India - Second Singrauli Thermal Power Project

Document of The World Bank FILE C PY FOR OFFICIAL USE ONLY Report No. 2745b-IN IND]IA SECOND SINGRAULI THERMAL POWfER PROJECT STAFF APPRAISAL REPORT April 25, 1980 Regional Projects Department South Asia Projects This document has a restricted distribution and may be used by recipients niry in mne pertormance 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 8.4 1/ Rs 1 = US$0.1190 1/ Rs 1 million = US$119,047.62 1/ MEASURES AND EQUIVALENTS 1 Kilometer (km) 1,000 meters (m) = 0.6214 miles (mi) 1 Meter (m) = 39.37 inches (in) 1 Cubic meter (m3) = 1.31 cubic yard (cu yd) = 35.35 cubic feet (ft) l1ectare (ha) 10,000 m2 = 2.471 acres (ac) l'Rilogram (kg) 2.2046 pounds (lb) 1 Ton 1 metric ton = 2,200 lbs 1 Kilocalorie (kcal) = 3.968 British thermal unit (Btu) 1 Kilovolt (kV) = 1,000 volts (V) 1 Kilovolt-ampere (kVA) = 1,000 volt-amperes (VA) 1 Megawatt (MW) = 1,000 kilowatts (kW) = 1 million watts 1 Gigawatt hour (GWh) = 1,000,000 kilowatt hours ABBREVIATIONS AND ACRONYMS APS - Annual Power Survey BHEL - Bharat Heavy Electricals Limited CANDU - Canadian Deuterium Uranium (Natural Uranium, Heavy Water Reactor) CEA - Central Electricity Authority CWPC - Central Water and Power Commission DESU - Delhi Electricity Supply Undertaking GOI - Government of India GDP - Gross Domestic Product HPSEB - Himachal Pradesh State Electricity Board HSEB - Haryana State Electricity Board HVDC - High Voltage Direct Current JKSEB - Jammu & Kashmir State Electricity Board KfW - Kreditanstalt fuer Wiederaufbau NHPC - National Hydro Power Corporation NTPC - National Thermal Power Corporation PERT - Programme Evaluation and Review Technique PSEB - Punjab State Electricity Board RAPS - Rajasthan Atomic Power Station REC - Rural Electrification Corporation Limited REB - Regional Electricity Board RSEB - Rajasthan State Electricity Board SEB - State Electricity Board TDO - Thermal Design Organization UNDP - United Nations Development Program UPSEB - Uttar Pradesh State Electricity Board NTPC's FISCAL YEAR (FY) April 1 - March 31 1/ Since September 25, 1975, the Rupee has been officially valued relative to a basket of currencies. As these currencies are floating, the US$/Rs exchange rate is subject to change. Conversions in this report have been made at US$1 to Rs 8.4.  FOR OFFICIAL USE ONLY INDIA SECOND SINGRAULI THERMAL POWER PROJECT STAFF APPRAISAL REPORT Table of Contents Page No. I. THE POWER SECTOR ....................................... 1 Background ............................................. 1 Energy Resources ...................................... 1 Past Bank Group Involvement in the Sector .... .......... 2 Sector Institutions .................................... 3 Existing Facilities - All India ........................ 5 Power Supply/Demand Balance - All India .... ............ 6 Future Development - All India ......................... 7 Regional Demand and Supply - Northern Region .... ....... 8 Future Integrated System Operation ..................... 9 Bank Group's Strategy in the Sector ........ ............ 9 II. THE BENEFICIARY - NATIONAL THERMAL POWER CORPORATION LIMITED ................................................ 13 Legal Status and Authorities ........................... 13 Organization and Management ............................ 14 Training ............................................... 15 Sale of Power from the Project .......................... 16 Accounting Organization and Systems .................... 17 Audit .................................................. 17 III. THE PROGRAM AND THE PROJECT ............................ 17 The Program ............................................ 17 The Project ......... ...... 18 Estimated Cost ......................................... 18 Project Financing ................... 19 Engineering and Construction ........................... 19 Procurement .......... .................................. 20 Disbursements .......................................... 21 Ecological Aspects ..................................... 21 Project Risks ............ ... 22 IV. FINANCIAL ANALYSIS ..................................... 23 Introduction ........... ... 23 Future Earnings ........................................ 23 Taxation ............ ................................... 24 This report is based on information provided by CEA, Department of Power in the Ministry of Energy, NTPC and SEBs during an appraisal carried out by Messrs. B.C. Lynch, V. Antonescu, K.G. Jechoutek and A_E. Bailey (consultant) during May/June 1979. This document hu a restricted distribution and may be used by recipients only in the performance of their omcial duties. Its contents may not otherwise be disclosed without World Bank authorization.  - ii - Table of Contents (continuation) Page No. Financing Plan FY1977-FY1987 ................................. 24 Internal Cash Generation .--------------------.-.------26 Future Finances ............................................ 26 Borrowing Powers ................---------------- 28 NTPC's Bulk Tariff .......................................... 28 Regional Tariffs .------------------------------------------ 28 Commercial Arrangements for Sale of NTPC Power .29 Tariff Level and Marginal Cost .............................. 29 V. JUSTIFICATION . 30 Project Definition .......................... 30 Comparison of Alternative .30 Benefits .................................................... 31 VI. AGREEMENTS REACHED AND RECOMMENDATION .33 ANNEXES 1. All India-Sales and Energy Data for 1969/70, 1974/75, 1975/76, 1976/77, 1977/78 and 1978/79 .................... 34 2. Regional Demand and Supply; Energy Exchanges Among Various Systems 1978/79; Schedule of Yearly Additions to Thermal Generating Capacity; Comparative Demand Forecasts for Uttar Pradesh and Rajasthan - Northern Region .35 3. Sales and Energy Data for 1974/75 - 1978/79 - Northern Region 45 4. Power Supply Position 1976/77-1983/84 - Northern Region ..... 50 5. Tentative Demand Forecasts 1984/85 to 1988/89 - Northern Region .51 6. Yearwise Capacity and Energy Allocation from the Singrauli Development .52 7. Planned Investment in the Power Sector 1978/79 to 1982/83 - Northern Region .53 8. Suggested Terms of Reference for a Study to Prepare a Least-Cost Power Development Program .54 9. Financial Position of the State Electricity Boards .59 10. Terms of Reference of the Rajadhyaksha Committee on Power 62 11. Organization Chart of NTPC .64 12. Organization Charts of NTPC's Finance and Accounting Organization .67 13. Description of the Singrauli Development .69 14. Project Cost Estimates .72 15. Estimated Construction Schedule .74 16. Estimated Schedule of Disbursements .77 17. NTPC - Income Statements FY1979 through FY1991 .78 18. NTPC - Source and Application of Funds FY1977 through FY1991. 80  - iii - ANNEXES (continuation) Page No. 19. NTPC - Condensed Balance Sheets FY1977 through FY1991 ....... 82 20. Assumptions on Financial Projections ........................ 83 21. Annual Rates of Return in Real Terms ........................ 87 22. NTPC's Bulk Tariff (Northern Region) and Bulk Exchange Tariffs in Northern Region ................................ 88 23. Regional Marginal Cost Analysis of NTPC Operations .... ...... 90 24. Definition and Cost of Alternative to the Project .... ....... 96 25. Additional Transmission and Distribution Cost .... ........... 97 26. Shadow Pricing of Costs and Benefits ........................ 98 27. Structure of Operation and Maintenance Costs .... ............ 100 28. Economic Benefits ........................................... 101 29. Economic Costs - Second Singrauli Project and Alternative ... 103 30. Economic Justification: Results ............................ 105 31. Documents Available in the Project File ..................... 107 MAPS IBRD - 14739R IBRD - 14517   INDIA SECOND SINGRAULI 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. In the present stage of economic development, the demand for power grows roughly twice as fast as the economy. Because the power industry is relatively capital inten- sive, its share in total fixed asset formation is increasing rapidly; the power sector, which has made great strides in the last two decades, is today the largest economic sector in the country in terms of investments. The sheer size and increasing complexity of India's power sector, as well as economic considerations, necessitate an approach to system planning which, to a much larger extent than in the past, should concentrate on nationwide power devel- opment and aim at making use of economies of scale through construction of larger, more efficient power stations and interconnected high voltage trans- mission systems. 1.02 The strategy of the Government of India (GOI) is to intensify centralized planning of generation and'high voltage transmission with a view to ultimately centralize control through a national grid with the operation of generating plant on a merit order basis. To this end, GOI established in 1975 two power generating companies, the National Thermal Power Corpora- tion (NTPC) and the National Hydro Power Corporation (NHPC) to construct and operate large thermal and hydro power stations and associated transmission. Consultants have been engaged to assist the Central Electricity Authority (CEA) in undertaking a 400 kV system study to determine the configuration and parameters of the future interconnected national power system. GOI also decided to proceed with the construction of four large thermal power stations of 1,100 MW to 2,100 MW capacity to be built in two stages, located on coal fields and supplying bulk power to the States via an interconnected 400 kV transmission system. The construction of three such developments, the 2,000 MW Singrauli, the 2,100 MW Korba and the 2,100 MW Ramagundam projects, has been started with IDA/Bank financial assistance. This comprises 600 MW of generating plant and transmission for each project (Credits 685-IN Singrauli, 793-IN Korba, 874-IN and Loan 1648-IN Ramagundam). The second stage of Singrauli, comprising two additional 200 MW units and two 500 MW units with associated transmission facilities, is the subject of this report. An IDA credit of US$300 million is proposed. Energy Resources 1.03 India's main commercial energy resources are coal, oil, natural gas and hydro power. There are also resources of nuclear fuels, principally uranium and thorium, and India's power program includes the construction of further "CANDU" type heavy water reactors using domestically produced natural  - 2 - uranium as fuel. Two nuclear power stations have been constructed to date and a third is under construction. Some geothermal energy sites have also been identified, but the potential appears to be limited. 1.04 Coal is by far the most extensive indigenous fossil fuel; reserves are estimated at 83 billion tons of which some 21 billion tons have been proven. Additionally, total reserves of lignite at the Neyveli field in Tamil Nadu are estimated at around 2 billion tons. If low quality coal, e.g., coal with high ash and moisture content, is excluded, the estimate of commer- cially usable coal and lignite is reduced to approximately 24 billion tons which, on a forecast countrywide usage, would be adequate for some 50 years under current assumptions of economic growth. 1.05 By comparison with coal, proven reserves of oil are small. However, oil and gas exploration programs are still going on. Exploration and drill- ing activities to date have already proven an estimated 230 million tons on shore, and recent off-shore discoveries west of Bombay in the Arabian Sea have led to delineation of fields with proven recoverable reserves of about 250 million tons of crude oil and 30 billion cubic meters of natural gas. Other reserves of natural gas, which are found in India both alone and in associa- tion with crude oil, are estimated at over 100 billion cubic meters. 1.06 The potential of hydroelectric power resources is estimated at 70,000 MW of which some 11,000 MW has already been developed. A further 4,700 MW is scheduled for commissioning by FY1984 (see Table 1.2) and some 23,000 MW is currently under investigation or scheduled for investigation. Some 70% of the total potential is in the Northern and Northeastern regions. Additional emphasis on hydro power investments is planned. 1.07 Oil and natural gas have important alternative uses and it is un- likely that they will be a significant factor in the generation of electric power. The Government intends, therefore, to base the development of generat- ing facilities for the foreseeable future on coal or lignite burning thermal stations and hydroelectric power stations and to gradually develop a small nuclear program. Past Bank Group Involvement in the Sector 1.08 The Bank has made nine loans to India for power projects amounting to US$334.5 million and IDA twelve credits totalling US$1,171 million. Of this amount US$870.5 million involves 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. Nine loans and credits for generating plant, the Beas project (Credit 89-IN) and the first three transmission projects (Loan 416-IN Credits 242-IN and 377-IN) have been completed. The Fourth Transmission Project (Credit 604-IN) is nearing comple- tion, and the whole credit amount of US$150 million has been committed. The Third Trombay Thermal Power Project (Loan 1549-IN) was approved in April 1978. The Ramagundam Thermal Power Project (Credit 874-IN and Loan 1648-IN) and the  -3- Second Rural Electrification Project (Credit 911-IN), are still in the preli- minary implementation stage and no disbursements have yet been made. Commit- ments to April 30, 1980 totalled some US$500 million on the four thermal power plant projects (Singrauli, Korba, Ramagundam and Trombay) and US$150 million on the two Rural Electrification Projects (Credits 572-IN and 911-IN). 1.09 The Singrauli, Korba and Trombay projects are on schedule. The Ramagundam Project, the Fourth Power Transmission Project and the First Rural Electrification Project are proceeding satisfactorily notwithstanding initial delays in implementation and the substantial delay in preparation of specifi- cations and review of tenders for the more sophisticated load dispatch equip- ment in the case of the transmission project. Sector Institutions 1.10 The principal agencies in the industry are: (i) the State Elec- tricity Boards (SEBs); (ii) the Atomic Energy Commission; (iii) the Central Electricity Authority (CEA); (iv) Regional Electricity Boards; (v) the two Central Power Corporations (NTPC and NHPC); and (vi) the Rural Electrification Corporation Ltd (REC). 1.11 The SEBs are constituted by the State Governments under the provi- sions of the Electricity (Supply) Act, 1948, to promote the coordinated development of the generation, supply 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 Bombay Suburban Elec- tric Supply Undertaking, and private utilities, the largest of which are the Tata Electric Companies, (Bombay), the Calcutta Electric Supply Company, and the Ahmedabad Electric Supply Company. At the present time, the States effec- tively 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. 1.12 The CEA was formally created in 1950 with responsibility for devel- oping a national policy for power development and coordinating the activities of the various planning 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 at that time 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 responsi- ble to the Prime Minister, deals with nuclear power generation. 1.13 CEA's powers were enlarged through amendments to the general provisions of the Electricity (Supply) Act, 1948, which were enacted on  -4- 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 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. The emerging role of CEA in financial affairs is evidenced by the conveying of statutory authority 1/ on it to formulate, in conjunction with GOI, policy for the accounting treatment of depreciation of fixed assets in the power sector in India. CEA is also playing a leading role in advising State Governments on the measures to be taken to implement the amendments to the financial provisions of the Electricity (Supply) Act, 1948, and is also providing information to the various working panels of the Rajadhyaksha Committee (para 1.42). A recent major achievement for the CEA was the adop- tion by the SEBs of a uniform system of commercial accounting, devised by it over a period of time. This system, which applies to all SEB accounts from April 1979, brings uniformity to the procedures relating to the maintenance of accounts, and, for the first time, enables direct inter-Board comparison of financial results. 1.14 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 and with the resultant increasing complexity of operation, GOI sees the necessity for an integrated national approach to sector development. 1.15 Four Regional Electricity Boards (REBs), for the Northern, Southern, Eastern and Western regions, were established between 1964 and 1966 by common resolution of the State and Central Governments, to help develop integrated power systems in their respective regions, and thus prepare for the transition from separate power systems at State level to regional systems and finally to an interconnected national grid. 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, coordinate overhaul and mainten- ance programs, determine generation schedules to be followed and the power 1/ Amendment of Section 68 of the Electricity (Supply) Act, 1948.  -5- available for transfer between States and 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. 1.16 NTPC and NHPC are at present not intended to take a leading role in the generation and sale of power in the States. At the present time, the construction of four large central thermal power stations has been started as mentioned in paragraph 1.02. All of these developments are being constructed and will be operated by NTPC. NHPC will construct and operate large hydro- electric 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 commis- sioned to undertake. In most States, the SEB will continue for some time to be the largest power undertaking. 1.17 REC was incorporated in July 1969 under the Indian Companies Act, 1965, as a company wholly owned by GOI, under the general supervision of 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 1.18 The total installed generating capacity in the whole of India as of March 31, 1979 was just under 29,000 MW, including about 2,225 MW of non- utility capacity, mostly thermal, which is owned by major industrial consumers to meet their own needs. The generating capacity is shown in Table 1.1 below: Table 1.1: INSTALLED GENERATING CAPACITY AS OF MARCH 31, 1979 (MW) Region Conventional Thermal Nuclear Hydro Total Northern 3,773 220 3,718 7,711 Western 5,204 420 1,770 7,394 Southern 2,193 - 4,303 6,496 Eastern 3,854 - 895 4,749 North-eastern 188 - 146 334 Andaman and Nicobar Lakshadweep 6 - - 6 Non-utility Capacity 2,225 - - 2,225 Total 17,443 640 10,832 28,915 Source: CEA.  - 6 - 1.19 Transmission is at 132 kV and 220 kV and, generally, load centers are interconnected by 132 kV and 33 kV subtransmission lines. Distribution voltages are 11 kV and 415/240 V. The supply, in general, is reliable, but power shortages, especially during the summer months, necessitate shutdowns and brownouts. System losses have been reduced in recent years but they are still high accounting for about 20% of units sent out. This subject is under examination by the "Rajadhyaksha Committee" (see para 1.42). Power Supply/Demand Balance - All India 1.20 India's installed power generating capacity increased at an annual rate of 10.3% 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 the 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 imple- ment projects in accordance with planned schedules; inadequate transmission development; operating and maintenance problems leading to a low plant avail- ability factor of around 72%; inadequate budget allocation and the absence of monsoon rains, particularly during the early 1970s, leading to lower hydro output. 1.21 The shortage situation was most serious in 1974/75 and 1977/78 and is again extremely serious now, particularly in the Eastern Region. The estimated deficit of energy throughout India in 1974/75 was about 11,000 GWh (14.1%); this fell to 8,600 GWh (10.3%) in 1975/76 and to 5,100 GWh (5.8%) in 1976/77, but increased to 15,800 GWh (15.5%) in 1977/78. Data for 1978/79 indicate that the deficit was of the order of 10%. 1.22 Power shortages, particularly in the industrial sector, have affected the output of the country and the cost in terms of industrial production fore- gone 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, could well be in the neighborhood of 3% of GDP. 1/ 1.23 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 agri- culture and irrigation have increased substantially during the 1970s, mainly because of the rural development programs. Industrial demand as a proportion of the total demand has declined, and there has been a small but steady increase in domestic demand. It is expected that this pattern of demand will continue with a gradual improvement in the annual load factor. 1/ See: India, Economic Issues in the Power Sector, 1979 (World Bank Report No. 2335-IN, paragraph 68).  -7-. Future Development - All India 1.24 The countrywide peak demand in 1977/78 was 15,520 MW; according to CEA's estimates, unconstrained demand was expected to increase to about 20,300 MW by 1979/80, 18,600 MW of which are being met by available capacity. Installed capacity by 1979/80 was expected to reach about 31,900 MW of which 29,700 MW would be utility plant with the balance of 2,200 MW non-utility. 1.25 The development program provides for an expansion of generating capacity during the five-year period 1979/80-1983/84, including the nuclear power plants which are scheduled to come into operation during that period, by about 19,000 MW, so that the total planned installed capacity would be about 45,000 MW by 1983/84. The additional capacity scheduled for commis- sioning during this period is shown in more detail in Table 1.2. Furthermore, the construction of some 15,000 km of 400 kV transmission lines is planned to enable full integration of the regional systems and the evacuation of the output from the proposed large thermal power stations. Table 1.2: SCHEDULE OF PLANNED ADDITIONS TO CAPACITY DURING THE PERIOD 1979/80-1983/84 /a Conventional Thermal Nuclear Hydro Total ------------------- (MW) -------------------- Northern 2,900 455 1,300 4,655 Western 5,270 - 521 5,791 Southern 2,100 470 2,310 4,880 Eastern 2,710 - 305 3,015 North-eastern 298 - 261 559 Total 13,278 925 4,697 18,900 /a Excludes non-utility capacity. Source: CEA. 1.26 Table 1.3 shows the planned annual installed capacity aggregating about 45,600 MW in 1983/84, the available capacity, the peak load and the forecast of energy requirements and availability (not taking into account diversity). The data referring to the peak load and energy requirement in 1978/79 show the demand constrained by supply. The estimated unsuppressed power and energy demand would have been about 10% higher (see para 1.21). The forecasts of peak load and energy requirements are based upon continuous monitoring of development trends during the preparation of the annual electric power surveys of India. If the program of generation development can be achieved on time, the present shortage of energy would be eliminated from 1982/83 on, but there would still be a capacity deficit through the five-year period due to a low availability factor of generating plants. The peak avail- ability in India under present operating conditions, is around 60% of installed capacity. This availability factor is expected to improve gradually as a result of the development of system interconnection and the improvement of maintenance practices.  - 8 - Table 1.3: INSTALLED CAPACITY, PEAK AVAILABILITY, PEAK LOAD, ENERGY AVAILABILITY, AND ENERGY REQUIREMENT ALL-INDIA 1978/79-1983/84 1978/79 1979/80 1980/81 1981/82 1982/83 1983/84 Installed Capacity (MW) /a 26,741 29,734 33,009 35,585 40,804 45,590 Peak Availability (MW) 16,268 18,566 20,968 22,171 25,443 28,822 Peak Availability Factor (%) 61 62 64 62 /c 62 /c 63 Peak Load (MW) 16,268 /b 20,348 22,443 24,717 27,334 30,068 Surplus (Deficit) (MW) - (1,782) (1,475) (2,546) (1,891) (1,246) Energy Availability (GWh) 97,376 103,549 117,855 131,496 151,036 171,949 Energy Requirement (GWh) 97,376 /b 112,700 124,408 137,089 150,819 166,298 Surplus/(Deficit) (GWh) - (9,151) (6,553) (5,593) 217 5,651 Ia Excludes non-utility capacity. lb Demand constrained by supply. Ic Reduction in availability factor due to commissioning of hydro plant. Source: CEA. 1.27 Table 1.3 also indicates that both peak load and energy requirement are estimated to grow at an average annual rate of around 10% during the five year period 1978/79-1983/84. The forecast capacity deficit decreases from around 10% of the system load in 1979/80 to 4% in 1983/84 and the energy availability exceeds energy demand by some 3% in 1983/84. These are varia- tions which are less than the accuracy of any of the forecast data inputs, but they demonstrate that, if anything, a case could be made for sanctioning more capacity than presently planned for commissioning during the five-year period ending 1983/84, particularly since All-India data mask shortages in specific regions, which may develop due to insufficient interconnection. Regional Demand and Supply - Northern Region 1.28 The major authorities supplying the Northern region are the Uttar Pradesh State Electricity Board (UPSEB), the Punjab State Electricity Board (PSEB), the Haryana State Electricity Board (HSEB), the Delhi Electricity Supply Undertaking (DESU), the Rajasthan State Electricity Board (RSEB), the Jammu and Kashmir State Electricity Board (JKSEB), and the Himachal Pradesh State Electricity Board (HPSEB). NTPC operates the Government-owned 510 MW thermal station at Badarpur. Each of these authorities owns either totally or partly generating facilities and (with the exception of NTPC) supplies electricity to final consumers. Interchanges of temporary power surplus are common. 1.29 The Bhakra/Beas hydroelectric generating complex is jointly owned by the SEBs of Punjab, Haryana, and Rajasthan. These SEBs draw energy from thi6 facility in accordance with their ownership shares. In addition, energy is supplied on a contractual basis to "common pool consumers" such as part of Himachal Pradesh, the Nangal Fertilizer Factory, Chandigarh, and Jammu and Kashmir. The largest intra-regional transfers are recorded between the  - 9 - Bhakra/Beas complex and its owners and bulk consumers, the second largest transfer occurs from the Badarpur thermal power station to DESU. Annex 2 describes the regional demand and supply situation in quantitative detail. 49% of installed regional capacity is thermal, 48% hydro, and the remainder nuclear. This hides significant differences between States: only UPSEB, DESU and the Central Sector are not heavily dependent on hydro generating facilities. Installed capacity has been growing at a rate of about 13% p.a. in recent years--firm available capacity, however, only at 9% p.a., reflect- ing a falling availability percentage. Availability is expected to improve by 1983/84, by which time an additional 4,655 MW are expected to have been added to the existing capacity, most of it thermal and nuclear. 1.30 The region is less industrially oriented than the Indian average-- only 52% of consumption is attributable to industry, compared to a national average of 66%. Agriculture, with its greatest burden on the supply system, is significantly more important than on an All-India basis. Energy consump- tion has been growing at an average annual rate of 14.5%, with fluctuations depending on hydro availability. Some reduction in technical losses has been achieved (Annex 3). 1.31 Peak unconstrained capacity demand is expected to exceed available capacity for the foreseeable future: the anticipated shortfall will be growing steadily to reach more than 1,100 MW in 1983/84. It is likely that persistent shortages will continue well beyond 1984 (Annexes 4 and 5). In 1983/84, the capacity of the proposed project's first stage will be the equiv- alent of 7% of regional capacity. At the time of commissioning of the last unit, the proposed project will represent about 3% of potential unconstrained regional capacity demand (Annex 6). The shift of responsibility for power generation from SEBs to NTPC is reflected in the lower anticipated percentage of the SEBs' investment programs devoted to generating facilities (Annex 7). All supply authorities in the region had to impose restrictions on demand in 1978/79. Restrictions are widespread in Uttar Pradesh, imposing large cuts on capacity demand and energy consumption (Annex 2), mostly borne by industry. Rotation of supply to rural areas is common, as is ad hoc load shedding. Future Integrated System Operation 1.32 With the increasing size of the power sector in India and its far- reaching impact on the country's economy, annual surveys and Five-Year Plans at the State level have become insufficient as a basis for power development planning. The larger size of power plants, their consequent longer construc- tion 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. 1.33 Recognizing the need for coordinated power development throughout the country, provision was made in Credit 604-IN to help finance the cost of consultants to study the technical, financial and economic aspects of a long-term national plan for the sector. Such a plan should include, inter alia, detailed demand forecasts, investigation of power generation schemes  - 10 - to meet load growth requirements for a 15-20 year period (indicating costs and sequencing of investments to optimize resources), development of primary grid configurations, including the 400 kV system study which CEA has started but which has come to a temporary standstill mainly due to lack of overall plan- ning, coordination of power plans with plans for other sectors (determining resource requirements), and recommendations on responsibilities and needed operational policies at the State, regional and national levels (Annex 8). Such a study is an essential prerequisite for formulating sound policies for future development of the sector, and the Government has indicated its inten- tion to complete such a study by April 1982. 1.34 The operation of regional systems, which will be integrated in the future in a national grid, requires large numbers of personnel who would have to be trained in the use of sophisticated load dispatch equipment and inter- connected systems operation. A UNDP project designed to assist CEA in devel- oping programs for training staff to operate the future load dispatch centers came to a halt in 1977, primarily because of personnel problems, and lack of counterpart staff. GOI's plans to revise this project, in consultation with UNDP, were discussed during negotiations. These plans would form part of a wider program for strengthening systems operation and training. The Associa- tion would be kept informed about the development of such program. Bank Group's Strategy in the Sector 1.35 The Bank Group's strategy in its involvement in the Indian power sector, has been one of co-operation with GOI in seeking solutions to the many difficult and politically sensitive problems which have confronted the Indian electricity supply industry since Independence. The sensitivity of Center-State relations, because of concurrent jurisdiction over the electri- city supply industry, has dictated that a policy of persuasion rather than one of explicit leverage would produce better results. 1.36 The Bank Group's main objectives in the sector are: (a) assistance in accelerating the installation of gene- rating capacity and promoting measures to improve the operation and maintenance of existing plant 1/ in order to gradually eliminate the prevailing power shortages in the country; (b) assistance in introducing long-range system plan- ning on a nationwide basis which would assure imple- mentation of a least-cost power development program; (c) promotion of appropriate measures with respect to improving the sector organization and training; and 1/ This subject is dealt with in the terms of reference of both the suggested Least-cost Power Development Study (Annex 8, para. 3) and the Rajadhyaksha Committee (see para 1.42 and Annex 10).  - 11 - (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 designing of appropriate tariff systems. 1.37 Progress towards achieving the above goals has been hindered by constitutional factors. Under the Electricity (Supply) Act 1948, 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 implement- ation of most actions. The States operate, and develop, through their Elec- tricity Boards, most of the power facilities. The consequence of this arrange- ment in many instances has been a parochial approach where a national or at least regional approach would have been more beneficial. On the other hand, it is debatable whether Central initiative could have been taken much further in the time available. The radical proposal which would have enabled power system generation and bulk supply to be exclusively a Central responsibility, would have meant a considerable upheaval and would have have raised fundamental political and constitutional issues going well beyond efficiency considerations. 1.38 Given these difficulties, results achieved so far have been encourag- ing. They are the following: (a) with the establishment of the Regional Electricity Boards (REBs, para 1.15) and later of NTPC and NHPC, the first important steps towards an improved organizational struc- ture 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 1.12 and 1.13); (c) a recent amendment of the financial provisions of the Electricity (Supply) Act 1948 requires that tariffs be set at levels sufficient to enable the SEBs to finance from internal sources a reasonable proportion of their investment programs; (d) recently, SEBs in the Northern Region and the Delhi Electricity Supply Undertaking (DESU), have developed and partially implemented plans designed to restore the covenanted rate of return of 9-1/2% (Credit 604-IN). These plans consist of tariff increases, rationalization of manpower requirements and other cost effective measures; (e) with a view to the reassessment of tariff policies, the majority of the SEBs have recently completed  - 12 - 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. To assist in this standardization process, CEA is establish- ing a specialist department to interact with the SEBs and to keep the Bank Group advised of future developments; and (f) NTPC's generation/transmission construction program (paras 3.01 and 3.02), which is in the process of staged implemen- tation with Bank Group assistance, will make an important contribution to the gradual elimination of the present deficit in the country's power balance. The proposed project would help to continue this program. 1.39 There are two major remaining areas which have been the cause of con- cern to the Bank Group and also have been the subject of continuing dialogue with GOI. They are: (a) the weakness of nationwide long-range planning for power development; and (b) the weak financial position of a number of SEBs which, for instance, have not always been able to achieve the covenanted rate of return of 9-1/2%. 1.40 In the continued effort of the Bank Group in dealing with the long- range problems of the power sector in India, it was decided to concentrate on the above two areas. During appraisal and negotiations, discussions were held with CEA, NTPC and NHPC on the content of a long-range power development study designed to prepare a least-cost power development program, CEA's capa- bility to undertake such study with its own staff, and the possible need for consultants' support (para 1.33). Agreements were reached during negotiations on the preparation of a least-cost development program based on the terms of reference suggested by the Association. 1.41 From a commercial point of view, the financial performance of several SEBs, the sole customers of NTPC, has been marginal (for detailed explanation see Annex 9) and even in years when 9-1/2% rates of return were achieved, a number of SEBs were not able to meet their debt service require- ments. 1/ There are several reasons for this unsatisfactory performance, 1/ However, in all States except one, excise taxes or duties are levied on electricity sales. Including such taxes as a benefit to the States/ SEBs increases the returns by up to 5 percentage points. Furthermore, a recently enacted GOI tax on kWh generated is also equivalent to a return of about 2-3 percentage points. The total return in economic terms is therefore substantially higher than the commercial return to the SEBs.  - 13 - such as insufficient generating capacity which does not permit utilization of the market potential to the fullest extent, less than efficient operating of existing plant, lack of monsoon rains in the Eastern Region leading to severe load shedding and blackouts, railroad and coal mine strikes resulting in insuf- ficient coal supply, and low tariff levels. In the Northern Region (supply area of the Singrauli station), the SEBs and the DESU have taken steps to redress the shortcomings (para 1.38d). The GOI representatives indicated during negotiations that these organizations were currently operating at levels which are expected to achieve rates of return of at least 9.5%, net of taxes. 1.42 Indian authorities have recognized that with the rapidly expanding power sector in the coontry, all aspects of the sector have to be reviewed and that satisfactory solutions have to be found for the various sector prob- lems. Consequently, GOI has established a high-level committee in November 1978, known as the "Rajadhyaksha Committee", so called after the name of its Chairman. This committee, whose terms of reference are attached as Annex 10, has been assigned the task to examine and make recommendations for improve- ments of the following aspects of the power sector: (a) power planning; (b) project formulation and implementation; (c) operation and maintenance; (d) organization and management; (e) finance, financial management and tariffs; (f) rural electrification; and (g) research and development. Draft reports by the seven expert panels assembled for this purpose have been completed and are under review by the committee. The committee is expected to submit its findings to GOI during 1980. The Bank Group will continue to take an active interest in the committee's progress, and it is recognized that the Bank Group may have to modify its approach to the problems of the Indian power sector in case the committee recommends approaches different from the present Bank Group approach, but equally acceptable. For example, one of the major concerns would be that consumers contribute more towards the cost of power supply facilities through allowing their SEBs to generate internally a reason- able proportion of their capital investments. 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  - 14 - 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 in May 1979 to Rs 3,000 (US$357 million). The Corporation has a Board of Directors consisting of not less than four and not more than fifteen, some of whom are part-time. 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 has been established are: (i) to design, construct, and operate large central thermal power stations and projects; 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 and sold in bulk to State Electricity Boards. Later this system will be part of the 400 kV interconnected regional system which 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 possi- ble that NTPC might ultimately take over the 510 MW Badarpur station near Delhi (ultimate planned capacity 720 MW). Presently NTPC is in charge of the operation of Badarpur on a management fee basis. Organization and Management 2.05 NTPC's organization which at present is necessarily construction oriented is shown in Annex 11, page 1. The complete range of management systems for all disciplines now under formulation are shown in Annex 11, pages 2 and 3. These are based on the philosophies explained in the NTPC publication "Framework for Project Management" which was discussed with NTPC during negotiations for the Ramagundam project and further reviewed by the mission during appraisal. The organization is adequate. 2.06 NTPC has adopted a two-tier organizational structure: one at the central/corporate level and the other for the projects. In addition to the accepted corporate level, activities such as the development and formulation of policies, and other services relevant to the projects, have been centralized; these are Technical Services, Contract and Procurement Services, Quality Assurance and Expediting and Project Management Services. Other departments at the central level are Corporate Planning and Marketing, Corporate Finance, Personnel and Administration.  - 15 - 2.07 The second 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 Chairman and Managing Director was appointed in early 1976 and the number of staff appointed by February 29, 1980, was 2,658 comprising 523 executives, 131 executives in training and 2,006 non-executives. NTPC has also taken over the majority of the employees of the Badarpur Project and Power Station (see para 2.04). 2.09 Present indications are that NTPC is developing along sound lines. It has a Chairman and Managing Director who is a competent administrator with an established reputation in the formation and development of large industrial undertakings. He has taken a great personal interest in developing a compre- hensive project management system as well as designing the organization and procedures, while building up an establishment of highly motivated engineers and staff. Remarkable progress has been made in all activities in the four years since his appointement 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 organiza- tions are effectively functioning at the Singrauli, Korba and Ramagundam proj- ects. The centralized functions which, in addition to the corporate person- nel, are planning and finance, and provide the engineering, contracting and project management input. They are organized to meet the project 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 from a present 2,658 to a figure in the neighborhood of 10,000. The importance, therefore, of implementing training programs for the various expertises required during the construction and operational phases cannot be too highly stressed. 2.11 Fortunately, NTPC has placed special importance on this aspect of its organization, and training programs are being developed by the Corpora- tion which will, in due course, be backed by a training school equipped with a simulator, financed from funds of Credit 793-IN, and other modern facilities for instructing and training the operating staff. 2.12 NTPC's training programs are presently concentrated on pre- operational spheres of activity such as Planning, Design, Construction and Management. Some of the current major activities are:  - 16 - (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 imple- mented by NTPC's consultants. 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 third group comprising 100 trainees was recruited during 1978 and joined the professional engineering training course which started on November 15, 1978. The fourth group comprising 131 trainees was recruited in 1979 and the training was started on November 25, 1979. The training programs have been well designed to provide exposure to power 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. 2.13 With the first 200 MW generating unit scheduled to commence commer- cial operation in FY1982, 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 to 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. 2.14 On-the-job training has high priority. The methodology includes classroom lectures, participation in group exercises and discussions sup- ported 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 GOI proposes to allocate 85Z of Singrauli's power to the SEBs of Uttar Pradesh, Punjab, Haryana, Rajasthan and the DESU, the remaining 15% being sold in accordance with priorities to be determined by CEA to States with the greatest need. The Association has received undertakings from the respective SEBs and DESU confirming that they would take power in accordance with agreed allocations, in aggregate not less than 85% of the output of power from the project.  - 17 7 Accounting Organization and Systems 2.16 NTPC and its management consultants report good progress in the planning of NTPC's finance and accounting organization (Annex 12) and in the design and implementation of accounting systems and procedures. The design of systems for both the construction and operational phases of NTPC's activ- ities 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 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 cente'r. 2.17 Current problems being faced by NTPC and its consultants in build- ing up the accounting organization are: difficulties in obtaining adequately qualified staff; retaining staff at project sites, and the introduction of tighter controls in the management of materials on sites. This latter prob- lem will be resolved by the introduction of the systems for inventory control which have been planned by management. These would include continuous stock checking and the use of more sophisticated weighing and measuring facilities. The personnel problems are likely to be more difficult to resolve. Audit 2.18 The audit of NTPC's accounts and records is undertaken by a profes- sional 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. The current auditor Messrs. V. K. Mehta and Company, Chartered Accountants, Delhi, has audited NTPC's accounts since its incorporation on November 7, 1975, and their audit reports have expressed satisfaction at the state of the company's affairs during this period. 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 loan, to submit to the Association/Bank audited financial statements within seven months of the end of the fiscal year to which they relate, together with a certified report by the auditor, and a review of the accounts by the Director of Commercial Audits. This has been restated in connection with the proposed credit. III. THE PROGRAM AND THE PROJECT The Program 3.01 NTPC's present development program comprising the four central thermal power stations Singrauli, Korba, Ramagundam and Farakka, with asso- ciated 400 kV transmission, is part of India's power development program which is described in paragraphs 1.24 through 1.27. The four power plants,  - 18 - totalling 7,300 MW, have been located on coal fields, since it is more econo- mical 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 3 x 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 July 1989 (last 500 MW unit at Ramagundam). The Project 3.03 The project represents the second stage of the Singrauli develop- ment comprising two additional 200 MW units and two 500 MW units with asso- ciated transmission totalling about 2,000 km of 400 kV lines. This extension would bring the power plant to its final installed capacity of 2,000 MW. 3.04 The Singrauli development which is described in detail in Annex 13 is being constructed on the fringe of the Rihand Reservoir close to the Sin- grauli coal field deposit at Kota in the Mirzapur district of Uttar Pradesh (see attached maps). Estimated Cost 3.05 The estimated cost of the project, excluding interest during con- struction and duties and taxes, is about Rs 7,175 million (US$854 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 1,199 million (US$238 million) and the local currency costs at Rs 5,176 million (US$616 million). The estimated costs of the principal features of the proj- ect are shown in Table 3.1 below, and in more detail in Annex 14. Table 3.1: ESTIMATED COSTS Local Foreign Total Local Foreign Total ------Rs million ------ --------US$--------- Preliminary Works 2.7 - 2.7 0.3 - 0.3 Civil Works 449.3 7.7 457.0 53.5 0.9 54.4 Electrical and Mechanical Plant 1,761.3 1,289.4 3,050.7 209.6 153.6 363.2 Coal Handling & Transportation 112.6 7.4 120.0 13.4 0.9 14.3 Transmission (400 kV) 1,032.4 129.9 1,162.3 122.9 15.5 138.4 Sub-Total 3,358.3 1,434.4 4,792.7 399.7 170.9 570.6 Physical Contingencies 190.2 72.2 262.4 22.6 8.5 31.1 Price Contingencies 1,217.9 467.3 1,685.2 145.0 55.7 200.7 Total 4,766.4 1,973.9 6,740.3 567.3 235.1 802.4 Engineering & Administration 409.2 25.2 434.4 48.7 3.0 51.7 Project Cost (before Duties & Taxes) 5,175.6 1,999.1 7,174.7 616.0 238.1 854.1 Duties & Taxes 505.9 - 505.9 60.2 - 60.2 Total Project Cost 5,681.5 1,999.1 7,680.6 676.2 238.1 914.3 Interest during Construction 528.4 - 528.4 62.9 - 62.9 Total Financing Required 6,209.9 1,999.1 8,209.0 739.1 238.1 977.2  - 19 - 3.06 The estimates for the main items of equipment are based on the quotations received during 1977, 1978 and 1979 for similar types of plant and equipment for the first stage of the Singrauli and Korba developments, in the case of the 200 MW units, and for the Trombay Project, in the case of the 500 MW units. Prices were escalated to 1979 levels. Transmission costs are equally based on estimates received for the 400 kV transmission associated with the first stage of the Singrauli development and on the costs of 400 kV construction 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 fixed price contracts and contracts with ceilings on price inflation for turbogenerators and boilers, as in the case of NTPC's three other power plants under construction, will also be obtainable in the case of the Second Singrauli Project. Costs for equipment and erection have been escalated at 6% for 1979, 10% for 1980, 7% for the years 1981-1983 and 5% for the years after 1983. These assumptions have resulted in price contingencies of 24% for civil works, 36% for supply and erection of electrical and mechanical equipment, 32% for supply and erection of coal handling and transportation equipment, and 31% for supply of materials and erection of the transmission system. Project Financing 3.07 The proposed credit of US$300 million representing about 35% of the cost of the project (excluding duties and taxes and interest during construc- tion), should be applied to the CIF and/or ex-factory costs of plant and equipment, excluding the 2 x 500 MW turbogenerators and associated equipment. The latter would be financed by Kredit fuer Wiederaufbau (KfW) from Germany which has been requested by GOI, and in principle has agreed, to extend a loan of about US$100 million equivalent to support the proposed project in financing the 500 MW turbo-generator units. Civil works, plant erection costs, inland transportation costs, interest during construction, duties and taxes and any other costs not financed from the credit and KfW, aggregating about US$694 million, would be financed by GOI in the form of loan and equity capital. Retroactive financing of up to US$15 million, to allow NTPC to exercise its option for a repeat order for the two 200 MW turbogenerators and boilers, is proposed. Engineering and Construction 3.08 As in the case of the first stage, the second stage of the Singrauli development comprises a number of major works which must be carefully coordi- nated to ensure efficient progress. The power plant is expected to be com- pleted by February 1987. The project construction schedule is shown in Annex 15. Much of the detailed power station engineering and design work carried out for the first stage is applicable to the second stage. Under previous credits and loan granted for NTPC's program, consultants were appointed for the 200 MW units to: (i) review NTPC's basic engineering and design; (ii) assist in the more sophisticated areas of design; and (iii) provide a back up review of specifications for generating units, boilers, transformers and other specifi- cations, as required by NTPC and the Association. NTPC has acquired adequate experience in the area of design and engineering of 200 MW units, especially  - 20 - from the first stage of the Singrauli power plant, and therefore there is no need to appoint consultants for the engineering of the 200 MW units. As for the 500 MW sets which are being installed for the first time in India, GOI and NTPC have agreed during negotiations as a condition of effectiveness of the proposed credit, to engage consultants acceptable to the Association to assist in the design, the preparation of specifications and bidding documents and the evaluation of bids for the 2 x 500 MW part of the project. 3.09 NTPC, under its competent chairman, has developed a comprehensive project management system, including program coordination and supervision of construction of the power stations. However, in view of the magnitude of its construction program, NTPC has agreed to conclude, as a condition of credit effectiveness, all contractual arrangements for the employment of consultants to review its project management and information systems and their initial implementation. 3.10 Under the first Singrauli Project, GOI agreed to take the necessary steps to make available adequate coal supplies for the 600 MW stage of the power plant by the time the first generating unit shall have been commissioned. These measures should be extended under the proposed project for the final installed capacity of the power plant. Agreements to this effect were reached during negotiations. Procurement 3.11 Procurement of all equipment to be financed from the proposed credit, with the exception of the 200 MW units including turbogenerators and boilers, would be on the basis of international competitive bidding in accordance with the Association's guidelines. For the procurement of the 200 MW turbo-generator sets and boilers, the Association has agreed, in view of the expected cost and time savings, that NTPC should exercise the option under the contract for the first Singrauli project, which was awarded after international competitive bidding. Documents for individual contracts above US$1,500,000 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 with the assistance of its consultants, and approved by the Association. To facilitate contract coordination, the invitation to tender for major plant contracts would be on a supply, deliver and erect basis. This could include civil works in certain cases where these cannot be disassociated from the plant contract--i.e., coal handling, substa- tion structures, transmission lines, but such civil works would not be financed from the proposed credit. 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 agreed during negotiations that it would grant import permissions for such items without further review by any agency of the Government. There are competent local contracting firms 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 KfW loan) will be subject to local procurement procedures, which are satisfactory.  - 21 - Disbursements 3.12 Disbursements from the proposed credit would be made against 100% of the cost of consultants retained for the 500 MW units (see para 3.08) and to review NTPC's project management systems (see para 3.09), and against the cost of the equipment to be financed from the proposed credit on the following basis: (a) 100% of the ex-factory cost of equipment procured in India after international competitive bidding; and (b) 100% of the foreign cost of equipment procured from abroad. Any balance of the credit not used after commitments have been made for all items covered by the list of goods, could be used to purchase other electrical and mechanical equipment for the project, after obtaining the Association's agreement. Retroactive financing of up to US$15 million is proposed for ex- penditures after August 1, 1979, made to allow NTPC to exercise its option for a repeat order for the two 200 MW turbogenerators and boilers (para 3.11). The estimated disbursement schedule is given in Annex 16. Ecological Aspects 3.13 The ecological and environmental aspects of the project were dis- cussed during appraisal. GOI confirmed that the Singrauli development had received the approval of the Indian National Committee on Environmental Plan- ning and NTPC agreed to comply with all environmental quality standards prescribed by this committee in the design, construction and operation of the project. 3.14 As in the case of the first stage of the Singrauli development, the principal environmental problems with the proposed project are: (a) location, (b) stack emissions, (c) heat dissipation, and (d) ash disposal. These are outlined below: (a) Location. The proposed Singrauli 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 4 or 5 km from the power station. (b) Stack Emissions. Electrostatic precipitators will be in- stalled and the stack will be of such a height that emitted particulate matter will be spread over a sufficiently wide area to reduce the density of pollutants to an acceptable level. The sulphur content of the coal is in the range of 0.3% to 0.6% which is low and does not present a pollution problem. (c) Heat Dissipation. The cooling pond is designed to ensure that its average temperature increase will not exceed 3% with the station under full operation. This would have no adverse effect on fisheries.  - 22 - (d) Ash Disposal. The ash will be pumped as a slurry, through a 5 km pipeline, to an ash dump area which has been reclaimed from the Rihand Reservoir. The area will be enclosed by a bund, and together with a reserve area, will be adequate to contain the ash output for the life of the power station. 3.15 With regard to the safety and occupational health of employees, safety regulations for power stations, to which all operating personnel must conform, will be strictly enforced. As far as noise levels are concerned the turbine hall of a modern steam turbine power station, which is the noisi- est 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. Project Risks 3.16 The project represents one phase of an overall development program which comprises 7,300 MW of generating plant and some 7,000 km of 400 kV transmission. It is part of a tightly designed program with plant and trans- mission coming in at phased intervals throughout the period 1982 through 1988. 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 care- ful coordination and supervision during construction and careful attention, when placing contracts, to the capability of manufacturers to meet the delivery schedules. 3.17 Other risk areas are in engineering design, cost overruns and prob- lems 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 by GOI through its self-insurance policy after commissioning. 3.18 These risks have been carefully assessed and the following safe- guards 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 cost 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; (c) a number of 200 MW generating units will have been in operation for some years before the project is commissioned, thus, providing experience and trained manpower for the project.  - 23 - IV. FINANCIAL ANALYSIS Introduction 4.01 Financial forecasts of NTPC's annual operations through FY91 are presented in Annexes 17 through 19. The forecasts are based on a capital investment program (Annex 18, page 2) which envisages the construction of four large thermal power stations with a combined capacity of 7,300 MW, together with almost 7,000 circuit kilometers of 400 KV transmission lines at a latest estimated cost of Rs 48 billion (US$5,714 million equivalent). The power stations and transmission lines will be commissioned on a phased basis during the period February 1982 to July 1989. 4.02 Concurrently with this construction program, NTPC is responsible for the operation and development of the Badarpur power station in Delhi. This involves directing operations of the 510 MW thermal generating plant (initial 300 MW plus 210 MW extension constructed and commissioned by NTPC), and for construction of a further 210 MW extension already sanctioned and due for commissioning in September 1981. Future Earnings 4.03 NTPC will become operational in February 1982 when its first 200 MW generating unit at Singrauli is expected to be commissioned. Additional gene- rating capacity scheduled for commercial operation during the succeeding seven year period, is set out in Annex 20, page 1, paragraph 2(a). NTPC's projected earnings are based on the assumption that NTPC would supply bulk power at 400 kV to State Electricity Boards at a tariff level which would enable it to earn a reasonable return on its investment. This was defined in connection with previous credits and loan as being a tariff level sufficient to produce a rate of return of not less than 9.5% on the book value of the average net fixed assets in service in FY1989 1/, and applied from the time of commis- sioning of the first generating unit in Singrauli in 1981/82 2/. 4.04 Several changes were necessary in, a number of assumptions underlying NTPC's financial projections, because of: slippage in the commissioning dates of operating plant, release of GOI funds as equity capital in the earlier years, followed by loan capital in later years and cost revisions in the overall investment program. The effects of these changes are to: 1/ The first fiscal year in which all generating units at Singrauli were projected to operate at 5,500 hours a year. 2/ There are no requirements within India either statutorily or for commer- cial accounting purposes, to note fixed asset and depreciation data at current price levels. The equivalent in real terms of a 9.5% rate of return on an historic rate base in FY1989 is about 7.5%.  - 24 - (a) increase the bulk selling price by 12% over the level estimated at the Ramagunda appraisal, bringing it to just over 29 paise/kWh; (b) eliminate losses during the initial years of operation; and (c) reduce by some 5% the overall cost of the investment program. 4.05 The income statement (Annex 17) shows the projected earnings per- formance for FY1982 through FY1991. Mainly because of a substantially reduced interest charge, resulting from the revised financing arrangement referred to at paragraph 4.04, NTPC will become profitable in its first year of commercial operation, FY1982. Earnings will rise rapidly thereafter, following the rapid commissioning of plant from FY1984 through FY1989, and will reach the stipu- lated rate of return of 9.5% in FY1989, rising to 11.4% by FY1991. Internal resources will generously cover debt service requirements in the initial years FY1982-FY1986 and adequately thereafter. 4.06 The regulation of NTPC's annual earnings is a function imposed on GOI by the amendment to Section 75A of the Electricity (Supply) Act, 1948. Under the amendment, GOI is required to specify the quantum of annual surplus which should be earned so as to provide from internal resources a reasonable contribution to capital investment, and to pay dividends on the equity capital. Under present assumptions, NTPC's internal resources would not be adequate to meet these commitments until FY1988. During negotiations, GOI confirmed that while NTPC's surplus would be regulated from the time NTPC became revenue earn- ing (FY1982) the appropriate amount of surplus would depend, in part, upon NTPC's future investment program at that time. It was thus premature to spe- cify a surplus at this stage. However, the 9.5% rate of return would be retained as a minimum requirement in FY1989 and thereafter. 4.07 As in earlier credits and loan, it has been restated for this pro- posed credit that NTPC would achieve in FY1989 and maintain thereafter a rate of return not less than 9.5% on net fixed assets in operation, and to set tariffs from the time the first generating unit at Singrauli is commis- sioned, at levels not lower than estimated to achieve the required 9.5% rate of return in FY1989. Taxation 4.08 NTPC is liable for income tax under the Indian Income Tax Acts. Because of the large capital expenditure program between FY1979 and FY1988 liability to tax will not arise in the foreseeable future and a tax equaliza- tion reserve is not necessary. Financing Plan FY1977-FY1987 4.09 The following table sets out the financing plan for the eleven-year period FY1977 through FY1987 (the year during which the project is scheduled for completion):  - 25 - Table 4.1 Total Total Rs Million US$ Million x Source of Funds Internal Cash Generation 6,426 765 14 Less: Debt Service (3,083) (367) (7) Deferred Charges (11) (1) - Working Capital Increase (579) (69) (1) Net Internal Cash Generation 2,753 328 6 Capital Raised: GOI Equity 21,959 2,614 48 GOI Loans 13,413 1,611 29 IDA Credits/IBRD Loan onlent /a 7,680 900 17 Total 43,052 5,125 94 Total Sources 45,805 5,453 100 To Finance: Investment Program 45,805 5,453 100 (incl. interest during construction) /a Includes the following: Singrauli (Credit 685-IN) 1,290 150 3 Korba (Credit 793-IN) 1,720 200 4 Ramagundam (Credit 874-IN) 1,720 200 4 Ramagundam (Loan 1648-IN) 430 50 1 Second Singrauli Proposed Credit 2,520 300 5 7,680 900 17 4.10 The financing plan provides for the construction of the ongoing First Singrauli, Korba, and Ramagundam Projects, the proposed Second Singrauli Project, and the tentative Farakka Project together with the balance of the generation and transmission construction program, during the project construc- tion period. GOI is expected to request additional financial assistance for the balance of the program. The cost of the proposed Second Singrauli Project represents almost 18% of construction expenditure in the financing plan. GOI would provide the capital required by NTPC in the form of debt and equity in a ratio not exceeding 1:1. 4.11 The proposed IDA credit of US$300 million would be relent to NTPC in accordance with an acceptable onlending agreement, as a condition of effectiveness of the credit. As in previous operations, the terms of the on-lending agreement would provide for final maturity in 20 years, including a grace period of 5 years, and repayment of principal in equal semiannual installments, with interest payable on outstanding loans at 10.25% per annum. This is the rate of interest at which GOI currently lends to industrial and commercial undertakings in the public sector, and compares with about 16%  - 26 - charged by domestic lending institutions for similar types of lending. The foreign exchange risk would be borne by the Government. GOI has invited KfW to assist in the financing Df th- Project It is likely that the latter will finance the 2 .. 500 MW turbogenerators and associated equipment to the extent of approximately US$100 million. Assurances were obtained during negotiations that GOI will provide the balance of the capital needed to complete the project on terms satisfactory to the Association. 4.12 IDA financing of the proposed Second Singrauli Project, US$300 million, together with Bank Group financing of the first stage development of each of the Singrauli, Korba and Ramagundam stations, US$600 million, in aggregate US$900 million, represents some 40% of the total costs involved, excluding duties, taxes, and interest charged to construction. Internal Cash Generation 4.13 The Source and Application of Funds Statement presented in Annex 18 shows the rapid buildup of internally generated funds from the time NTPC becomes revenue earning in February 1982. An unusually high debt service coverage of 9 times and 6 times in FYs1982 and 1983, respectively, is caused by the mainly equity financing in those years. Financing by means of loan capital in succ,eding years reduces the coverage ratio to a more balanced level reaching 1.7 times in FY1987, when the total Singrauli development would be commissioned. 4.14 The level of internal cash generated is determined by the assump- tions made in the financial projections (Annex 20). Surplus funds arise in FY1988 and accelerate rapidly thereafter. It is reasonable to assume that having reached a sat-isfactory level of financial viability, NTPC would be expected to commence paying dividends on its equity share capital. This is a decision which will have to be made by GOI in due course, and will be influenced by decisions on whether or not to expand the activities of NTPC beyond the current investment program. A decision could also be made to pay off GOI loans in advance of their maturity, thereby saving interest and improving NTPC's profitability. Future Finances 4.15 Forecast condensed balance sheets through FY1991 are presented in Annex 19. The balance sheets reflect the build-up of the construction pro- gram, the 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, so as not to exceed a debt/equity ratio of 1:1, with equity being released initially followed by loan capital later. Table 4.2 below shows NTPC's projected financial position at three significant points in its development: (a) at March 31, 1982 - end of year when NTPC becomes revenue earning; (b) at March 31, 1987 - end of year following commissioning of the proposed Second Singrauli Project; and  - 27 - (c) at March 31, 1991 - end of year in which the Singrauli Station (2,000 MW) would be operating 5,500 hours a year. Table 4.2 As at March 31 FY1982 FY1987 FY1991 --------Rs Million-------- Fixed Assets at Cost 2,453 29,530 48,275 Less: Depreciation 1 1,866 6,748 Net Fixed Assets in Service 2,452 27,664 41,527 Work-in-Progress 11,589 16,275 - Total Net Fixed Assets 14,041 43,939 41,527 Short Term Deposits - - 5,207 Working Capital 27 579 1,129 Deferred Expenses 11 - - Total Net Assets 14,079 44,518 47,863 Financed by: Equity Capital 13,812 21,959 21,959 Retained Earnings 7 1,866 9,862 Total Equity 13,819 23,825 31,821 Long Term Debt 260 20,693 16,042 Total Capitalization 14,079 44,518 47,863 Debt/Equity Ratio 2/98 46/54 34/66 4.16 The above table shows that by March 31, 1982, just after the point at which NTPC becomes revenue earning, total capitalization would be about Rs 14,000 million (US$1,667 million), with a debt/equity ratio of 2/98. Five years later - end of FY1987, after the Second Singrauli Project would be commissioned - total capitalization would have more than tripled to about Rs 45,000 million (US$5,357 million) with a debt/equity ratio of 46/54. Over 60% of the construction program will have been completed at this time. By March 31, 1991, when the balance of the construction program would be completed and Singrauli station operating at 5,500 hours per year, capitalization would be about Rs 48,000 million (US$5,714 million) with an improvement in the debt/ equity ratio to 34/66. The improvement in the debt/equity ratio between FY1987 and FY1991 reflects the assumed cessation of expansion and its associated financing, combined with significant increases in the level of retained earn- ings, caused by improved profit volume. NTPC's authorized share capital would be raised progressively during the period FY1981 through FY1987 (Annex 19) to reach a figure of about Rs 22,000 million (US$2,620 million). It is currently Rs 3,000 million (US$357 million).  - 28 - 4.17 The level of working capital in NTPC's balance sheet assumes that its customers (SEBs) would have credit terms of 30 days. Monthly billings for energy sold would be running at the rate of almost US$3 million in FY1983, US$47 million in FY1987 and US$116 million in FY1991. Accordingly, delay in payment of accounts by SEBs would adversely affect NTPC finances. This is not regarded by NTPC as a serious problem because, under existing circumstances in India, credit terms of less than 30 days for interstate transfers are com- mon. In addition, penalties for late payment of accounts would be imposed. Further reference to this subject will be made during dialogue with GOI and NTPC on the bulk tariff issue (para 4.19). Borrowing Powers 4.18 The Companies Act 1956 (Section 293.1(d)) restricts borrowing by NTPC to within a sum equal to the aggregate of the paid up share capital and the "free reserves" (i.e., those not set apart for a specific purpose) except with the consent of the corporation in general meeting. During negotiations NTPC agreed to inform the Association beforehand of any proposal to alter or modify existing limitations on the borrowing powers of its Board of Directors. NTPC's Bulk Tariff 4.19 This is a matter which was first discussed during the appraisal and negotiation of the First Singrauli Project (Credit 685-iN). Since the first 200 MW unit was not scheduled to come into commercial operation until early calendar year 1982, this matter has awaited the formulation by GOI and NTPC of the strategy for the sale of power from the central thermal power stations. The dialogue was resumed at negotiations of the Ramagundam Project (Credit 874-IN and Loan 1648-IN) and continued during appraisal of the Second Singrauli Project. Subjects discussed included the regionalization of the bulk tariff; the form of contract with SEBs and REBs, covering operating practices, finan- cial requirements, arrangements for settlement of disputes; and the structure of proposed tariff. These matters are discussed in more detail in the follow- ing paragraphs. Regional Tariffs 4.20 There appears to be a valid case for regionalizing NTPC's bulk tariff to better reflect the nature of the individual NTPC 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 compatible with NTPC's tariff covenant with the Association (para 4.07). If the total capital base at FY1989 was broken down over each of the four stations and operating costs and revenues for the various years similarly allocated, a bulk tariff for each station in each region would emerge. This exurJis was undertaken during appraisal and produced the following approximate bulk tariffs:  - 29 - Paise/kWh 1/ Singrauli (Northern Region) 23 Korba (Western Region) 31 Ramagundam (Southern Region) 34 Farakka (Eastern Region) 32 Average (All Regions) 29 A comparison of the Singrauli bulk tariff with bulk exchange tariffs in the Northern Region is contained in Annex 22. Commercial Arrangements for Sale of NTPC Power 4.21 NTPC has prepared a draft contract for the sale of its power to its customers in the Northern Region (mostly SEBs). The draft explains the manner in which power (including NTPC's) would be distributed to individual customers in the region through the Regional Load of Dispatch Centers, the commercial and financial arrangements for the sale of NTPC's power, and the arrangements for the settlement of disputes. During negotations, GOI confirmed that NTPC's draft contract was being examined in the context of a proposal to study the feasibility of a common agency selling power from all central projects in a region to SEBs at a common rate, so as to optimize operation of regional systems. The feasibility and the several technical, operational, commercial and institutional aspects of this proposal needed examination. Once a view had been taken on the concept of a pooled tariff for central generation in a region, NTPC's commercial arrangements for the sale of its power would be finalized. It was recognized that this would need to be some months before the start of commercial operation of the first NTPC unit which was scheduled for February 1982. Continuing dialogue would be maintained with the Associa- tion on this subject. Tariff Level and Marginal Cost 4.22 At the present time, while no output will be sold by NTPC for sev- eral years to come, it is irrelevant to talk of marginal cost-based tariffs at 1979 levels. NTPC is not an existing expanding system, but has to be treated as the beginning of such a supply system. By definition, practically all costs of the system known in 1979 are future, marginal costs of supplying incremental demand. In order to arrive at marginal costs in future years when power is actually sold, assumptions about the future expansion and operation of the system, and about inflation expectations have to be made (Annex 23, pages 1 through 5). 1/ While interest during construction has been calculated on a "total company" basis, some inequities may emerge in allocating of the interest to individual stations, due to the fact that loans as distinct from equity finance may have been allocated to specific plants, on a "first in-first out" basis, whereas it might be more equitable to allocate interest on an "average cost of capital basis". The figures above would require some adjustment if this were the assumption. Nevertheless they are useful for purposes of illustration.  - 30 - 4.23 Assuming that capacity expansion investment will continue for the foreseeable future in line with growing demand, and that, ultimately, NTPC will be operating at the limit of its capacity, the estimates of marginal-cost- based tariffs for 1984/85, the first year of operation of all four stations range from 35 to 37 paise/kWh (USJ4.1-4.4) as a one-part tariff, and Rs 935- 1,022/kW/year (US$111-122) plus 9.3-11.2 paise/kWh (WScl.1-1.3) as a two-part tariff 1/ (Annex 23, page 6). The discrepancy between these figures and the financially justified tariff levels (para 4.20) is, of course, attributable to the fact that present financial projections are based on investment tapering off in the later years, while the marginal cost concept assumes that additional investment will be necessary to accommodate any incremental demand. 4.24 Notwithstanding the limitations of the marginal cost approach, it will be necessary to consider it as an input into tariff construction in later years, when marginal cost will start exceeding the financial tariff that is planned to remain fixed in absolute terms throughout the projection period. Any intention to expand NTPC operations after the late 1980's or an integra- tion of NTPC capacity into a future national generating authority will have to take into account the need to provide for future investment and to post proper price signals to SEBs and consumers. By the mid-1980's, the time will have arrived to adjust the bulk tariff upwards in line with marginal cost. This will be particularly relevant for the Singrauli station (Northern Region), where the projected financial tariff level would be as low as 23 paise/kwh compared to a marginal-cost based tariff of 35 paise. V. JUSTIFICATION Project Definition 5.01 The proposed project 2/ is justified as the least-cost solution available to meet part of forecast demand in the Northern Region within a limited time frame. Comparison of Alternatives 5.02 Given the existing and forecast power shortages in the Northern region, the need for additional capacity in the shortest possible time is urgent (para 1.31). This short-term capacity of the required size can only be provided by thermal plant with a sufficiently short gestation period. Possible new hydro sites require extensive engineering studies, and those hydro projects that could yield available capacity within a reasonable time 1/ Total capital cost recovered in fixed charge. 2/ For purposes of justification, the project is defined as the expansion by 1,400 MW of the first 600 MW stage of the Singrauli thermal power station.  - 31 - are designed to meet another part of future demand as part of the concurrent SEB investment plan. The justification of the complete 2,000 MW development at the time of appraisal of the first stage, was based on the fact that any ready hydro potential was already included to be developed in parallel with Singrauli. The nuclear alternative was excluded because of the long gestation period. 5.03 In continuation of the approach used in the analysis of realistic alternatives at the time of first stage appraisal, the only solution that could yield available energy at the same time as the incremental 1,400 MW of Singrauli would be a combination of new smaller coal-fired plant and expan- sion of existing stations, undertaken by the regional SEBs individually. The theoretically most attractive solution to provide equivalent thermal capacity quickly is the expansion of existing sites. Two obstacles to this are evident in the Northern Region: (a) the expansion potential of existing stations is limited, or allocated to be developed concurrently with Singrauli; (b) the Singrauli expansion cost of about Rs 3.3 million/MW (in 1979 market prices) (US$0.39 million) is lower than the average cost of installing scattered new capacity in the region, amounting to about Rs 3.7 million/MW (US$0.44 million). 5.04 The alternative consisting of smaller stations would encompass three new sites (a pithead site in Uttar Pradesh near the Singrauli site, and two sites in Punjab and Haryana), and two expansions of existing stations (Kota in Rajasthan, and Badarpur for Delhi), with an aggregate capacity equal to that of the proposed project. With the exception of the Uttar Pradesh site, all locations would require transport of coal. The largest station (630 MW) would supply Uttar Pradesh; the remaining stations range from 110 MW to 220 MW (Annex 24). 5.05 As the transmission cost included in the proposed project cost is designed to serve not only for the evacuation of Singrauli power, but also for other energy flows in the region, an allowance for some additional trans- mission investment has been made in the cost of the alternative solution. This includes not only the transmission necessary for the evacuation of power from the Uttar Pradesh pithead station, but also the "regional" element (Annex 25). 5.06 The costs of both the project and its alternative have been phased to provide capacity and energy in the same pattern (Annex 29). All costs are expressed in economic terms, i.e. in CIF/FOB prices where available and ad- justed by the appropriate conversion factors to border prices where necessary. Unskilled labor has been shadow priced at 75% of the market wage, skilled labor at full market wage. The economic cost of coal has been derived from production cost expressed in border prices (Annexes 26 and 27). 5.07 The present value of the cost stream of the project is lower than that of the alternative at any discount rate. The project, therefore, consti- tutes the least cost solution for satisfying the future 1,400 MW portion of demand in the Northern Region gradually from 1985 onwards. Annex 30 shows the present values of the cost streams of the project and of the alternative assuming opportunity cost of capital of 10% as the discount rate, with as a  - 32 - sensitivity test a discount rate of 13%. The results show the advantage of the project over its alternative (Rs 1,075 million (US$128 million) at 10% discount rate, and Rs 792 million (US$94 million) at 13% discount rate). The cost differentials in the base case increases slightly if the cc;t of capital goods is increased, and decreases slightly if this cost decreases. The cost advantage of the project rises with higher fuel cost. Benefits 5.08 Quantification of economic benefits arising from the implementation of an expansion of generating plant integrated into an existing and growing system is not easily established. A two-stage approximation approach has been adopted for the proposed project: (a) average retail tariffs in the region have been assumed to represent a proxy for the minimum observed will- ingness of consumers to pay for power; and (b) in order to quantify any addi- tional consumer surplus beyond this minimum, the cost incurred by industry in maintaining and operating standby generating sets has been assumed to represent a proxy for industrial consumers' willingness to pay for continuous power supply (Annex 28). 5.09 Corresponding to the definition of benefits as willingness to pay at the retail level, additional costs of transmission and distribution invest- ment as well as for operation and maintenance have been allocated to project cost in line with the general regional incremental investment pattern. This additional cost is net of the transmission element already included in the project cost. The incremental amount of energy sold has been adjusted to account for system losses typical for the region (Annex 25). 5.10 The weighted average of tariff revenue at retail level in the Northern Region has been established at 26.4 paise/kWh in 1979 prices, and converted to border prices for purposes of the comparison with economic cost. The industrial tariff revenue is replaced by the observed average willingness to pay for continuous power supply. 1/ The minimum economic internal rate of return is about 13%, rising to 16% if outages are more frequent and standby sets utilized more (Annex 30). 5.12 The internal economic rate of return is likely to be considerably higher than the minimum quantifiable estimate of 13%, if the derived consumers' and producers' surplus of industrial, agricultural and commercial output made possible by the alleviation of shortages is taken into account and if indirect benefits accruing to the Indian economy would be fully considered. Benefits accruing to domestic consumers are understated by the use of the tariff as benefit. The conclusion that can be drawn from the exercise using retail tariffs only, is that regional tariffs charged final consumers are slightly inadequate to recover the incremental cost of the project. 1/ The average cost of grid supply together with the operation of diesel standby generating sets during power outages has been established as about 37 paisa/kWh as opposed to the weighted average regional industrial tariff of 25 paisa/kWh (22 paisa in economic terms), given typical utilization rates of standby sets (Annex 28).  - 33 - VI. AGREEMENTS REACHED AND RECOMMENDATION 6.01 During negotiations, the following issues were raised with GOI and satisfactory agreement or assurances were obtained with regard to: (a) preparation of a study for a long-term development plan (para 1.33); (b) continuation of the 400 kV study (para 1.33); (c) revival of the UNDP project to assist CEA in establishing a systems operation organization and developing and imple- menting programs for training staff (para 1.34); (d) status of action programs of Northern Region SEBs and DESU to achieve rates of return of at least 9-1/2% on historic assets (para 1.41); (e) provision of adequate coal supplies (para 3.10); (f) import permission without Government review (para 3.11); (g) provision of the balance of capital to complete the project, together with any additional funds which might be needed due to cost overruns or other unforeseeable factors (para 4.11); and (h) bulk tariffs (para 4.21). 6.02 During negotiations the following issues were raised with GOI and NTPC and satisfactory agreement or assurances were obtained with regard to: (a) audit (para 2.18); (b) appointment of consultants for the 500 MW units (para 3.08); (c) appointment of consultants to review NPTC's project manage- ment systems (para 3.09); (d) tariffs (para 4.07); (e) the conclusion of an onlending arrangement between GOI and NTPC (para 4.11); and (f) borrowing (para 4.18). 6.03 Subject to the foregoing assurances, the project forms a suitable basis for a credit of US$300 million.  INDIA SECOND SINGRAULI THERMAL POWER PROJECT All-India-Sales and Energy Data for 1969/7 1, 1974/75, 1975/76, 1976177, 1977i70 and 1978/79 1969/70 1974/75 1975/76 1976/77 1977/78 1978/79 (Estimated Installed Capacity (excl.non-utility plant (MW) 14,102 18,317 20,117 21,814 23,770 26,743 Electricity Generated (MW) 57,988 70,191 79,231 88,333 91,206 97,376 Electricity sold GW4 41,061 52,682 60,246 66,608 68,693 78,32 Electricity Generation per capita kWh 96.2 119.2 132.5 147.2 146.7 156.4 Electricity Consumption per capita kWh 76.0 89.9 100.3 111.0 110.9 118.7 Proportion of Sales (%) Agricultural and Irrigation 9.2 14.5 14.5 14.4 14.5 15.1 Railway Traction 3.5 2.9 3.1 3.3 3.5 3.2 Industry 69.1 62.1 62.4 62.5 61.6 61.8 Commerce and Government 6.5 8.5 7.3 7.3 7.3 7.0 Dkues tic 8.ti 8.5 9.7 9.5 10.0 10.2 Other (Public Lighting, Waterworks etc.) 3.1 3.5 3.2 3.0 3.0 2.7 Average Annual Growth of Sales (%) 9.9 5.3 14.5 10.5 3.2 14.0 Losses as percentage of kWh sent out 16.8 20.5 19.4 19.7 19.6 19.9  .--35- ANNEX 2 Page 1 of 10 pages INDIA SECOND SINGRAULI THERMAL POWER PROJECT Regional Demand and Supply (Northern Region) 1. Of all energy flows in the region, about 45% (including Bhakra/Beas share distribution) are accounted for by inter-authority transfers. Similarly, about one-third of total capacity demand at peak is made available as inter- authority exchange (Annex 10). 2. Estimated total energy consumption in the region 1978/79 was 20,062 GWh (at final consumer level); estimated maximum regional coincident peak demand during the same fiscal year was 4,796 MW. This represents a large increase of 20% (3,347 GWh) in terms of energy, and an increase by 8% (356 MW) in terms of capacity over the previous year. The large jump in energy sales can be explained by an exceptionally high availability level of hydro capacity following a good monsoon, while 1977/78 had actually experienced a decrease in energy sales. The importance of the hydro element in the fluc- tuations can be observed in the fact that States heavily dependent on hydro generation (Punjab, Haryana, Jammu and Kashmir) have recorded energy sale increases of up to 25%, while Uttar Pradesh with its predominantly thermal capacity shows an increase of about 10%. 3. In March 1979, 49% of installed regional capacity consisted of thermal plant, 3% of nuclear and 48% of hydro. The high dependence on hydro capacity makes the region vulnerable to fluctuations in water levels, but also provides it with desirable peaking capacity for future, shortage-free years. The degree of reliance on hydro varies within the region (Project File Working Papers): Share of hydro in the installed capacity (%) a/ Central Sector Delhi - Himachal Pradesh 98 Haryana 67 Jammu & Kashmir 83 Punjab 70 Rajasthan 60 Uttar Pradesh 35 a/ Including shares of common hydro complex.  -36 - ANNEX 2 Page 2 of 10 pages 4. Diversity within the Region is not very pronounced, the diversity factor ranging from unity to 1.048 (Project File Working Papers)). By far, the largest supplying authority is UPSEB, accounting for 40% of total installed capacity, followed by Punjab with about 20% (including its hydro share). In terms of firm available capacity at the peak, Uttar Pradesh also provides 40%, while Punjab's share is about 18%. UPSEB's share of potential unconstrained peak demand would be even slightly higher at 41% of the esti- mated regional total. In 1978/79, the net imports of energy from outside the region were negligible, mainly confined to minor local exchanges with Madhya Pradesh and Bihar. In effect, therefore, the region operates as a self-contained system. 5. The pattern of electricity consumption in the region shows a pre- dominance of industry, but to a much lesser extent than the All-India average: industry accounts for 52% of consumption, against a national average of about 62%. Agriculture, on the other hand, occupies a large share of consumption in the region (26% as against a national average of about 15%, (Annex 3)). The region, therefore, is subject to the disadvantages of high agricultural demand, such as pronounced peaks in the daily load curve, low load factor, and high system losses in distribution. Punjab, Rajasthan, and Uttar Pradesh are States with a relatively high degree of industrial consumption, while the other States show a more even split between industry and agriculture. Over the period 1974-79, the pattern of consumption has remained approximately constant, and no major changes in the composition of consumption are expected. 6. During recent years, installed capacity in the region has been increasing at a rate of about 13% per year to reach 7,769 MW in March 1979. Firm available capacity, however, has been increasing only at a rate of about 9% per year, falling to 62% of installed capacity from 73% in 1973/74. DESU is the only supply authority in the region whose plant availability factor has not deteriorated severely since 1976: rapidly rising installed capacity is not reflected in similarly increasing ability to meet peak demand. An increase in availability approaching 70% is expected for future years after present difficulties with forced outages are overcome. 7. In terms of energy, consumption has been growing at approximately 14.5% per year for the five years up to 1978/79, with growth rates of up to 25% for years with good hydro availability. Growth of sales over time has been uniform throughout the region. Energy available to be sent out, however, has been growing only at a rate of about 13% during the same period: some progress in reducing the high system losses is evident. Future Development 8. By 1983/84, an additional 4,820 MW (plus 62%) are expected to have been added to regional capacity installed in March 1979. 3,059 MW (63%) of this increase will be accounted for by UPSEB and the Central Sector (mainly NTPC) together. Presently available plans indicate a further increase of about 3,000 MW between 1984 and 1988, and new capacity amounting to 665 MW already sanctioned to come on stream after 1988. About 25% of total new  - 37 - ANNEX 2 Page 3 of 10 pages capacity to be commissioned between 1980 and 1988 is attributable to the Singrauli development. About 70% of new capacity to be available by 1983/84 will be thermal and nuclear thus shifting the regional balance somewhat away from excessive dependence on hydro capacity. This trend is expected to con- tinue until 1988: new capacity in the region will be 75% thermal. Annex 2, pages 7-10 indicates the planned investment program at its latest status in June 1979. 9. The basis for this capacity extension plan is the demand forecast- ing conducted in the form of the periodical comprehensive power surveys ("Annual Power Surveys") by the CEA, and amended by deliberations of the Planning Commission, SEBs, and National Development Council. At the time of publication of the tenth APS in 1977, it was envisaged that about 5,530 MW of an unconstrained potential peak load demand of almost 6,000 MW in 1978/79 would be met. Actual estimated peak availability in that year, however, was only about 4,800 MW. All demand forecasts have now been scaled down by the Planning Commission's Working Group: unconstrained potential peak load demand in 1983/84 is now estimated to be about 9,130 MW (a reduction by 10% from the tenth APS estimate), 8,320 MW of which are expected to be met by available plant. The anticipated capacity shortfall will be growing steadily over the five years to reach more than 800 MW in 1983/84. 10. A possible variation in the forecast capacity and energy require- ment is introduced by consideration of future new industrial consumers and future agricultural demand. Differences of opinion on the extent of demand attributable to new high-voltage industries exist between the Planning Commis- sion, the APS, and the SEBs. Macro-economic considerations of the Planning Commission have led to a reduction of the bulk provision for industries likely to be licensed in the future. On the other hand, the SEBs' micro-economic forecasts are consistently higher than either the APS or the Planning Commis- sion estimates. Annex 2 page 10 illustrates the range of recent forecasts for two States in the Northern region (Uttar Pradesh and Rajasthan): the estimate for potential unconstrained peak demand in 1983/84 ranges from 3,997 MW to 4,957 MW for Uttar Pradesh, and from 1,186 MW to 1,600 MW for Rajasthan. In the years beyond 1984, the range increases. Correspondingly, the forecasts of annual energy demand are spread over a wide range. The significance of the disparity becomes clear in its effect on future shortages: the Working Group's estimate for Rajasthan,, for example, forecasts a slight capacity surplus from 1980/81 onwards; RSEB's estimates would result in continuing capacity short- falls. This is reflected in the tentative RSEB projections of new available capacity, which exceed the CEA's by about 260 MW until 1983/84. 11. Neither forecast can be based on recent data, all of which are constrained by shortages. For planning purposes, the latest estimates of the Planning Commission's Working Group, which are also the lowest so far, are being used (Annex 4). Further tentative projections of demand by the CEA, which are not universally accepted as of now, indicate a growth of potential peak load demand in the Region by about 11% per year, to reach about 15,350 MW by 1988/89. Similarly, the potential energy requirement is expected to grow at a similar rate to about 80,000 GWh (Annex 5). Firmer forecasts will be available after the ongoing eleventh APS is finalized early in 1980.  - 38 - ANNEX 2 Page 4 of 10 pages 12. Resource constraints and slippage in implementation of projects are expected to reduce the target of additional capacity installation: preliminary estimates envisage a figure of total capacity installed by 1982/83 which is about 7% lower than anticipated by the Working Group. It is likely, therefore, that persistent shortages at peak times are going to be more pronounced, and will continue well beyond 1984, even under the lowest assumption of demand growth. 13. The investment expenditure in the region necessary to reach the physical targets for 1982/83 is estimated to be about Rs 43,935 million (US$230 million) for the fiscal years 1979/80 to 1982/83. The bulk (60%) of this expenditure will be allocated to Uttar Pradesh (including the NTPC Singrauli development), the State with the largest anticipated peak load shortfall. About 60% will be attributable to generation, the remainder to transmission, distribution and rural electrification. Except for UPSEB, most States in the region will devote smaller percentages of their investment to generation, reflecting the shifting of some of the responsibility for generation development from the States to NTPC (Annex 7). Shortages and Restrictions 14. During 1978/79, only Punjab and some of the smaller supply areas were relatively free of shortages. All other supply authorities had to impose restrictions on unconstrained demand to avoid large-scale breakdowns at peak. In addition, the regional dependence on hydro generation leads to the need to impose a maximum on the monthly energy consumption. UPSEB is continuing to impose the following major restrictions on its consumers: (i) non-continuous industries do not get supply at the four hours of evening peak; (ii) many continuous industries suffer a 50% cut in capacity availability and energy consumption; if they have at least 50% captive capacity, the cut is 100%; (iii) rural feeder lines are interrupted for 3 hours, 3 days per week; and (iv) commercial establishments business hours are limited to 9 a.m. to 8 p.m. It is notable that domestic and rural consumers are guaranteed almost con- tinuous supply, while industry is bearing the brunt of the shortages. 15. The other supply authorities resort to less drastic restrictions of their industrial consumers' demand. The usual restrictions are the non- supply to industry during the evening peak (about 6 to 10 p.m.), and an overall cut in monthly energy allocation by 5-10%. Rotation of supply to individual rural feeders during the day is also widespread. In addition to these planned restrictions, ad hoc load shedding becomes necessary in the case of local plant or distribution breakdowns.  - 39 - ANNEX 2 Page 5 of 10 pages The Project in the Regional Context 16. As Singrauli capacity gradually comes on stream between 1981/82 and 1986/87, shares of this capacity will be allocated to individual supply authorities. Fifteen percent of total capacity will remain unallocated to satisfactory demand where needed on an ad hoc basis. UPSEB will be receiving 50% of allocated capacity. Annex 6 illustrates the planned build-up of allo- cations of capacity and energy in the region. At the time of fully available Singrauli capacity, the complete project (including the first 600 MW stage) will represent about 15% of regional potential unrestricted demand. In 1983/84, the latest year for which accepted regional capacity forecasts are available, Singrauli capacity will be the equivalent of 8% of total regional capacity. If a high firm availability of the project is assumed, its share of capacity actually available at peak rises to about 10-12%. 17. In terms of energy supplied to the Northern region grid from the project, the Singrauli share of forecast unconstrained energy requirement will be about 13% in 1988/89. In 1983/84, its share in the consumption actually met is anticipated to be 5-6%.  INDIA SECOND SINGRAULI THERMAL POWER PROJECT Northern Region 1/ Energy Exchanges Among Various Systems- 1978-79 (million Kwh) From To Bhakra Dehar Pong Badarpur Hydro Hydro Hydro Thermal RSEB DESU UPSEB PSEB HSEB HPSEB JKSEB Total Delhi - - - 562.7 36.4 1,462.0 17.6 53.1 175.3 - - 2,307.1 Punjab 2,420.9 922.0 259.9 - 10.4 - - 967.0 30.5 70.9 9.8 4,691.4 Rajasthan 987.1 384.2 610.4 59.0 346.7 - - 63.5 - - - 2,450.9 U.P. - - - 48.0 29.4 - 11,058.6 86.3 - 33.5 - 11,255.8 . Haryana 1,754.5 614.7 173.2 16.40 - 286.2 - 38.2 140.4 - - 3,023.6 Chandigarh 191.2 - - - - 14.5 3.5 - 0.3 209.5 J&K 125.9 - - - - - - 23.5 3.1 - 467.7 620.2 Himachal 154.9 6.7 - - 54.1 - 215.7 Pradesh Nagal 935.0 -- - - - - - - - 935.0 Fertilizer Beas/Sutlej 39.8 - - - - - - - - 39.8 Link Salal - 13.1 - - - - - - - 13.1 Siul - - - 16.1 - - - - - - - 16.1 Transfer 161.7 80.7 40.5 - - - - - - - - 282.9 Losses TOTAL 6,771.0 2,008.3 1,084.0 715.3 422.9 1,748.2 11,076.2 1,246.1 352.8 158.5 477.8 26,061.1 X . .~~~~~~~~~~~~~~~~N 0 1/ Including supply from own capacity in own State. o Source: CEA x  INDIA SECOND SINGRAULI THERMAL POWER PROJECT Northern Region Schedule of Yearly Additions to Thermal Generating Capacity CAPACITY 1979-80 - 1987-88 (All figures in MW) State Projects Installed Additions to Installed Capacity 1984/85- Capacity 1979-80 1980-81 1981-82 1982-83 1983-84 Total 1987/88 Haryana Panipat, Stages I, 5x110 110 - - 220 - 330 220 II, III Faridabad, Unit 3 lx60 60 - - - - 60 Sub-Total 170 - - 220 - 390 Rajasthan RAPP, Unit 2(nuclear) 1x220 220 - - - - 220 Kota 2x110 - 110 110 - - 220 Sub-Total 220 110 110 - - 440 Uttar Obra Extn. 3x200 200 400 - - - 600 Pradesh Paricha 2xllO - - - 220 - 220 Anpara 3x210 - - - 210 420 630 Narora (nuclear) 2x235 - - - - 235 235 235 4x110 - - - - - - 440 Sub-Total 200 400 - 430 655 1685 Central Badarpur Extn. lx210 - - 210 - - 210 Unit 5 Singrauli 5x200 _ _ 200 400 - 600 1,400 Sub-Total +2x500 _ 410 400 - 810 GRAND TOTAL 590 510 520 1050 655 3325 2,295 | -.4 0 Source: HECO, CEA 0)  Northern Region Schedule of Yearly Additions to Hydro Generating Capacity 1979-80 1987-88 (All figures in MW) State Project Type* Installed Additions to Installed Capacity 1984/85- Capacity 1979-80 1980-81 1981-82 1982-83 1983-84 Total 1987/88 Himachal Bassi Extn. R lx15 15 - - - - 15 Pradesh Andhra R 3x5 - - - 5 10 15 Binwa R 2x3 - - - 6 - 6 Rongtong R 4x0.5 - - - 2 - 2 Bhabar 3x40 - - - - - 120 Sub-Total 15 - - 13 10 38 1 Jammu & Lower Jhelum, R lx35 35 - - - - 35 Kashmir Unit 3 Punjab Shannan Extension R lx5O - 50 - - - 50 Anandpur Sahib ROR 4x33.5 - 33.5 100.5 - - 134 Mukerian ROR 6x15+6x - - - 15 69 84 123 Sub-Total 19.5 35 83.5 100.5 15 69 303 Rajasthan Mahi I R lx25+1x45 - - 25 45 - 70 Mahi II R lx25+1x45 - - - 25 45 70 Sub-Total - - 25 70 45 140 Uttar 1/ Yamuna II(Khodri) R 4x30 - - 90 30 - 120 Pradesh - Maneri Bhali I R 3x30 - - 90 - - 90 Garhwal Rishi- RO1, 4x36 36 108 - - - 144 kesh (Chilla) C m Vishnu Prayag 3x65.5 - - - - - 196.5 Sub-Total 36 0 30  Northern Region Schedule of Yearly Additions to Hydro Generating Capacity 1979-80 1987-88 (All figures in MW) State Projects Type* Installed Additions to Installed Capacity 1984/85- Capacity 1979-80 1980-81 1981-82 1982-83 1983-84 Total 1987/88 Central Baira Siul R 3x60 60 - 120 - - 180 Sector Salal 3x115 - - - - - - 345 Common Dehar Extn. R 2x165 - - - 165 165 330 Projects Pong Extn. RIC 2x60 - - - 120 - 120 Sub-Total - - - 285 165 450 GRAND TOTAL 146 191.5 425.5 413 289 1465 784.5 * RIC Reservoir stations with Irrigation Control R Reservoir stations without Irrigation Control ROR Run of the River Stations 1/ After 1988: Tehri Hydro: 600 MW, Vishnu Prayag Hydro: 65.5 MW 0 Source: HECO, CEA CD CQ  -44 ANNEX 2 Page 10 of 10 pages INDIA SECOND SINGRAULI THERMAL POWER PROJECT Comparative. Demand Forecasts for Uttar Pradesh and Rajasthan . Uttar Pradesh Rajasthan 10th APS (77) PCWG (79) UPSEB (79) 10th APS (77) PCWG (79) RSEB (79) Peak Load (MW) 1979/80 2,859 2,421 3,234 864 747 961 1980/81 3,190 2,738 3,577 973 841 1,079 1981/82 3,639 3,090 4,003 1,115 943 1,223 1982/83 4,042 3,568 4,498 1,253 1,061 1,425 1983/84 4,457 3,997 4,957 1,409 1,186 1,600 1988/89 7,474 6,940 8,500 2,416 2,038 n.a. 1995/96 14,745 n.a. 17,746 4,770 n.a. n.a. 2000/01 n.a. n.a. 29,400 n.a. n.a. n.a. Energy Require- ment (GWl;) 1979/80 14,935 12,682 17,127 4,6300 4,000 4,760 1980/81 16,605 14,293 18,854 5,221 4,488 5,392 1981/82 18,950 16,080 21,112 5,955 5,031 6,214 1982/83 20,963 18,059 23,459 6,695 5,624 7,370 1983/84 23,082 20,310 25,781 7,503 6,300 8,414 1988/89 38,890 36,113 43,427 12,930 10,906 n.a. 1995/96 77,500 n.a. 89,084 25,700 n.a. n.a. 2000/01 n.a. n.a. 146,715 n.a. n.a. n.a. S>ource: APS, GOI estimates, UPSEB, RSEB n.a. pnot available *Note: APS - Annual Power Survey PCWG - Planning Commission Working Group  INDIA SECOND SINGRAULI THERMAL POWER PROJECT Northern Region Sales & Energy Data for 1974-75 - 1978-79 Delhi 1974-75 1975-76 1976-77 1977-78 1978-79 (Provi- (est.) sional) Electricity Sold (GWh) 1,420 1,447 1,608 1,707 1,925 Proportion of Sales (%): Agriculture & Irrigation 0.4 0.4 0.3 0.3 0.5 Railway Traction 0.0 0.0 0.0 0.0 0.0 Industry 33.6 34.0 35.1 36.6 37.4 Commercial & Government 21.7 23.0 22.9 21.8 21.8 Public Lighting 5.4 2.6 2.8 2.9 2.9 Domestic 31.0 32.4 32.0 31.7 30.6 Public Waterworks, Drainage etc. 7.9 7.6 6.9 6.7 6.8 Average Annual Growth of Sales (%) 6.1 1.9 11.1 6.2 12.8 Losses as % of the units sent out 9.8 16.3 15.6 NA NA mlb Source: Commercial Directorate, CEA. w OQ 0)  Northern Region Sales & Energy Data 1974-75 - 1978-79 Haryana 1974-75 1975-76 1976-77 1977-78 1978-79 (Provi- (est.) sional) Electricity Sold (GWh) 1,239 1,602 1,866 1,892 2,333 Proportion of Sales: Agriculture & Irrigation 42.6 37.1 38.6 35.4 38.6 Railway Traction 0.0 0.0 0.0 0.0 0.0 Industry 42.0 48.5 47.0 49.0 47.1 Commercial & Government 6.2 5.5 5.5 5.8 4.9 Public Lighting 0.4 0.4 0.4 0.4 0.3 Domestic 7.4 7.4 7.4 8.3 7.9 Public Waterworks, Drainage etc. 1.4 1.1 1.1 1.1 1.2 Average Annual Growth of Sales (%) -11.6 29.3 16.5 1.4 23.3 Losses as % of the units sent out 24.4 23.2 21.5 NA NA Source: Commercial Directorate, CEA. (D M r'o 0 F-h Ln oq ;b 0q  Northern Region Sales & Energy Data 1974-75 - 1978-79 Punjab 1974-75 1975-76 1976-77 1977-78 1978-79 (Provi- (est.) sional) Electricity Sold (GWh) 2,219 3,380 3,585 3,434 4,180 Proportion of Sales (%): Agriculture & Irrigation 31.4 26.5 27.1 31.9 31.1 Railway Traction 0.0 0.0 0.0 0.0 0.0 Industry 53.8 60.6 59.4 51.9 53.8 Commercial & Government 5.5 5.0 5.2 6.1 5.3 4s- Public Lighting 0.3 0.3 0.3 0.3 0.3 Domestic 8.9 7.4 7.8 9.6 9.1 Public Waterworks, Drainage etc. 0.1 0.2 0.2 0.2 0.4 Average Annual Growth of Sales (%) -20.0 52.3 6.1 - 4.2 21.7 Losses as % of the units sent out 19.1 15.1 17.5 NA NA Source: Commercial Directorate, CEA. o sn a, OQ fb 02  Northern Region Sales & Energy Data 1974-75 - 1978-79 Rajasthan 1974-75 1975-76 1976-77 1977-78 1978-79 (Provi- (est.) sional) Electricity Sold (GWh) 1,560 1,821 2,107 2,255 2,700 Proportion of Sales (%): Agriculture & Irrigation 22.2 19.4 20.4 19.3 22.2 Railway Traction 0.0 0.0 0.0 0.0 Industry 56.4 60.0 58.8 59.4 63.0 Commercial & Government 8.2 8.2 8.8 8.3 4.8 Public Lighting 0.8 0.8 0.7 0.8 0 Domestic 6.9 6.6 6.4 7.1 6.7 Public Waterworks, Drainage etc. 5.5 5.0 4.9 5.1 2.6 Average Annual Growth of Sales (%) 17.5 16.7 15.7 7.0 19.7 Losses as % of the units sent out 30.6 25.8 24.5 NA NA Source: Commercial Directorate, CEA. oq z: O L o L) rD  Northern Region Sales & Energy Data 1974-75 - 1978-79 Uttar Pradesh 1974-75 1975-76 1976-77 1977-78 1978-79 (Provi- (est.) sional) Electricity Sold (GWh) 4,682 5,925 7,072 6,760 8,147 Proportion of Sales (%): Agriculture & Irrigation 26.3 28.7 26.2 30.4 28.2 Railway Traction 3.9 3.7 3.7 4.5 4.3 Industry 54.2 47.1 56.5 51.0 54.0 Commercial & Government 4.0 8.2 2.2 2.1 1.1 Public Lighting 0.6 0.6 0.5 0.5 0.4 Domestic 9.3 9.8 9.5 10.1. 9.8 Public Waterworks, Drainage etc. 1.7 1.9 1.4 1.4 2.2 Average Annual Growth of Sales (%) 12.8 26.5 19.4 - 4.4 20.5 Losses as % of the units sent out 26.4 22.0 24.0 NA NA Source: Commercial Directorate, CEA. LJi 09 I-tA n GQ w  -50- ANNEX 4 INDIA SECOND SINGRAULI THERMAL POWER PROJECT Northern Region Power Supply Position 1976-77 - 1983-84 1976-77 1977-78 1978-79 1979-80 Installed capacity (MW) 5,629 6,654 7,769 8,505 Peak availability (MW) 4,288 4,440 4,796 5,479 Peak Load (MW) 4,288 4,440 4,796 5,868 Surplus/Deficit (MW) - - - (-)389 Energy availability (.UWh) 23,317 22,539 26,190 30,681 Energy requirement (CWh) 23,317 22,539 26,190 30,065 Surplus/Deficit (GWh) - - - 616 1980-81 1981-82 1982-83 1983-84 Installed capacity (MW) 9,207 10,168 11,645 12,589 Peak availability (MW) 6,085 6,850 7,593 8,318 Peak Load (MW) 6,538 7,294 8,205 9,130 Surplus/Deficit (MW) (-)453 (-)444 (-)612 (-)812 Energy availability (OWh) 35,009 39,195 44,213 48,453 Energy requirement (GWh) 33,578 37,451 41,700 46,500 Surplus/Deficit (GWh) 1,431 1,744 2,513 1,953 Source: GOI * demand constrained by supply.  - 51 - ANNEX 5 INDIA SECOND SINGRAULI THERMAL POWER PROJECT Northern Region Tentative Demand Forecasts 1984-85 to 1988-89 1984-85 1985-86 1986-87 1987-88 1988-89 Peak Load (MW) Haryana 1,352 1,509 1,682 1,878 2,090 Himachal Pradesh 171 195 222 253 288 Janmu & Kashmir 329 376 430 490 557 Punjab 1,591 1,724 1,864 2,017 2,176 Rajasthan 1,322 1,475 1,646 1,832 2,038 Uttar Pradesh 4,409 4,943 5,537 6,207 6,940 Chandigarh 77 84 92 101 110 Delhi 805 863 966 1,055 1,150 TOTAL 10,056 11,189 12,439 13,833 15,349 Energy (GWh) Haryana 6,479 7,244 8,091 9,030 10,068 Himachal Pradesh 878 1,000 1,137 1,291 1,464 Jammu & Kashmir 1,618 1,853 2,117 2,415 2,752 Punjab 8,642 9,351 10,108 10,917 11,779 Rajasthan 7,043 7,867 8,780 9,790 10,906 Uttar Pradesh 22,828 25,636 28,764 32,244 36,113 Chandigarh 375 412 452 494 540 Delhi 3,951 4,330 4,737 5,175 5,641 TOTAL 51,814 57,693 -64,186 71,356 79,263 Source: Provisional GOI estimates  INDIA SECOND SINGRAULI THERMAL POWER PROJECT Yearwise Capacity and Energy Allocation from the Singrauli Development 1981-82 1982-83 1983-84 1984-85 1985-86 1986-87 1987-88 1988-89 1989-90 1990-91 I. Capacity (MW) Delhi 8 24 58 58 104 150 - - Punjab 12 36 84 84 142 200 - - - - Haryana 12 36 84 84 142 200 - - - - Rajasthan 18 54 124 124 212 300 - - - - U.P. 50 150 350 350 600 850 - - - - Unallocated 100 300 300 300 300 300 - - - - NORTHERN 200 600 1,000 1,000 1,500 2,000 - - - - REGION II. Energy (GWh) Delhi 3 39 119 224 385 587 714 791 821 825 Punjab 5 58 176 327 541 800 960 1,056 1,095 1,100 Haryana 5 58 176 327 541 800 960 1,056 1,095 1,100 Rajasthan 7 87 262 484 803 1,196 1,437 1,534 1,643 1,%50 U.P. 21 242 734 1,363 2,270 3,383 4,070 4,488 4,654 4,675 Unallocated 42 484 1,050 1,474 1,650 1,650 1,650 1,650 1,650 1,650 z NORTHERN 83 968 2,517 4,199 6,190 8,416 9,791 10,625 10,958 11,000 REGION  -53- ANNEX 7 INDIA SECOND SINGRAULI THERMAL POWER PROJECT Northern Region Planned Investment in the Power Sector 1978-79 to 1982f83 (Rs million) Transmission & Rural Elec- Generation Distribution trification Total Total Plan 1978-79- 1982-83 Haryana 2,024 1,238 387 3,680 Himachal Pradesh 750 245 226 1,245 Jammu & Kashmir 790 646 156 1,633 Punjab 2,697 2,073 687 5,476 Rajasthan 2,974 3,123 859 6,961 Uttar Pradesh 11,313 5,438 1,775 18,670 Delhi 58 1,255 20 1,419 Chandigarh - 88 12 100 Centrall/ 9,789 1,898 - 11,687 TOTAL 30,396 16,003 4,121 50,869 Estimated 1978-79 Haryana 326 211 105 652 Himachal Pradesh 120 31 40 193 Jammu & Kashmir 77 90 40 214 Punjab 461 277 172 913 Rajasthan 187 364 148 700 Uttar Pradesh 1,318 1,041 378 2,751 Delhi 15 216 8 243 Chandigarh - 13 3 16 Central/ 1,131 125 - 1,256 TOTAL 3,635 2,368 894 6,938 1/ Including NTPC Source: GOI Note: Totals are rounded  - 54 - ANNEX 8 Page 1 of 5 pages INDIA SECOND SINGRAULI THERMAL POWER PROJECT Suggested Terms of Reference for a Study to Prepare a Least-Cost Power Development Program Introduction 1. With the rapid growth of the power sector, the increasing size of power plants and the resultant complexity of operation, it has become neces- sary to extend the perspective of power development both geographically and with regard to the considered period, in order to avoid possible unjustified investments in the future and the occurrence of chronic gaps between demand and supply. 2. These Terms of Reference outline the scope of a study to be under- taken by the Central Electricity Authority (CEA) (with possible technical advisory services if consicdered necessary), aimed at preparing a least-cost power development strategy for the country for the next twenty years, initi- ally for the period 1980-2000. The study should be updated periodically (say, every two years) to reflect the current trends in the country's economic development. It would thus become a basis for investment decisions for each five year plan and within the context of a long-range least-cost national program. The study should include, inter alia, detailed demand forecasts. investigations of power generation schemes to meet load growth requirements efficiently, development o:. primary grid configurations, coordination of the power sector with plans for other sectors, resources requirements, and recom- mendations on responsibilities and operational policies at the state, regional and national levels. Existing Facilities 3. The study should review the existing power facilities in the country and those under construction, by state and region, including a general descrip- tion of the supply stations, power and energy capabilities, equipment types, transmission line voltages and configuration, power system characteristics such as load flow, short circuit and stability considerations, and facility retirement schedules. A survey should be made of the present capacities of the generating, transmission and distribution systems in each state/region, as a basis of determining future system expansion requirements. This should include a critical analysis of the availability and capacity utilization of thermal power plants in the public sector with possible targets for improving the situation, and necessary measures to reach these targets. The types and sizes of generating capacities in the private sector should be included so that data are available on the overall power sector.  - 55 - ANNEX 8 Page 2 of 5 pages Existing Power Market 4. The historic power market should be reviewed by state/region, covering at least ten years, i.e., 1970-80, divided into the various consumer categories with special emphasis on large industrial loads. System energy losses should be reviewed by state/region, and losses should be broken down in those attributable to station auxiliaries, transmission losses, distri- bution losses, unpaid electricity, etc. The pattern and trend of monthly peak (kW) and energy (kWh) demands should be studied and any unsatisfied demand, peak and/or energy, should be estimated. Load Forecast 5. Load forecasts should be made, building on the framework of the "Annual Power Surveys" for the period 1980-2000, including, if necessary, monthly forecasts in regions where hydro energy availability in critical water years may influence the development program. Appropriate methodology should be used, including extrapolation of statistical data, regression modeling using the relationship between electricity consumption and appro- priate independent variables such as gross domestic product, analysis of urbanization and electrification trends, projected population growth, satu- ration of present market, consideration of the sales impact of expected future tariffs, review of trends in reduction of losses and unpaid consump- tion, and a survey of expected major industrial consumers and other economic development plans with consideration of possible delays in implementation schedules. The forecast for each state/region should be developed on an energy basis, thereafter determining peak demand based on the expected evolu- tion of the system load factor. To allow for data uncertainties, a range of forecasts should be developed (i.e., "high," "low," "most likely") and the basis of each and its probability should be explained. 6. The regional load forecasts should be combined into a national forecast with appropriate consideration of any possible diversities between regions. Energy Resources 7. The country's known energy resources--coal, oil, gas, hydro, nuclear fuels should be reviewed giving all available data including location, size of field and reserves, available energy and capacity in the case of hydro sites, ownership, present production, national market, future production schedules, refinery plans, economic costs, etc. An assessment should be made of the alternative uses of these resources, e.g., in the case of natural gas, use as feedstock for fertilizer or petrochemical production. Least-Cost Regional Programs 8. Taking account of possible interconnections between states and regions (see para 14), all practicable alternatives should be considered in the preparation of regional least-cost development programs, comprising the most beneficial combination of thermal, hydro and nuclear power plants.  - 56 - ANNEX 8 Page 3 of 5 pages 9. The capital costs should be based on present (1979 or 1980) prices, excluding taxes, duties or interest during construction (which should be shown separately) without escalation. The capital costs should be separated into civil works, electromechanical works, engineering, administration (for owners's costs associated with project execution) and physical contingencies. All costs should be expressed in CIF/FOB prices or their equivalent. Capital cost estimates should be prepared for the hydro sources that are known from the results of the available studies and for thermal alternatives from recent feasibility studies. 10. Recurrent operation and maintenance costs (except fuel) should also be based on present prices, without allowance for future inflation. The fuel requirements of the alternatives considered should be valued at their oppor- tunity cost, e.g., coal at its incremental cost of production; crude oil. at import or possible export price; residual fuel oil at the import price (or export price, if to be supplied from local refineries), and natural gas at its economic value if not used for electricity production. I1. Other shadow prices should be used wherever appropriate in costing the alternatives (e.g., for valuing unskilled labor). 12. least-cost development programs should be prepared for each region based on a common reliability standard say, a capacity reserve from a loss of load probability analysis (LOLP) using the discounted cash flow method to compare alternative programs for the period 1980-2000. The comparison of the alternative programs should include all relevant transmission costs where these may change with alternative programs. 13. The discounted cash flow comparison should be based on a 10% opportunity cost of capital with sensitivity testing in the range of 8 to 13%. Sinking fund residual values, if any, of the capital costs at the end of the discount period should be deducted. Changes in plant scheduling and possible changes in plant mixes through adoption of the "high" or "low" load forecasts should be expected. Sensitivity testing should also be conducted for changes, over the range of possible values, in capital costs, and operating and main- tenance costs. Regional Interconnections 14. It is expected that within the 1980-2000 study period, interconnec- tion of most, if not all, of the state/regional systems may become feasible. The regional programs should, therefore, be restudied assuming various inter- connections to consider the benefit obtained through reduction of generating capacity reserves, complementary operation of hydro and thermal sources, increased energy capability if some hydraulic diversity exists, more rapid absorption of major new sources, increased availability and utilization of existing capacities, etc. For this purpose the relative merits of different transmission voltages should be compared to determine the most economic choice of the next voltage level, including DC back to back ties, given the expected long-term development of the national power system.  - 57 - ANNEX 8 Page 4 of 5 pages Organization of the Power Sector 15. The study should examine the present organization of the Power Sector, with the State Electricity Boards as principal agencies and the recently created national corporations, NTPC and NHPC, which are responsible for the construction and operation of large power plants. Recommendations should be made with regard to the long-term measures to be taken by the Government in the organization of the sector to reflect the structural changes in the power systems, from state level to region level and finally to an interconnected national grid. Constraints 16. Of major consideration in the study would be the financing of growth in the electricity industry. The rate at which electricity consump- tion has been growing relative to GNP is much higher in India than is typical in other countries, being about 2:1 as against 1:1 respectively. The ability to mobilize resources to finance continued growth at this level is likely to be a restricting factor to the development of the physical program. Another factor which in the past has curtailed physical achievements is inflation. The study would need to review financial planning methodology currently used by GOI in investment planning to recognize the existence of inflation. (Con- sidering the relatively long gestation periods of generation projects, resources which have been earmarked for the physical program have to be diverted to finance inflation of earlier projects unless additional resources can be mobilized. 17. Other points of reference would be: (a) Sources of resource mobilization. There is need to increase the internal resources generated by the SEBs so as to relieve the burden of financing of the power sector from general revenue sources. (b) Need for efficiency in operations of SEBs--improved organi- zational structure and management, and more efficient use of existing plants. Study Results 18. The study results should show the least-cost national program, region by region, and combination of regions where interconnection is recommended within the period 1980-2000, based on a rational discount rate and the "most likely" load forecast. A full explanation of the impact of the various sensitivity tests should be given, including related recommenda- tions in cases where substantial savings or increases in reliability could be made by small changes in the base assumptions. 19. The schedule of projects and their costs comprising the least-cost program for the period 1980-2000, together with the year-by-year investments (at least until 1995), should be shown for each region and combined into a  - 58 - ANNEX 8 Page 5 of 5 pages national total (including estimates for the private sector), with appropriate regional investments for transmission and distribution, to provide the overall power sector investment requirements. 20. The study results should include proposals for the organization of the Power Sector, the phases of its implementation and for increasing of sector efficiency. 21. The results should be compared to the investment program presently planned or under construction for the initial part of the study period. The "ideal" schedule of projects as resulting from the study should be reviewed in the light of projects under implementation that might not be fully con- sistent with the study results. Similarly, "second-best" scenarios should be prepared taking into account the resource constraints.  - 59 - ANNEX 9 Page 1 of 2 pages INDIA SECOND SINGRAULI THERMAL POWER PROJECT Financial Position of the State Electricity Boards 1. The problems associated with the SEBs' financial position have been the subject of continuing dialogue with GOI. Under previous transmission Credits/Loan, the beneficiary SEBs undertook to achieve and maintain rates of return of 9-1/2% (on a rate base stated at actual cost), in some cases on a graduated basis, in order to take account of particular circumtances. (See Attachment 1). In all cases the 9-1/2% rate was to be achieved by FY1979. Results have been moderately successful, with a wide variation in performance as between SEBs. By FY1977, seven out of the sixteen major SEBs achieved their target rates of return, with a further two SEBs reaching their targets in FY1978 with the help of rural electrification subsidies from their State Governments under the conditions of eligibility for the second rural electri- fication project (Credit 911-IN). Uttar Pradesh SEB is expected to reach 9-1/2% in FY1979 mainly due to State Government rural electrification subsi- dization commencing in that year, again under eligibility criteria of Credit 911-IN. The other six SEBs, while not reaching the stipulated return, showed improving trends up through FY1977. However, the results generally deterio- rated during FYs1978 and 1979 to leave seven out of the sixteen major SEBs in a position of default on their rate of return undertakings with the Association. This group included two Northern Region SEBs, Haryana and Rajasthan, and the DESU (recipients of Singrauli power). 2. The main reason for the poor financial performance of some of the SEBs was that tariffs have not kept pace with increases in operating costs thus not ensuring that a healthy ratio between operating income and capital base is maintained during periods of expansion. Other factors which have adversely affected financial performance were: low availability of plant and of power imports from neighboring state systems, and increased cost of these imports because of a higher proportion of expensive thermal power where pre- viously cheaper hydro power was available. It can be justifiably argued that the situation faced by some SEBs did not constitute "normal circumatances" and that the achievement of covenanted rates of return could not be realistic- ally expected. 3. During appraisal, financial plans for the restoration of rates of return to at least 9-1/2% were discussed with the SEBs and the DESU of the Northern Region and found acceptable. These plans either have been imple- mented or are under implementation and consist of: tariff increases ranging from 10-14%, rationalization of manpower requirements, improving generating efficiency, reduction in line losses, improved billing and collection proce- dures, and introduction of other cost reduction measures. In the case of Haryana, plans include the commencement of subsidization of rural electrifi- cation losses by the State Government.  -60 - ANNEX 9 Page 2 of 2 pages 4. The financial provisions of the Electricity (Supply) Act, 1948, have been recently amended to put the operations of the SEBs on a more com- mercial basis by enabling them to generate internally a reasonahie (considered by CEA to be 20-25%) contribution to their capital investments. Under the Amendments (Section 59 (1)), the State Governments are now required to specify the level of annual surplus which should be earned by their SEBs to enable them to comply with the amended legislation. The manner in which this will be achieved is a subject which has been under evaluation by both the State Governments in conjunction with their SEBs, and by the finance panel of the Rajadhyaksha Committee. Complex issues are involved which will require "tailoring" by each State Government to meet the particular circumtances of its SEB, while at the same time giving due consideration to State resources and impact on consumers. CEA has issued guidelines to the State Governments and the SEBs explaining these issues and pointing out the measures that need to be taken by each of them and the options which are available. 5. The guidelines emphasize the following aspects: (i) special steps to increase sales volume; (ii) economies in both operating costs and capital expenditure; (iii) more efficient asset utilization; (iv) timely commissioning of new projects; (v) reduction in line losses; (vi) improved financial management; (vii) tariff revisions to reflect cost of supply; (viii) capital structure adjustemnts - SEBs may now receive funds from the State Government in the form of share capital, and State Government loans may now be con- verted into share capital; (ix) disposal of arrears of State Government loan interest; and (x) basis for charging depreciation of fixed assets. 6. Because of the far reaching consequences of the above measures, the State Governments and their SEBs are awaiting the findings of the Rajadhyaksha Committee before implementing financial policies to give effect to the finan- cial amendments of the Electricity (Supply) Act 1948.  INDIA Second Singrau i Thermnal Power Project Rates of Return !:/of SEBs FY 1976 - FY 1980 FY 1976 | F1977 FY 1978 FY 1979 FY 1980 (Actual) (Actual) (ActuAl) (Estimated) (Ehxpectation) Return to Return inc. Return to Return incl. Return to Return incl. Return to Return incl. Return to Return incl. SEBs SEB State Dutiea SEB State Duties SEB State Duties SEB State Duties SEB State Duties . % q . % % % % Andhra Pradesh 7.7 7.7 9.0 9.0 9.5 9.5 9.5 9.5 t 9.5 9.5 AsawA 6.4 7.4 12.3 13.5 10.4F 11.5F 2.0 3.4 "'A NA Bihar 7.0 8.5 8.1 9.5 8.0 9.4 1.8 2.6 I.b 2.b Gujarat 7.9 11.0 9.7 13.9 9.5 13.5 I 9.5 13.5 9.5 13.3 Haryana 7.2 11.4 6.4 10,9 6.6 10.6 10. OA 14.4A 9.5 13.5 Maharashtra 10.0 11.5 13.0 14. 5 15.3 16.8 14.2A 15,7A 9. 5 11.0 Punjab 7.4 10.1 8.2 11, 9. 5 11.9 9.5A 11,9A 9 . 11.6 Rajasthan 8.7 9.9 9.2 10,5 '7.9 9.0 i 8.6 9.6 9.5 10.5 Uttar Pradesh 4.6 5.4 5.8 6.6 o.s 1.6 9.5 10.1 9.5 10.1 West Bengal 6,o 8.0 9.5 11.1 9.8 11.0 9.5 11.1 7 0 8.5 Delhi ESU (14.7) (9.6) 7.6 12.9 7.6 14.7 8.6 18.5 S.5 15.4 Kerala 5.9 8.1 8.5 10.5 8.0 9.9 7.5 9.5 8.7 10.7 Madhya Pradesh 12.8 15.4 13.1 15.3 14.7 16.7 11.2 13.2 9.5 11.5 Karnataka 10.0 14.9 15.8 20.7 8.3F 12.6F 7.1 11.0 NA NA Orissa 5.8 9.1 6.3 9.9 4.8 9.1 4.9 9.9 4.9 9.7 Tamil Nadu 9.7 10.4 9.5 10.3 9.5 10.3 9.5 10.2 9.5 10.2 INDEX F = Forecast A = Actual :L NA = Not Available 8 I/ Target rate of return in general is 95,%. When this was established in 1964. it was also conceived that an averape eZr is txY or duty eao;val.nt +o a .+,-r of 1 5 1 would *b- H applied, making the total expected return 11%. Effective March 1978, GGI has levied am additional excise tax of 2 paise/kWh of generation which is not included ebore. TS would add an estimated 2-3 percentage points to tbe returns noted.  - 62 - ANNEX 10 Page 1 of 2 pages INDIA SECOND SINGRAULI THERMAL POWER PROJECT Ministry of Energy (Department of Power) No. 31 (33)/78-US. V New Delhi, November 27, 1978 Terms of Reference of the "Rajadhjaksha Committee" on Power Power Planning 1. Evaluate the methodology adopted for the present power survey and demand forecast being made by the Central Electricity Authority; examine the introduction of concepts of energy management in the power industry; critic- ally examine the thermal-hydel-nuclear mix for power development in the national regional contexts and the time frame in which such plans are made; examine other aspects of power planning including institutional changes interstate linkages in power, the role of central generation and Regional Electricity Boards; and the problems of funding the massive investments in the power sector; study the need for and policy regarding captive power generation. Project Formulation and Implementation 2. Review the approach by the State and Central organizations in formulating projects examine the procedures and evaluation criteria adopted by the CEA for approving them; examine the need and scope for standardization of project design especially in thermal and transmission projects; examine the procedures/agencies fcr implementation of major projects with a view to reducing/eliminating the delays and cost overruns; identify the more common constraints in execution; and propose measures to remove them, including training in project implementation and monitoring systems, and availability of power equipment for generation, transmission and distribution; also study the institutional/organizational framework in this regard. Operation and Maintenance 3. Review the operational efficiency (including outages, renovation schemes and maintenance standards of present equipment) of power stations and the state grids, and suggest ways and means of improvement; suggest methods for the optimum utilization of present installed capacity including the flattening of the load curve by restructuring demand patterns, incentives, etc., identify shortcomings in the training institutions/programs being provided for power plant operators and evolve appropriate systems of training norms for operations and maintenance personnel.  - 63 - ANNEX 10 Page 2 of 2 pages Organization and Management 4. Study the organization of State Electricity Boards afid other Central bodies in the Power Sector (including Central Undertakings) and suggest ways and means for increasing their effectiveness/efficiency; also examine the need for creation of new organizations to fill specific gaps; examine the existing legislation with regard to the adequacy of its provision for the proper organization of the State Electricity Boards; evaluate the recruitment and selection procedures of these organizations training schemes and also the extent of professionalization achieved so far; evolve guidelines for the appropriate relationship between Electricity Boards and the State/central bodies. Finance, Financial Management and Tariffs 5. Study in depth the financial working of Electricity Boards and other generation and distribution organizations; study the existing legisla- tive framework to make the Boards financially viable and make recommendations in this regard; examine ways and means of funding needs of the power sector both at State and Central levels and suggest changes required in this regard; examine procedures for capitalization of interest charges during construction and principles regarding the depreciation of assets, cost accounting methods and related issues; study the tariff structure in the various States, includ- ing matters relating the concession given to certain classes of consumers; examine the desirability for adopting of marginal cost pricing in India in the light of experience in other countries; study the problems encountered in interstate sales of power, and suggest institutional and other changes. Rural Electrification 6. Evaluate the progress achieved so far by the rural electrification programs in meeting its stated social and economic objectives and identify the constraints in timely project implementation and efficient operation and manning norms; study the organizations concerned with rural electrification, i.e., Electricity Boards, Rural Electrification Corporation, etc., the finan- cial working of the organizations involved in rural electrification and sug- gest ways and means of augmenting the resources available for the purpose; evolve criteria for distribution of funds to various States for rural elec- trification programs keeping in view regional imbalances; examine patterns/ procedures for financing capital outlays to rural power consumers and their problems of maintenance of power equipment; study the implications of subsi- dizing extensive rural electrification, especially its implications for the tariff policies to be adopted by the Boards; examine alternative energy systems for motive power in rural areas and suggest policy guidelines. Research and Development in Power Sector 7. Evaluate the present state of R&D in the power industry, make recommendations for the systematic development of R&D work with a view to improve planning techniques, system/station efficiencies and reliability.  INDIA SECOND SINGRAULI THERMAL POWER PROJECT NATIONAL THERMAL POWER CORPORATION LIMITED Organization Chart CHAIRMAN & MANAGING DIRECTOR MANAGEMENT COMMITTEE| PROJECT REVIEW TEAMS PLANNINGFINANCE | PERSONNEI MARKTIN SECFRETARY ' & TRAIN ING |c TECHNICAL SERVICES CONTRACT DIVISION QUALITY CONTRACTS ASSURANCE & EXPEDITING OQ z p]~~~~~~~~~~~~~~~~~ m BADARPUR SINGRAULI KORBA RAMAGUNDAM FARAKKA I TRANSMISSION 00 THERMAL POVVER THERMAL THERMAL THERMAL THERMAL |SYSTEMS STATION/PROJECT POWER PROJECT POWER PROJECT POVVER PROJECT POWER PROJECT |DIVISINW World Bank - 20639 CD  INDIA SECOND SINGRAULI THERMAL POWER PROJECT NATIONAL THERMAL POWER CORPORATION LIMITED Project Organization GENERAL MANAGER PLANNING & SYSTEMS QUALITY SURVEILLANCE MATERIALSCCIVIL FINANCE & EQUIPMENT PERSONNEL I, MANAGEMENT CONSTRUCTION ACCOUNTS ERECTION & ADMIN. E | _ ~~~~~~~~~~~~~~FIELD ENGINEERING 1 CONTROL& COAL NSTRUMENTA HANDLING & 0 P TION TRANSPORT -6 w  INDIA SECOND SINGRAULI THERMAL POWER PROJECT NATIONAL THERMAL POWER CORPORATION LIMITED Technical Services Division GENERAL MANAGER (ENGINEERING) OPERATION PLANT AND CIVIL AND SERVICES EQUIPMENT SYSTEMS ENGINEERING ENGINEERING PROJECT ENG MGMT. CO-ORDS. SERVICES OPERATiON MECHANICAL NT A ELECTRICAL TRANSMISSION CIVIL SYSTEMS CONSTRUCTION SERVICES DESIGN TRMN DESIGN COORDINATION DESIGN ENGINEERING SERVICES World Bank -20641