms), while domestic and agricultural consumers benefitted from some growth in supply (Annex 5). 1.42 Potential unconstrained peak demand in the Region is expected to grow at about 9% p.a. until 1990. As total installed capacity (derived from identified generation projects and limited by expected fund constraints) is anticipated to grow at about 10.5% p.a., and available capacity at slightly less than that, the present estimated overall peaking capacity shortage of about 6% of potential demand will be reduced to 2-3% in the late 1980s, and practically eliminated by 1990. The energy shortage, a major problem of the Region in poor hydro years, is expected to be practically eliminated by the mid 1980s, but will increase again to reach about 8% by 1990 (Annex 9). Much depends on timely approval and implementation of generation projects. In this precariously balanced situation, the proposed project's 1,500 MW addition by 1989 will constitute about 10% of Regional peak demand and may make the difference between balance or shortage. 1.43 Expected capacity additions during the coming decade show an emphasis on hydro capacity, but with a decreased share of about 56% of the total. By 1990, this will reduce the hydro share in total capacity to 59% from the present 64%, making the Region less vulnerable to poor monsoon seasons (Annex 10). The proposed project, with a final level of sales to SEBs of about 7,300 GWh per year, will contribute significantly to this shift in emphasis towards a better hydro-thermal balance. Future Integrated System Operation 1.44 With the increasing size of the power sector in India and its far-reaching impact on the country's economy, annual demand surveys and Five-Year Plans at the State level have become inadequate as a basis for power development planning. The larger size of power plants, their consequent longer construction period--on average six to eight years for thermal plants and eight to ten years for hydro plants--as well as their gradual interconnection require a long-range perspective for investment decisions on a regional and national level. 1.45 In recognition of the need for coordinated power development throughout the country, provision was made in Credit 604-IN to help finance the cost of consultants to develop a long-range national plan for the sector, including technical, financial and economic aspects. Such a plan would include, inter alia, detailed demand forecasts, investigation of power generation schemes to meet load growth requirements for a 15-20 year period (including costs and sequencing of investments to optimize resources), development of primary grid configurations (including the 400 kV system study which CEA has started but has so far limited to a 1987--88 perspective due to lack of overall long-term planning of power plants and coordination with plans for other sectors in determining resource -15- requirements), and recommendations on responsibilities and needed operational policies at the State, regional and national levels. Such a study is an essential prerequisite for formulating sound policies for future development of the sector and GOI has indicated its intention to complete such a study by April 1982, based on the terms of reference agreed with the Association (para. 1.51). 1.46 The operation of regional systems, which will be integrated in the future into a national grid, requires large numbers of personnel who will have to be trained in the use of sophisticated load dispatch equipment and interconnected systems operation. Programs for training staff to operate the future load dispatch centers have been set up by CEA, and the Association is being kept informed about the development of these programs under the Fourth Transmission Project (Credit 604-IN). Bank Group's Strategy in the Sector 1.47 The Bank Group's strategy in its involvement in the Indian power sector, has been one of cooperation with GOI in seeking solutions to the many difficult and politically sensitive problems which have confronted the Indian electricity supply industry since Independence. 1.48 The Bank Group's main objectives in the sector are: (a) assistance in accelerating the installation of generating and transmission capacity and promotion of measures to improve the operation and maintenance of existing plant, in order to gradually eliminate the prevailing power shortages in the country; (b) assistance in introducing long-range system planning on a nationwide basis which would assure implementation of a least-cost power development program; (c) promotion of appropriate measures with respect to improving the sector organization and training; and (d) strengthening of the finances of the institutions involved in the sector, particularly of the State Electricity Boards (SEBs), through setting of rate-of-return targets or levels of self-financing and advising in design of appropriate tariff systems. 1.49 Under the Constitution, power supply is a "concurrent" subject. This means that the responsibility for supplying electricity is shared between the Central Government and the State Governments, requiring full agreement between the Center and the States for the implementation of most actions. The States develop and operate, through their Electricity -16- Boards, most of the power facilities. The consequence of this arrangement in many instances has been a local or State approach where a national or at least regional approach would have been more beneficial. Given these difficulties, the improvements achieved so far have been encouraging. They include the following: (a) with the establishment of the Regional Electricity Boards (para. 1.22) and later of NTPC and NHPC, the first important steps towards an improved organizational structure of the power sector have been made. GOI intends to gradually strengthen the authority of the REBs and to increase their role of coordinating the SEBs in matters of power development and operations; (b) CEA was reorganized and had its powers enlarged through the amendment in 1976 of the Electricity (Supply) Act 1948 (paras. 1.19 and 1.20); (c) The amendment in June 1978 of the financial provisions of the Electricity (Supply) Act 1948 requires that tariffs be sel: at levels sufficient to enable the SEBs to finance from internal sources a reasonable proportion of their investment program; (d) Between 1978 and 1981, SEBs have, with some success, been developing and implementing plans designed to improve their financial performance at least to the extent of achieving a rate of return of 9.5% as agreed under previous transmission credits/loans. These plans consist of tariff increases, rationalization of manpower requirements, improved maintenance practices and other cost-effective measures; (e) with a view to the reassessment of tariff policies, the majority of the SEBs have recently completed tariff studies based on marginal cost pricing principles. The Bank Group's review of these studies recommended the standardization of certain assumptions so as to produce a uniform methodology for general application by all SEBs. (f) NTPC's generation/transmission construction program (paras. 3.01 and 3.02), which is in the process of staged implementation with Bank Group assistance, will make an important contribution to the gradual elimination of the present deficit in the country's power balance, and is planned in the national interest, a move away from the provincial attitude prevailing in the past with SEBs constituting the almost exclusive source of power supply. The proposed project would help to continue this program. -17- 1.50 There are two specific areas which have been the cause of concern to the Bank Group and also have been the subject of a continuing dialogue with GOI. These are: (a) the weakness of nationwide long-range planning for power development; and (b) the weak financial position of some SEBs. 1.51 So far, long-range power planning on a nationwide basis has not been carried out in India, a major reason for the unreliable power supply in the country. The only regular planning activities carried out in the past were on a State-wide basis in the context of the various Five-Year Plans and the Annual Power Reviews carried out by CEA. Consequently, discussions were held with the Indian authorities both on the content of a long-range power development study designed to prepare a least-cost power development program and on CEA's capability to undertake such a study with its own staff. GOI agreed with the terms of reference suggested by the Bank Group. The study is underway and is to be completed by April 1982 (para. 1.45). During negotiations for the Second Korba Thermal Power Project GOI provided to the Bank Group a copy of a document outlining the status of preparation and schedule for completion of the ongoing long-range development study. During negotiations, the status of preparation of the study was discussed with GOI and found satisfactory (para. 6.01a). 1.52 While the financial performance of some SEBs (the sole prospective customers of NTPC) has been marginal in the past in achieving the 9.5% rate of return, as covenanted under previous lending operations for power transmission and rural electrification projects, there was a big improvement overall during FY1979 and FY1980 when, out of a total of sixteen major SEBs, eleven and thirteen SEBs, respectively, reached or exceeded the target. This compares with seven and six in FY1977 and FY1978, respectively (see Annex 11, Attachment 1 for further details). The implementation by these SEBs of action programs designed to restore or maintain their target rates of return has proved effective in most cases. In the case of Uttar Pradesh SEB, the subsidization by the State Government of rural electrification losses 1/ has enabled the SEB to reach its target rate of return for the first time. Overall, the SEBs' performance for FY1981 is expected to be maintained at the FY1980 level. 1/ In accordance with Credits 604-IN, 572-TN, and 911-IN, subsidies in respect of rural electrification losses are to be included in "operat- ing income" in calculating the annual rate of return. -18- 1.53 In the context of this project, special attention is being given to the SEBs of the Southern Region which would be recipients of Ramagundam power/energy. The Southern Region is comprised the States of Andhra Pradesh, Karnataka, Kerala, and Tamil Nadu. The Union Territory of Goa will also be a recipient of the Ramagundam output. The actual results of these SEBs for FY1980 are set out in Annex 11, Attachment 1. Five year projections through FY1985 are presently being prepared and it is expected that in each case the covenanted rate of return of 9.5% will be either maintained or exceeded. 1.54 Considering its increasing level of involvement in the Indian power sector, the Bank Group requested more comprehensive information on the sector during negotiations of the Farakka Thermal Power Project (Credit 1053-IN/Loan 1887-IN). This request was formally made to GOI in June 1980 when a suggested format for the monitoring of technical and financial performance of the sector was forwarded to GOI for review and approval. During appraisal, the reporting format was further reviewed with CEA. This was also discussed between the Bank Group's representatives and the Indian delegation during the Korba II negotiations and an agreement was reached with regard to the format for technical performance reporting. GOI has also indicated that it considers the Bank Group's proposal regarding financial reporting requirements broadly acceptable. The performance reporting would be provided annually within one year following the close of of the Indian fiscal year. The first report would relate to the fiscal year 1981/82. 1.55 The Indian authorities have recognized that with the rapidly expanding power sector in the country, all aspects of the sector should be reviewed and that satisfactory solutions must be found for the various sector problems. Consequently, GOI established a high-level committee in November 1978, called the "Committee on Power" under the chairmanship of V. G. Rajadhyaksha, former member of the Planning Commission. This committee was assigned the task to examine and make recommendations for improvement of the, power sector. It completed its task and submitted its conclusions to GOI in September 1980. All major aspects of the power sector were considered, including: planning, project formulation and implementation; operation and maintenance; organization and management; finance, financial management and tariffs; rural electrification; and research and development. The recommendations of the Committee on Power, most of which are satisfactory in the light of the Bank Group's strategy, form a useful basis for improvement of India's power sector in all its aspects. 1.56 Implementation of some of the Committee's recommendations is already underway or, among others, better planning procedures and improved operating and maintenance management. Although other important recommendations made by the Committee may have considerable impact on long established structures and deep-rooted habits, it is of the utmost -19- importance that GOI acts expeditiously in initiating the implementation of measures to bring about the required improvements. 1.57 In addition to the actions already discussed with GOI (paras. 1.51 and 1.52), the Bank Group considers that actions to accelerate improvement in the following areas are of high priority: (a) Performance of thermal power plants: the measures to be taken should focus on achieving better utilization of rated capacity through improving maintenance practices, overcoming delays in the supply of spare parts, reducing the duration of maintenance shut-downs, improving the quality and flow of coal supplies and upgrading the skills of personnel engaged in operation and maintenance. (b) Co-ordination of power development and growth in other sectors: in connection with the long-range power development plan, demand forecasting which is currently done on the basis of unrestricted power supply should be related to realistic projections limiting the growth of demand to the available supply; this would be accomplished by adjusting the connection policy for new consumers and by stressing conservation and demand management measures for existing consumers in order to make the optimal use of installed generating capacity. (c) Intensification of hydroelectric development: only 11% of the economically exploitable potential has so far been developed (para. 1.08); the measures to be taken should include not only increased investment allocation, but also appropriate project preparation procedures through managerial, technical and administrative improvements. (d) Strengthening of the role of the Central sector in power generation and inter-State high voltage transmission: the current transition from local grids to regional grids and then to a national system should go in parallel with the implementation of adequate institutional structures, which should permit gradual shifts of the responsibility of planning and operating power plants and inter-State transmission linkages of 220 kV and above, from State level to national level. (e) Establishment of financial objectives and policies for their implementation, principles for evolving rational tariff policies and improvements in management information and accounting systems for each SEB: to comply with the provisions of the financial amendments to the Electricity -20- (Supply) Act, 1948 (para. 1.20), in terms of improving the SEBs' self-financing capability to the extent of producing a reasonable contribution towards future expansion, alternative methods of financing of the SEBs must first be evaluated in order to determine the impact both on consumers and on State budgets. 1.58 The concern of the Bank Group with regard to the above-mentioned areas of India's power sector is also reflected in the recommendations of the Committee on Power. During the Korba II negotiations, GOI agreed to provide to the Bank Group, by April 1982, an implementation plan and schedule outlining the steps to be taken in each of the five priority areas of power sector improvements listed above. In addition, tentative agreement was reached during the appraisal of a proposed Third Rural Electrification Project to accelerate the implementation of financial and accounting improvements in SEBs, particularly with respect to commercial accounting practices and SEBs' self-financing capability. -21- II. THE BENEFICIARY - NATIONAL THERMAL POWER CORPORATION LIMITED Legal Status and Authorities 2.01 NTPC, the beneficiary of the proposed credit, was established in 1975 under the Companies Act, 1956. The Electricity (Supply) Act, 1948, has been amended to give the Corporation statutory recognition. NTPC is a company wholly 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) was increased to Rs 8,000 million (US$1,000 million) in June 1980 and Rs 15,000 million (US$1,875 million) in September 1981. The paid-up capital of the Corporation on September 30, 1981 was Rs 5,862 million. The Corporation has a Board of six Directors. 2.02 The Companies Act, 1956, confers broad powers on NTPC to carry out its work. However, the tariffs to be applied as well as any changes in such tariffs, its investment plans and annual capital budgets, have to be approved by the Government. NTPC is also subject to periodic examination by the Committee on Public Undertakings--a body established by GOI to monitor the performance of public sector enterprises. 2.03 The main objectives for which the Corporation was established are: (i) to design, construct, and operate large central thermal power stations and the associated transmission systems; and (ii) to transmit and sell the power generated. NTPC will initially own and operate the associated 400 kV transmission system over which power will be distributed from each plant and sold in bulk to SEBs. Later these systems will be part of the 400 kV interconnected regional systems which, still later, will be integrated into the national grid. 2.04 NTPC's present program provides for the construction of four thermal power stations (Singrauli, Korba, Ramagundam and Farakka). It is also possible that NTPC might ultimately take over ownership of the 510 MW Badarpur station near Delhi, which is at present being managed by NTPC on a management fee basis. The station is presently planned for an ultimate capacity of 720 MW. The feasibility of installing two more 210 MW units, which would increase the capacity of this station to 1140 MW, is being investigated. NTPC has also undertaken investigations for identifying additional sites for thermal power stations in the Central sector. Based on these studies, feasibility reports submitted by NTPC for pithead developments at Waidhan (Madhya Pradesh), Kehalgaon (Bihar), Talcher (Orissa) and Pench (Madhya Pradesh) are under consideration by GOI. Feasibility studies for other sites, i.e., Second Singrauli (Uttar Pradesh) and Mangur (Andhra Pradesh) are under formulation. The capacity -22- to be installed at these sites in the first instance is likely to be about 5,000 MW while the ultimate potential is estimated to be nearly 14,000 MW1. Organization and Management 2.05 NTPC's organization, which at present is necessarily construction oriented, is shown in Annex 12, page 1. The complete range of management: systems is shown in Annex 12, pages 2 and 3. NTPC has also designed an organizational structure (Annex 12, page 4) for the next stage of development, when it will be taking up operation of large thermal plant along with its increasing construction responsibilities. The new organization structure is being progressively implemented. 2.06 NTPC has adopted a three-tier organizational structure. The first tier consists of the corporate functions of Planning and Marketing, Personnel, and Finance which are entrusted with normal corporate level responsibilities, such as the development and formulation of policies andl their implementation. The other services relevant to the projects (second tier) have been centralized as Service Divisions located at headquarters. These are Technical Services, Contract and Procurement Services, Quality Assurance and Expediting, and Project Management Services. 2.07 The third tier, which embraces project activities, consists of a project organization for each of the four power plants under construction. Each project organization is headed by a General Manager who is entrusted with total responsibility for implementation of all aspects of the project's construction program. 2.08 Good progress has been made in building up the organization since 1975 when NTPC was established. The number of staff appointed by August 1981 was 3,665 comprising 1039 executives, 204 executives in training and 2,256 non-executives. NTPC has also taken over the majority of the employees of the Badarpur Project and Power Station (para. 2.04). 2.09 To date, NTPC has developed along sound lines. Its founding Chairman and Managing Director, a competent administrator with an established reputation in the formulation and development of large industrial undertakings, has been appointed Secretary of the Ministry of Heavy Industry and a new Chairman has recently been appointed. NTPC's well-trained staff is expected to carry on its work without noticeable interruption. Remarkable progress has been made in all activities in the NTPC's first five years and providing this impetus can be maintained with no deterioration in management, NTPC should with the assistance of consultants, be capable of handling the present large development program. Site organizations are effectively functioning at all projects. The centralized functions which, in addition to corporate personnel, are planning/marketing and finance, provide the engineering, contracting and project management input. They are organized to meet the project -23- requirements and to ensure an effective coordination of the projects under construction. Training 2.10 NTPC is a young organization which is growing rapidly to meet the demands of its large construction program. The next phase of expansion will involve the need to recruit and train operating staff. When all current developments have been completed and commissioned, NTPC's establishment will have grown to a figure in the neighborhood of 15,000. The importance, therefore, of implementing training programs for the various skills required during the construction and operational phases cannot be too highly stressed. 2.11 NTPC has placed special importance on this aspect of its organization, and training programs are being developed by the Corporation which will, in due course, be backed by a training school equipped with 200 MW and 500 MW simulators, financed from the proceeds of Credits 793-IN and 1053-IN, as well as other modern facilities for instructing and training the operating staff. 2.12 NTPC's training programs which so far have concentrated on pre-operational spheres of activity such as Planning, Design and Construction Management, are now additionally being aimed at its operational sphere. Some of 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 managerial staff on the accounting systems and procedures being implemented. Recruitment of young executive trainees is mainly from engineering graduates belonging to mechanical, electrical and civil disciplines on appointment, who are inducted into a one-year training program. The first group of young executive trainees was recruited in February 1977, the second in December 1977 and the third by mid-1978, comprising 35, 45, and 84 members, respectively. The fourth group comprising 131 trainees was recruited in November 1979 and training commenced in November 1980. The training programs have been well designed to provide exposure to power -24- stations under construction and operation, equipment manufacturing plants, engineering descriptions and project management services. For these purposes, assistance is taken from a large faculty of experienced engineers and managers selected from all over the country. NTPC is also utilizing the facilities of the Central Electricity Generating Board (U.K.) for training of operation and maintenance staff. 2.13 With the first 200 MW generating unit (at Singrauli) scheduled to commence commercial operation in February 1982, NTPC has finalized comprehensive plans for training operational staff, particularly the non-supervisory staff in the various technical and non-technical trades, to provide foremen for the first two units at Singrauli. The manpower for these is being drawn from experienced staff as well as from fresh recruitment. Recruitment of manpower has commenced and key personnel, such as the station superintendent, are already in position. Sixty-three executives including those experienced in power plant operation and ninety-five supervisory staff are in position at Singrauli. Recruitment of operation manpower also commenced at Korba and seventeen executives are in position. 2.14 On-the-job training has high priority. The methodology includes classroom lectures, participation in group exercises and discussions supported by direct reading, audio-visual presentations and plant visits. Overall training plans and arrangements at this time are satisfactory. Sale of Power from the Project 2.15 As in the case of NTPC's other projects being financed with Bank Group assistance, GOI has undertaken to allocate at least 85% of the proposed project's power/energy to the States in the region in which the project is located. The remaining 15% will be sold in accordance with priorities to be determined by GOI to States with the greatest need. During negotiations, GOI confirmed that allocation of 85% of the output of. power from the project to the SEBs of Andhra Pradesh, Karnataka, Kerala, Tamil Nadu and the Electricity Department of the Union Territory of Pondicherry has been agreed in principle. Undertakings to this effect from these organizations, endorsed by their State Governments were received by the Bank Group (para. 6.01b). Accounting Organization and Systems 2.16 NTPC continues to report good progress in the planning of NTPC's finance and accounting organization (Annex 13) and in the design and implementation of accounting systems and procedures. The design of accounting systems for both the construction and operational phases of NTPC's activities has been completed. Implementation of systems for the construction phase is either complete or at an advanced stage both at the corporate center at headquarters, and also at the sites, while the -25- consultants' proposals for the operational phase are at an advanced stage of discussion with management. To familiarize staff with the systems and procedures, training courses are being conducted by the consultants in conjunction with staff members from NTPC's corporate center. Audit 2.17 The audit of NTPC's accounts and records is undertaken by a professional auditor appointed by the Company Law Audit Board, on the recommendation of the Comptroller and Auditor General of India. The auditor is normally a member of the Indian Institute of Chartered Accountants, and his audit report on NTPC's financial statements is subject to comment by the Auditor General. Auditors Messrs. V.K. Mehta and Company, Chartered Accountants, Delhi audited NTPC's accounts from its incorporation up to and including FY 1979 and their audit reports expressed satisfaction at the state of the company's affairs during this period. For the audit of the accounts for FYs 1980 and 1981 two auditors were appointed, Messrs. Raghu Nath Rai and Company and Messrs. Prasad Azad and Company, both firms of Indian Chartered Accountants. There were no adverse comments from the auditors on the accounts of either year. It should be borne in mind that NTPC's activities will cover only project construction until FY1982 when power will be sold for the first time. NTPC has already undertaken in connection with previous credits and loans to furnish to the Bank Group audited financial statements within seven months of the end of the fiscal year to which they relate, together with a certified report by the auditors, and a review of the accounts by the Director of Commercial Audits. This has been restated in connection with the proposed Loan (para. 6.01c). -26- III. THE PROGRAM AND THE PROJECT The Program 3.01 NTPC's current development program, comprising the four central thermal power stations of Singrauli, Korba, Ramagundam and Farakka, with associated 400 kV transmission, is part of India's power development program which is described in paragraphs 1.31 through 1.35. The four power plants, totalling 8,300 MW, have been located at coal fields, since it is more economical 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 are under construction. The commissioning of the power plant units is scheduled between February 1982 (first 200 MW unit at Singrauli) and April 1990 (last 500 MW unit at Farakka). The Project 3.03 The project represents the second stage of the Ramagundam development comprising three 500 MW units with associated transmission totalling about 1,400 km of 400 kV lines. This extension would bring the power plant to its final installed capacity of 2,100 MW. The project also provides for the purchase of a 6-8 seat, twin engine airplane to be used for supervisory visits of NTPC's present and future plants. 3.04 The Ramagundam development which is described in detail in Annex 14 is being constructed in the Karimnagar district of Andhra Pradesh, south of the Godavari river, in the vicinity of the Godavari coal fields (see attached maps). 3.05 The coal for the Ramagundam development will be supplied from thLe South Godavari coal fields located adjacent to the power plant. The mines belong to the Singareni Colliery Company jointly owned by GOI and the Andhra Pradesh Government. The South Godavari mining area has estimated coal reserves of 1,135 million tons in four seams. The top two seams with an estimated reserve of 567 million tons are of grade suitable for power generation. The extractable reserves of 372 million tonnes, based on a 60 percent recovery in underground mining and 90 percent recovery in opencast mining, would be sufficient to cover the coal consumption capacity of a 2,100 MW power plant for about 50 years. The coal requirement for the power plant would be met from thirteen mines, of which eleven are already in production. The mines are planned to have a capacity of 7.55 million tons by 1988/89. Ramagundam's demand is expected to build gradually from 1983/84 to a maximum of 6.4 million tons by 1992/93, of which 1.9 million tons would be for the fist stage of the power plant (600 MW) and 4.5 million tons for the second stage (1,500 MW). -27- The requirement of the second stage (the Project) would commence from 1987/88. The output from the mines would be adequate to meet the coal requirement of the Ramagundam development. As in the case of the first stage, GOI agreed during negotiations that necessary steps will be taken to ensure adequate coal supplies for the efficient operation of the power plant (para. 6.01d). 3.06 The cooling water system envisaged for the project is a closed circuit system using cooling towers. Water requirements for the power plant would be met from the Pochampad reservoir on the river Godavari, located about 160 km upstream of the project site. The Pochampad reservoir has a live storage capacity of 3.4 billion m3. Although total water requirements of the power plant will be of the order of 85 m3/sec, real water consumption for boiler make-up, ash disposal, addition of cooling water, etc., will be only about 5.6 m3/sec. The consumptive water requirements will be supplied from the Pochampad reservoir through an irrigation canal system which reaches the area of Ramagundam. The Andhra Pradesh Government has confirmed that the necessary water would be made available and also assured that this shall have priority over all other requirements. In order to ensure the continuity of water supply even during canal maintenance or in case of a canal failure, a balancing reservoir at the power plant, which will store its requirement of water for about three months, is being constructed under the first stage of the Ramagundam power project. Estimated Cost 3.07 The estimated cost of the project, excluding interest during construction, duties and taxes, is Rs 11,308 million (US$1,414 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 3,910 million (US$489 million) and the local currency cost at Rs 7,398 million (US$925 million). The estimated costs of the project are set out in Annex 15 and summarized in Table 3.1 below: -28- Table 3.1: ESTIMATED COSTS Local Foreign Total Local Foreign Total - - - Rs million --- - --US$ million - - - Preliminary Works 18.4 - 18.4 2.3 - 2.3 Civil Works 661.6 0.8 662.4 82.7 0.1 82.8 Electrical and Mechanical Plant 1,888.0 2,439.2 4,327.2 236.0 304.9 540.9 Coal Handling and Transportation 180.0 34.4 214.4 22.5 4.3 26.8 Power Transmission (400 kV) 930.4 120.8 1,051.2 116.3 15.1 131.4 Sub-total 3,678.4 2,595.2 6,273.6 459.8 324.4 784.2 Physical Contingencies 217.6 130.0 347.6 27.2 16.3 43.5 Price Contingencies 2,687.2 1,175.2 3,862.4 335.9 146.9 482.8 Total 6,583.2 3,900.4 10,483.6 822.9 487.6 1,310.5 Consultants' and 108.8 9.6 118.4 13.6 1.2 14.8 Engineering Services Administration 705.6 - 705.6 88.2 - 88.2 Project Cost (before duties and taxes) 7,397.6 3,910.0 11,307.6 924.7 488.8 1,413.5 Duties and Taxes 1,232.0 - 1,232.0 154.0 - 154.0 Total Project Cost 8,629.6 3,910.0 12,539.6 1,078.7 488.8 1,567.5 Interest During Construction 662.9 - 662.9 82.9 - 82.9 Total Financing Required 9,292.5 3,910.0 13,202.5 1,161.6 488.8 1,650.4 3.08 The estimates for the main items of equipment are based on the quotations received during 1979 for similar equipment for the third Trombay Project and estimates for the Second Singrauli Thermal Power Project, with prices updated to mid-1981 levels. Transmission costs are also based on estimates received for the 400 kV transmission associated with the first stages of the Singrauli, Korba and Ramagundam thermal power plants and on the costs of 400 kV facilities at various locations in India. Physical contingencies of 10% on civil works and of 5% on plant and transmission costs have been allowed to provide for unforeseeable factors. In assessing price contingencies, it has been assumed that contracts will be fixed price or with ceilings on price inflation for the plant equipment as was the case for NTPC's other projects under construction. Costs for equipment and erection have been escalated at 15% for FY1981, 9% for FY1982, 8% for FY1983, 7% for FYs 1984 through 1986 and 6% yearly after FY1986. :-29 g-ectE Financin-g 3.09 The proposed credit of US$300 rallion, representing about 21% of the cost of the project (excluding duties and taxes and interest during construction), would be applied to the CIF and/or ex-factory costs of plant and equipment, excluding the 500 MW turbines and generators and associated equipment and consultants' services. The turbines and generators would be financed by the Federal Republic of Germany (Kreditanstalt fuer Wiederaufbau (KfW), which has been requested by GO!, and is expected to extend a loan of US$150 million equivalent to support the proposed project in financing those parts of the 500 MW turbo-generator units which will be manufactured in Germany (para. 3.13). A US$30 million loan froTu the OPEC funds is also under consideration. Civil works, plant erection costs, inland transportation costs, interest during construction, duties and taxes and any other costs not financed from the credit of KfW or the loan from the OPEC fund would be financed by GOI in the form of loan and equity share capital2 However, GOI has indicated that it may seek additional sources of financing for the project. Engineering and Construction 3.10 Consultants (United Engineers, U.S.A.) were appointed under Credit 1027-IN (Second Singrauli Thermal Power Project) for NTPC's program for installation of 500 MW units to: (i) review NTPC's basic engineering and design; (ii) assist in the more sophisticated areas of design; and (iii) review specifications, as required by NTPC and the Association. GOI has also agreed to appoint consultants for engineering of 500 MW units under the credit for the Second Korba Thermal Power Project. A similar arrangement is proposed for the project to (i) review NTPC's basic engineering and design; and (ii) assist in other areas as required by NTPC and the Association. Supervisory services for erection and commissioning of the main equiDment, such as turbo-alternator units and steam generators, would be provided by the manufacturers of the equipment. The review engineering consultancy requirements for the project are estimated at about 90 man-months, at an average cost of US$12,500 per man-month, including salary, costs, fees, interrnational travel and subsistence. 3.11 The project is comprised of a number of major works which coordinated to ensure efficient progress. To this end, NTPC has developed comprehensive project management systems, including program coordination and supervision of construction of -,he power stationis and has already appointed a foreign consultant firm (United Engineers, U.S.A.) to review these systems and their initial implementation. The review was taken up in January 1981. To ensure an effective coordination of the projects under construction, NTPC' uses PERT ohLsrtcs, vWhrich not only plan the progress of various physical ncti-vitles but also indicate the phasing and -30- quantum of inputs such as financial resources, manpower of different types, scarce materials, etc. 3.12 The project construction schedule is shown in Annex 16, Project completion is expected by September 1989. Procurement 3.13 Procurement of all equipment to be financed from the proposed credit would be on the basis of international competitive bidding in accordance with the Association's guidelines. Documents for individual contracts above US$2,500,000 equivalent would be subject to prior review by the Association. Bidding documents for such equipment, including tender analyses and recommendations for award of contracts, would be prepared by NTPC, and approved by the Bank Group. To facilitate contract coordination, the invitation to tender for major plant contracts would be on a supply and erect basis. This could include civil works in certain cases where these cannot be di-associated from the plant contract--i.e., coal handling, substation structure, and transmission lines. Local manufacturers would be expected to bid for all categories of equipment. A domestic preference of 15% or the import duty, whichever is less, would be applied in bid comparison for equipment contracts. To prevent administrative procurement delays, in case the lowest evaluated bidder is a foreign manufacturer, GOI has agreed that it would grant import permission for such items without further review by any agency of the Government (para. 6.01e). There are competent local contractors in India and also manufacturing facilities covering most of the equipment for the project. All goods not financed from the proposed credit (and from the expected KfW loan) will be subject to local procurement procedures, which are satisfactory. The 500 MW turbines and generators are being built by Bharat Heavy Electricals Limited (BHEL) under license from Kraftwerk tfnion (KWU), Germany. BHEL is progressively taking over the manufacture of the 500 MW generating units, Although a substantial part of the turbines and generators for the proposed project would be manufactured by BHEL, critical components would be manufactured in Germany by KWU. KfW would finance those parts manufactured in Germany. Disbursement 3.14 The estimated disbursement schedule is given in Annex 17. Disbursements from the proposed credit would be made against 100% of the cost of consultants retained for the 500 MW units (para. 3.10), and against the cost of the equipment to be financed from the proposed credit as follows: (a) 100% of the ex-factory cost of equipment manufactured in India after international competitive bidding; and -31- (b) 100% of the foreign cost of equipment procured from abt - Disbursements will be fully documented in accordance with IDA's standard requirements. Ecological Aspects 3.15 The ecological and environmental aspects of the project were discussed during appraisal. GOI confirmed that the Ramagundam development had received the approval of the Indian National Committee on Environmental Planning for the final installed capacity of 2,100 MW and NTPC agreed to comply with all environmental quality standards prescribed by this committee in the design, construction and operation of the project. 3.16 As in the case of the first stage of the Ramagundam development, the principal environmental concerns with the proposed project are: (a) location; (b) stack emission; (c) heat dissipation; (d) ash disposal; and (e) effluent discharge. These are outlined below: (a) Location. The proposed Ramagundam power station is a pit head station and is situated far from any urban area. Accordingly, there are no problems other than the need to ensure the health and environment of the operating staff who will be housed in a residential area to be constructed some 2.5 km from the power station. They would not be affected because of the high stack. (b) Stack Emissions. Electrostatic precipitators with an efficiency of 99% will be installed and the stack will be 220m high to ensure that emitted particulate matter will be spread over a sufficiently wide area to reduce the density of pollutants to an acceptable level. DusS emission at the stack outlet will be limited to 300mg/m . The sulfur content of the coal is in the range of 0.3% to 0.5% which is low and does not present a pollution problem. The ambient coiicentratiou of S02 and dust at ground level is estimated at 0.05 mg/ml and 0.07 mg/m3, respectively, well below the threshold limits. The above target figures of stack emissions will be monitored after commissioning of the power plant through analysis by chemical and physical methods of carefully collected samples. (c) Heat Dissipation. The cooling water system adopted for the project is a closed circuit system with cooling towers. Hence only blow down from the closed circiit will be discharged into storm water drain. This will not have arny adverse impact on marine life. -32- (d) Ash Disposal. The ash will be pumped as slurry through a pipeline to an ash dump area located to the west of the Kazipet-Ballarshah railway line. Water from the ash disposal area will also be discharged into the Godavari river. Tests at other locations have shown that this does not have any detrimental effect on the ecological system and that the downstream water is fit for irrigation purposes. To reduce pollution due to windblown ash, trees are being planted around the ash disposal area. (e) Effluent Discharge. The effluent from the water treatment plant will be neutralized suitably in neutralizing pits and discharged into storm water drains. Any oil spillage from the fuel oil storage area and transformer yard will be drained to a separate drain and absorbed in the ground through percolation in soak pits. Sewerage from the plant and township area will be treated before discharging it into a natural stream. 3.17 With regard to the safety and occupational health of employees, safety regulations for power stations, to which all operating personnel must confirm, will be strictly enforced. As far as noise levels are concerned the turbine hall of a modern steam turbine power station, which is the noisiest area of the plant, has a sound pressure level of less than 90 decibels which is well below the maximum acceptable threshold for the normal 8 hour/day shift worker. Fans and safety valves are being provided with silencers to limit the noise. All the control rooms will be provided with sound proof doors, windows and walls. Project Risks 3.18 The project represents one phase of an overall development program comprised of 8,300 MW of generating plant and some 7,000 km of 400 kV transmission. It is part of a tightly designed program with plant and transmission coming in at phased intervals throughout the period 1982 through 1991. Maintaining this program on schedule requires careful coordination and expert supervision at all levels. The principal risk is the possibility of slippage which could give rise to delayed commissioning of plant and loss of revenues. With a program of construction of this magnitude, there is no guarantee that some delays will not occur, but these will be kept to a minimum through careful coordination and supervision during construction and careful attention, when placing contracts, to the capability of manufacturers to meet the delivery schedules. -33- 3.19 Other risk areas are in engineering design, equipment quality, cost quality, cost overruns and problems of commissioning and operation during the early operational stage with resultant loss of revenues. There is also the risk of damage due to fire, explosion, etc., but this is covered by insurance provided by the respective contractors during the construction stage and through a comprehensive insurance policy which NTPC is formulating for its operation stage. 3.20 These risks have been carefully assessed and the following safeguards taken: (a) NTPC is being assisted by consultants and sub-consultants, and this should minimize problems due to error at the engineering and design stage; (b) plant and equipment costs are based on similar works currently in progress in India; provision has been made for cost escalation and there should be little risk of any substantial cost overrun; and (c) a number of large generating units will have been in operation for some years before the project is commissioned, thus providing experience and trained manpower for the project. -34- IV. FINANCIAL ANALYSIS Investment Program 4.01 NTPC is currently in the sixth year of an investment program wrhich originally envisaged the construction of four large thermal power stations with an aggregate capacity of 7,300 MW, together with almost 6,000 circuit kilometers of associated 400 kV transmission lines, at an estimated cost of about Rs 41,000 million (US$5,125 million). The power stations and transmission facilities were to have been commissioned on a phased basis during the period February 1982 through March 1988. However, because of rescheduling and expansion of the construction program, the investmeni program has been subject to continuous review during the past five years, with appropriate revisions being made during appraisal of the Ramagundam (Credit 874/Loan 1648-IN), Second Singrauli (Credit 1027-IN), Farakka (Credit 1053/Loan 1887-IN) and Second Korba projects. The revisions iwere necessary to reflect: (a) increases in the expected base prices of equipment; (b) increases in price contingency factors because of higher expected rates of inflation for the period of construction of the balance of NTPC's investment program; (c) rescheduling of the commissioning dates of individual generating plants; (d) the addition of 1,000 MW (two 500 MW units) to the final installed capacity of the Farakka station; and (e) additional transmission facilities at Singrauli, Ramagundam and Farakka. A further minor revision was made during appraisal of the proposed project to reflect a further increase in onlending interest rates by GOI to NTPC (para. 4-.04). 4.02 The financial impact of these revisions is to increase the estimated cost of the initial investment program by about 63% (Rs 25,970 million, US$3,246 million) with the additions to the generating capacity and transmission facilities accounting for about Rs 10,700 million (US$1,338 million) or 42% of the increase. Finance for the increased investment program costs will come from increased internal resources arising mainly during the three year period of the extended construction program (from March 1988 to end March 1991), and from GOI in a combination of long term loans and equity share capital. Financial statements showing both past performance and future forecasts of NTPC's operations are -35- provided in Annexes 18 through 20. Assumptions made in preparing the forecasts are provided in Annex 21. Future Earnings 4.03 NTPC will commence commercial operations in February 1982 when its first 200 MW generating unit at Singrauli is expected to be commissioned. Additional generating capacity, scheduled for commissioning during the succeeding nine year period, is set out in Annex 21, page 1, para 2(a). NTPC's projected earnings are based on the assumption that NTPC will supply bulk power at 400 kV to State Electricity Boards at a tariff level which will enable it to earn a reasonable return on its investment. Initially this was defined under previous Bank Group support of NTPC's projects as being a tariff level sufficient to produce a rate of return of not less than 9.5% on the book valuel/ of the average net fixed assets in service in FY19892/, and applied from the date of commissioning of the first generating unit at Singrauli in FY1982. However, mainly because of the rescheduling of the 500 MW unit construction program, energy sales in FY1989 are now forecast at only about 60% of maximum. Accordingly, the extension in the rate of return qualifying year to FY1991, wghen sales volume would approach 90% of maximum, was agreed under the Second Korba project. 4.04 The Income Statement in Annex 18 shows the projected operating results of NTPC from FY1982 through FY1994. The forecast earnings performance of NTPC is satisfactory. On the basis of the FY1991 forecast the average bulk supply price will be 31.8 paise (US cents 4.0) per kWh, excluding fuel surcharge. This price is used to project the annual revenues each year from FY1982 through FY1991 and has also been maintained thereafter. The bulk supply price compares with 31.7 paise (US cents 4.0) per kWh calculated at the time of the Second Korba appraisal in October 1980 and 29.1 paise (US cents 3.6) per kWh calculated for the appraisal of the Farakka Project and based on a qualifying rate of return year of FY1989. Increases in projected operating costs, profit requirement 1/ There are no requirements within India, for commercial accounting purposes, to note fixed asset and depreciation data at current price levels. The equivalent in real terms of a 9.5% rate of return on a rate base stated at historic cost in FY1991 is about 7.0% (Annex 22). 2/ The first fiscal year in which all generating units at Singrauli were projected to operate at their maximum capacity. -36- (because of increases in the capital base) and interest costsl/ have been offset only partially by the increased sales volume in FY1991 and have resulted in the increase in the bulk supply price. Minor losses in FYs 1982 and 1983 are acceptable as part of NTPC's development program. NTPC will become profitable in FY1984 and, following the rapid commissioning of plant from FY1984 through FY1991, earnings will rise rapidly thereafter, and will reach the stipulated rate of return of 9.5% in FY1991 when the investment program is fully commissioned. Following the decision taken in 1980 to expand the Farakka station's capacity by 1,000 MW, additional earnings will accrue from FY1990 onwards on the incremental output. The rate of return will accordingly rise to 11.8% by end FY1994 when all generating units in each of the stations would be operating at maximum capacity. Consequently as in previous NTPC Bank Group assisted projects, an assurance was obtained at negotiations that NTPC will achieve in FY1991, and maintain thereafter, a rate of return of not less than 9.5% on the net fixed assets in operation, and will set tariffs from the time the first generating unit at Singrauli is commissioned at levels not lower than estimated to achieve the required 9.5% rate of return in FY1991 (para. 6.01f). Taxation 4.05 NTPC is liable for income tax under the Income Tax Acts. However, because of the large capital expenditure program between FY1979 and FY1991, an income tax liability will not arise in the foreseeable future and, accordingly, a tax equalization reserve is not necessary. Internal Cash Generation FY1977-FY1994 4.06 A Statement of Sources and Applications of Funds covering NTPC's current investment program is provided in Annex 19, page 2. As a result of the rescheduling of the commissioning dates, particularly the 500 MW units of the second phase station developments and the addition of 1,000 MW at Farakka, the duration of the initial construction program has been extended by three years through FY1991. A rapid buildup of internally generated funds would occur from FY1990 and would be available to finance future projects. Dividends on equity share capital are not included in the forecasts on the assumption that surplus funds would go towards the expansion of NTPC's activities beyond its current investment program. Recently, GOI indicated that it has under consideration an expanded investment program for NTPC (para. 2.04). After the first year of 1/ GOI onlending rates were increased by 0.5% to 10.75% from July 1, 1980 and by a further 1% to 11.75% from June 1, 1981. -37- operation debt service coverage would be not less than 1.3 times, which is satisfactory. NTPC's Financing Plan (FY1983-FY1990) 4.07 The financing plan for the eight year period during which the project will be constructed is set out in table 4.1 and is satisfactory. The financing plan covers a time-slice of NTPC's total investment program and provides for construction of the ongoing first and second Singrauli and Korba projects, the first and the proposed second Ramagundam projects and the Farakka project, together with the balance of the generation and transmission construction program discussed at paras. 3.01 and 3.02. The investment cost of the proposed project represents about 24% of construction expenditures in the financing plan. 4.08 The proposed Loan would be onlent to NTPC by GOI in accordance with an acceptable onlending agreement as a condition of effectiveness of the Loan (para. 6.02). As in previous operations, the terms of the onlending agreement would provide for maturity in 20 years, including a grace period of five years, and repayment of principal in equal semi- annual installments, with interest payable on outstanding balances at 11.75% per annum. This is the rate of interest at which GOI currently lends to industrial and commercial undertakings in the power sector and reflects the increase of 1% from June 1, 1981 (para 4.04). The rate compares with about 13-15% from domestic lending institutions for similar types of lending., The foreign exchange risk would be borne by the Goverment. An assurance was also obtained during negotiations that GOI will ensure prompt availability to NTPC of sufficient funds to complete the project including any additional funds which might be required due to cost overruns or other unforeseeable factors (para. 6.01g). 4.09 Bank financing of the proposed project, US$300 million, together with Bank Group financing of NTPC's investment program to date, in aggregate US$1,850 million, represents about 20% of the total costs involved, excluding duties, taxes, and interest charged to construction. -38- Table 4.1: NTPC'S FINANCING PLAN FY1983-FY1990 US$ Million Rs Million Equivalent _ Source of Funds: Internal Cash Generation 21,590 2,698 39 Less: Debt Service (14,783) (1,848) (27) Working Capital Increase (1,331) (166) (2) Contribution to Investment 5,476 684 -i- Capital Raised GOI Equity Capital 21,071 2,634 38 IDA Credits/IBRD Loans 11,092 1,354 a/ 20 GOI Loans (incl. KfW and OPEC 17,314 2,197 b/ 32 Loans) Total 49,477 6,185 90 Total Sources 54,953 6,869 100 mmmm~~~~~~~~~~~~~~~~=== ==== m m ==s Requirements: Constructiorn Program 54,953 6,869 100 (including interest during construction) a! Includes the following: Rs US$ Million Million Equivalent Singrauli (Credit 685-IN) 176 21 Korba (Credit 793-IN) 640 76 Ramagundam(Credit 874-IN/Loan 1648-IN) 1,291 154 Second Singrauli (Credit 1027-IN) 1,638 195 Farakka (Credit 1053-IN/Loan 1887-IN) 1,747 208 Second Korba Credit 3,200 400 Second Ramagundam Proposed Loan 2,400 300 11,092 1,354 b/ Includes US$33 million, the difference between actual US$ equivalent of previous Bank Group finance and that calculated using the current exchange rate of Rs8.0 = US$1. Future Finances 4.10 Actual and forecast balance sheets, at March 31 annually from FY1977 through FY1994, are provided in Annex 20 and are satisfactory. The balance sheets reflect the build-up of the construction program, the -39- commencement of commercial operations in February 1982, and the financing of NTPC's capital requirements by GOI through a combination of long-term borrowing and equity capital, in a ratio which would normally not exceed 1:1. Project-wise, equity would be released initially followed later by loan capital. Table 4.2 summarizes NTPC's projected financial position at three significant points in its development: (a) at March 31, 1982 - end of the year in which NTPC will become revenue earning; (b) At March 31, 1990 - end of the year following the commissioning of the proposed project; and (c) at March 31, 1991 - end of the year following the commissioning of the last generating unit in the investment program. 4.11 These forecasts indicate that by March 31, 1982, shortly after NTPC will become revenue earning, total capitalization will be Rs 11,495 million (US$1,437 million), divided between GOI loans, including the onlending of Bank Group finance and equity capital in a ratio of 20/80. Eight years later - end of FY1990, after the proposed project is complete - total capitalization will have risen to Rs 61,891 million (US$7,736 million) with a debt/equity ratio of 45/55. No new debt is forecast after FY1990 towards the completion of the current investment program and this, combined with a significant increase in internal cash generation, will reduce the debt/equity ratio to 42/58 by FY1991. NTPC's authorized share capital will be raised progressively during the period FY1982 through FY1987 from the present 15,000 million (US$1,875 million) to a figure of Rs 35,000 million (US$4,375 million). -40- Table 4.2: FINANCIAL POSITION OF NTPC At March 31 FY1982 FY1990 FY1991 -------Rs Millions-------- Fixed Assets at Cost 2,546 62,495 66,968 Less: Depreciation - 5,876 7,749 Net Fixed Assets in Service 2,546 56,619 59,219 Work-in-Progress 8,985 3,989 - Total Net Fixed Assets 11,531 60,608 59,219 Short Term Deposits - - 1,179 Working Capital (47) 1,283 1,441 Deferred Expenses 11 - - Total Net Assets 11,495 61,891 61,839 Financed by: Equity Capital 9,155 30,226 30,226 Retained Earnings (8) 3,910 5,903 Total Equity 9,147 34,136 36,129 Long Term Debt (including IDA 2,348 27,755 25,710 Credits/IBRD Loans) Total Capitalization 11,495 61,891 61,839 Debt/Equity Ratio 20/80 45/55 42/58 Borrowing Powers 4.12 The Companies Act 1956 (Section 293.1d) limits borrowing by NTPC to an amount equal to the aggregate of the paid up share capital and "free reserves" (i.e., those which are not set apart for a specific purpose), except with the consent of the Corporation in general meeting. During negotiations, an assurance was obtained that NTPC will inform the Bank Group beforehand of any proposal to alter or modify existing limitations on the borrowing powers of its Board of Directors (para.6.01h). Commercial Arrangemens for Sale of NTPC Energy 4.13 Under previous credits and loans NTPC has agreed to prepare bulk supply contracts for the sale of energy on terms and conditions satisfactory to the Bank Group. NTPC intends to complete all the necessary commercial arrangements prior to the sale of energy from each project. In order to ensure that such arrangements are satisfactory, prior to the first sale of energy by NTPC (from Singrauli station in -41- February 1982), during negotiations a draft of the bulk contract for the sale of energy from the Singrauli station was reviewed and found satisfactory in principle. NTPC has also agreed to sell the output of power from the Ramagundam station to SEBs under bulk supply contracts, satisfactory to the Bank Group, a final draft of which will be forwarded to the Bank Group by August 1, 1983 (six months prior to the first sale of energy) (para. 6.01i). 4.14 NTPC recognizes that the regionalization of its bulk tariff would better reflect the nature of its individual thermal power stations as integral parts of regional power systems, at least until a national power grid is established. This could be achieved in a manner acceptable to the Bank Group and compatible with NTPC's tariff covenant with the Bank Group (para. 4.06) by applying the tariff formulation on an individual station basis to better reflect different cost components as between regions. The following regional tariffs would emerge: Paise/kWh Singrauli Northern Region 23 Korba Western Region 30 Ramagundam Southern Region 41 Farakka Eastern Region 34 Average All Regions 32 Variations in the above regional tariffs reflect regional differences in coal prices, investment timing and level of energy output in FY1991. -42- V. JUSTIFICATION General 5.01 The proposed project, defined as the expansion by 1,500 MW of the first 600 MW stage of the Ramagundam thermal power station and associated transmission investment, is justified as the least-cost solution to meel: part of projected base load demand in the Southern Region from 1987/88 onwards. The project's economic internal rate of return is about 15%. 5.02 The minimum of about 7,500 GWh (net of auxiliary use) sent out per year from the project from 1993 onwards (first output is scheduled for 1987/88) will contribute about 9% of total energy supply to consumers in the Region. This is a significant marginal contribution if seen against: the precarious balance that is expected to be achieved in the Southern Region by 1990 even if all identified projects come on stream on time. Comparison of Alternatives 5.03 Given the existing and forecast power shortages in the Southern Region (paras. 1.41 and 1.42), the need for additional capacity is urgent. The necessary base load capacity addition of the required size and reliability can be provided by thermal pit-head plant of the type proposed under the project. Concurrent SEB investment plans provide for complementary hydro capacity development to cover peaking requirements (Annex 10). 470 MW of additional nuclear capacity is planned in the Region during the 1980s. A fully integrated system of Regional investment planning is now being created: steps have been taken by GOI in consultation with IDA to formulate a least-cost long-term investment plzn for the Indian power sector by March 1982, a significant improvement for purposes of future analysis of investment decisions (para 1.52). 5.04 The only realistic alternative solution to the incremental 1,500 MW of Ramagundam is advanced implementation of smaller coal-fired stations that are at present identified for later construction by individual SEBs. The theoretically most attractive solution is the expansion of existing sites. The obstacles in this approach are that the expansion potential of many existing sites is limited, and that many expansion projects are already allocated to be developed concurrently with the project. 5.05 The alternative, consisting of smaller stations, would encompass an expansion of a pithead station in Tamil Nadu, and new load-center stations in Karnataka ad Andhra Pradesh, with a combined capacity approximately equal to that of the proposed project. The Karnataka and Andhra Pradesh sites would require transport of coal. The larger pithead station's size would be 630 MW, while the load-center stations' capacity would amount to about 420 MW each. An appropriate allowance for -43- transmission investment is included in the cost of the alternative solution, reflecting the different needs for power evacuation in the case of scattered individual stations (Annex 23). 5.06 All costs are expressed in economic terms, i.e. in CIF/FOB prices where available, and adjusted by the appropriate conversion factors to border prices where necessary. Unskilled labor has been shadow priced at 75% of the market wage, skilled labor at full market wage. The economic cost of coal was calculated as long-run marginal cost of extraction (Annex 24). The cost of both the project and its alternative are phased to provide capacity and energy in the same pattern (Annex 25). 5.07 The present value of the cost stream of the project is lower than that of the alternative at any discount rate within a reasonable range. The project, therefore, constitutes the least-cost solution for satisfying the future 1,500 MW portion of base load demand in the Southern Region gradually from 1987 onwards. Annex 29 shows the present values of the cost streams of both options, assuming an opportunity cost of capital of 10% as the discount rate, with a discount rate of 13% as a sensitivity test. The cost advantage for the project in present value terms amounts to about Rs 857 million (US$107 million) at 10%, and about Rs 685 million (US$86 million) at 13%. Only under the most pessimistic assumption in the sensitivity analysis (project cost increase by 10% and alternative cost decrease by 10%), the cost advantage for the project is lost. Cost-Benefit Analysis 5.08 A two-stage approximation approach has been adopted for the quantification of economic benefits arising from an expansion of generating plant that is integrated into an existing and growing system: (i) average retail tariffs in the Region have been assumed to represent a proxy for the minimum willingness to pay for power; and (ii) in order to quantify any additional consumer surplus beyond this minimum, the cost incurred by industrial consumers in maintaining and operating standby generating sets has been assumed to represent a proxy for industrial consumers' maximum willingness to pay for continuous power supply. 5.09 The incremental amount of energy sold is adjusted to account for system losses typical for the Region. The weighted average of 1980 tariff revenue at retail level in the Region has been estimated at Rs 0.29/kWh (US$0.04/kWh), and converted to border prices for purposes of the comparison with economic cost. The industrial tariff revenue of about Rs 0.31/kWh (US$0.04/kWh) is replaced by the observed average willingness to pay for continuous power supply, amounting to about Rs. 0.43/kWh (US$0.05/kWh) in economic terms (Annex 26). 5.10 Corresponding to the definition of economic benefits as willingness to pay at the retail level, additional costs of transmission -44- and distribution investment (including operating and maintenance expenses) have been allocated to the cost of the project in line with the general Regional investment pattern (Annex 27). This additional cost is net of the transmission element already included in the project cost. Benefit and cost streams are presented in Annex 28. 5.11 The minimum economic rate of return is about 15%, falling to about 12% if more pessimistic cost and benefit assumptions are tested (Annex 29). The true internal rate of return is likely to be considerab:Ly higher than the minimum quantifiable estimate, if the derived consumers' and producers' surpluses of industrial, agricultural, and commercial output made possible by the alleviation of shortages are taken into account, and if indirect benefits accruing to the Indian economy are fully considered. Furthermore, benefits accruing to non-industrial consumers are likely to be understated by the use of the tariff as benefit proxy. Tariffs 5.12 Using only retail tariffs as measure of the benefit, the internal rate of return of the project is about 8%, falling to about 4% with the most pessimistic scenario (Annex 29). These results indicate that retail tariffs including electricity duty in the Region are economically somewhat inadequate to ensure an acceptable financial return on the proposed project at the retail level. 5.13 The implied financially justified regional bulk supply tariff of about Rs 0.41/kWh (para 4.14) that NTPC would charge its consumers receiving power from the project is compatible with the other bulk exchange tariffs between SEBs that are expected to prevail in the Region during the first years of project output. The average accounting cost of generation as calculated by SEBs may be substantially lower than the NTPC tariff, unless the trend towards a higher share of thermal generation wiLl result in a significant increase in cost. At the time of first sales from the project, no major difficulties should be expected in the willingness of prospective NTPC customers to pay a price that is financially satisfactory for NTPC, except possibly in the case of Kerala and Karnataka, two fully hydro-based States. 5.14 The economic marginal cost of NTPC operations projected for 1987/88, the first year of sales from the project, is below the intended bulk supply tariff at about Rs 0.38/kWh in border price terms, and about Rs 0.44/kWh if converted back to domestic prices. The marginal cost recovery by NTPC, therefore, will be satisfactory in economic terms if the presently planned regional bulk supply tariff would be applied to project output (Annex 31). -45- VI. AGREEMENTS REACHED AND RECOMMENDATION 6.01 During negotiations the following issues have been raised with GOI and NTPC and satisfactory agreements or assurances have been obtained with regard to: (a) The status of preparation of the long-term development plan and timing of the completion of its different parts (para. 1.51); (b) Undertakings, endorsed by the State Governments, to buy allocated power (para. 2.15); (c) audit (para. 2.17); (d) provision of adequate coal supplies (para. 3.05); (e) import permission without Government review (para. 3.13); (f) rate of return and tariffs (para. 4.04); (g) provision of the balance of capital to complete the project, including any additional funds which might be needed due to cost overruns or other unforeseeable factors (para. 4.08); (h) borrowing (para. 4.12); and (i) commercial arrangements for sale of NTPC energy (para. 4.13). 6.02 Effectiveness of the Loan would be conditional on the conclusion of an acceptable onlending agreement between GOI and NTPC (para. 4.08). 6.03 Subject to the foregoing, the project forms a suitable basis for a Loan of US$300 million equivalent. INDIA SECOND RAMAGUNDAM THERMAL POWER PROJECT All-India-Sales and Energy Data 1969/70 - 1979/80 1969-70 1974-75 1975-76 1976-77 1977-78 1978-79 1979-80 1980-81 (provisional) Installed Capacity (excl. non-utility 14,102 18,317 20,117 21,814 23,770 26,681 28,448 30,271 plant) (MW) Electricity Generated (GWh) 57,988 70,191 79,231 88,333 91,206 102,432 104,716 111,514 Electricity sold (GWh) 41,061 52,682 60,246 66,608 68,693 77,293 78,226 Electricity Generation per capita (kWh) 96.2 119.2 132.5 147.2 146.7 159.6 163.6 Electricity Consumption per 76.0 89.9 100.3 111.0 110.9 120.7 122.2 capita (kWh) Proportion of Sales (M) Agricultural and Irrigation 9.2 14.5 14.5 14.4 14.5 15.6 16.9 Railway Traction 3.5 2.9 3.1 3.3 3.5 2.8 2.9 Industry 69.1 62.1 62.4 62.5 61.6 61.7 59.7 Commerce 6.5 8.5 7.3 7.3 7.3 5.6 5.3 Domestic 8.6 8.5 9.7 9.5 10.0 9.8 10.8 Other (Public Lighting, Waterworks 3.1 3.5 3.2 3.0 3.0 4.5 4.4 etc.) Average Annual Growth of Sales (X) 9.9 5.3 14.5 10.5 3.2 12.5 1.2 Losses as percentage of kWh sent out 16.8 20.5 19.4 19.7 19.6 20.0 20.5 August 1981 INDIA SECOND RAMAGUNDAM THERMAL POWER PROJECT All-India Power Supply Position 1980 - 90 (Excluding non-utility) 1979-80 1980-81 1981-82 1982-83 1983-84 1984-85 1985-86 1986-87 1988-89 1989-90 Installed Capacity (MW) 28,448 30,271 33,483 38,027 43,414 48,114 53,741 59,227 71,134 79,253 Peak Availability (MW) 19,139 19,080 20,970 23,855 27,525 31,152 34,476 38,457 46,826 52,857 Peak Demand (MW) 19,139 1/ 19,0801! 24,922 27,296 29,718 32,703 35,972 39,586 47,972 52,546 Surplus (Deficit) (MW) - - (3,952) (3,441) (2,193) (1,551) (1,496) (1,129) (1,146) 311 3/ Energy AvailabilitA- (GWh) 99,480 104,782 132,263 141,990 161,710 183,459 203,041 226,466 275,318 306,400 Energy Requirement3 (GWh) 99,48 1 104,782-/138,929 152,142 165,304 182,077 200,429 220,716 267,832 293,373 Surplus (Deficit) (GWh) - - (6,666) (10,152) (3,594) 1,382 2,612 5,750 7,486 13,027 lt Suppressed by load shedding 2/ At station busbars 3/ At station busbars Source: CEA August 1981 - 48 - ANNEX 3 Page 1 of 2 INDIA SECOND RAMAGUNDAM THERMAL POWER PROJECT CEA Norms for Estimating Capacity and Energy Availability 1. Thermal (i) Effective Capacity: In the case of existing thermal generating units the derated capacity, if any, is considered. In the case of newly commissioned thermal units, no benefits are taken during the first three months after the unit is commissioned and subsequently 50% of the capacity during the next 9 months, and thereafter full benefits are considered. (ii) Retirement of old sets: Deduction on this account are made at e percent ot the installed capacity available at the end of the base year 1977-78 and it is increased cumulatively at
Groupe de la Banque mondiale · Staff Appraisal Report
India - Second Ramagundam Thermal Power Project
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