Report No. 833a-NEP IFLE C:tiP Nepal u Appraisal of the Kulekhani Hydroelectric Project November 25, 1975 Power Division South Asia Projects Department Not for Public Use Document of the World Bank This document has a restricted distribution and may be used by recipients only in the performance of their official duties. Its contents may not otherwise be disclosed without World Bank authorization. CURRENCY EQUIVALENT To October 9, 1975 US$1 n 10.56 Nepal Rupees (NRs.) NR 1 - US cents 9.47 NR1 - O 100 pais From October 9. 1975 US$1 = 12.50 Nepal Rupees (NRs.) NR 1 US cents 8.00 WEIGHTS AND MEASURES EQUIVALENT kV - Kilovolt = 1000 volts kW - Kilowatt - 1000 watts MW - Megawatt = 1000 kilowatts kWh a Kilowatt hour 1000 watt hours GWh = Gigawatt hour = 1000000 kilowatt hours KVA - Kilovolt amperes = 1000 volt amperes ha - hectares = 10000 square meters ACRONYMS AND ABBREVIATIONS HMG - His Majesty's Government of Nepal ED - Electricity Department of the Ministry of Water and Power NEC - Nepal Electricity Corporation EEC 0 Eastern Electricity Corporation BPC m Butwal Power Company ADB u Asian Development Bank OECF - Japanese Overseas Economic Cooperation Fund NK - Nippon Koei Co., Ltd. Nepal's Fiscal Year - Year beginning July 16 and ending July 15. NEPAL APPRAISAL OF THE KULEKHANI HYDROELECTRIC PROJECT TABLE OF CONTENTS Page No. SUMMARY AND CONCLUSIONS ....... . . . ................. .o. . i - ii I. INTRODUCTION . ...... ... ... . . .... -.*... 1 II. THE COUNTRY, THE ECONOMY AND THE SECTOR ... o...... 1 The Country and the Economy ................. 1 The Power Sector s..*.. o.....*....ee"..0.0 2 Existing Facilities .. .... * * * * ... * * *.-o-o* * * * * * * .... 3 Energy Resources .o-.* ....... ....-..o... * 4 Development Strategy .. ..................... . 4 Power Development Program .......... ......... 4 Rural Electrification ..................... ... 5 III. THE BORROWER AND THE BENEFICIARY ......o. .......... 5 Organization and Management .. . .............. 6 Electricity Department ..... . .................. 6 Nepal Electricity Corporation ............... 6 System Loss ... o......................................... se 7 IV. THE PROJECT .............. . -. *.....**.....t. 7 The Project ...o........ . . . .. . . ............-.... *.*.*.. 7 Cost Estimate ...........................-... 8 Financing Arrangements ...................... 10 Ptocurement and Disbursement ....... o...... o. 11 Consulting Services ... .. .. ...*. ....... . . . . . .. 11 Implementation Schedule ..................... 11 Hydrology ooe ...................... o...o........ ..... se 12 Geology ........................................ ........ 12 Ecology ... ............ 0........ ......................... 12 V. PROJECT JUSTIFICATION ................. see ..... ... 13 The Power Market ........ . . ........................ ....ee 13 The Least Cost Solution ........... . ... 14 Return on Investment ...............0...0...... 15 -2- Page No. VI. FINANCIAL ASPECTS ................ **. .*..*......... 15 Past and Present Earnings .....000.............. 15 Present Financial Position .......... ........ 16 Tariffs ................................... 16 Future Earnings ........ ..... 16 Proposed Financing Plan * .................... 17 Future Finances .. .. .. ............ ........ . 19 Accounts Receivable ................ ......... 19 Dividends o.*...... .***. * ..... .... 19 Audit *................................ .. 20 VII. AGREEMENTS RIAChED AND RECOMMENDATION ............ 20 LIST OF ANNEXES ANNEX 1 - Generating Facilities in Nepal ANNEX 2 - Principal Hydro Power Stations ANNEX 3 - Principal Thermal Power Stations ANNEX 4 - Power Development Program (No. 9546 R) ANNEX 5 - Organization Chart - Electricity Department (No. 8849) ANNEX 6 - Resume of Nepal Electricity Corporation Act ANNEX 7 - Organization Chart - Nepal Electricity Corporation (No. 8848) ANNEX 8 - Project Description ANNEX 9 - Cost Estimate ANNEX 10 - Disbursement Schedule ANNEX 11 - Schedule of Implementation (No. 15252 R) ANNEX 12 - Hydrology ANJNEX 13 - Geology ANNEX 14 - Proposed Detailed Investigations and Studies ANNEX 15 - Operating Statistics, Nepal Electricity Corporation ANNEX 16 - Load Forecast, Nepal Electricity Corporation ANNEX 17 - System Load and Generating Capacity ANNEX 18 - The Least Cost Solution ANNEX 19 - Return on Investment ANNEX 20 - Incremental Cost of Energy ANNEX 21 - Schedule of Current Tariffs - Nepal Electricity Corporation ANNEX 22.1- NEC Income Statement for FY 1970/71 through FY 1982/83 ANNEX 22.2- Analysis of kWh sold, Revenues and Revenues per kWh ANNEX 22.3- Statement Showing Impact of Tax and Royalty on Proposed Tariff Increases ANINEX 23.1- NEC Sources & Application of Funds - FY 1974/75 through FY 1982/83 ANNEX 23.2- Capital Expenditure Program - FY 1974/75 through FY 1982/83 ANNEX 24 - Condensed Balance Sheet at mid-July 1971 through mid- July 1983 ANNEX 25 - Assumptions for Financial Projections MAP 1 - Location of Existing and Future Power Installations (IBRD-10107 R3) MAP 2 - General Plan and Profile of the Project (IBRD-11931) NEPAL APPRAISAL OF THE KULEKHANI HYDROELECTRIC PROJECT SUMMARY AND CONCLUSIONS i. This report appraises the Kulekhani Hydroelectric Project which is needed to meet the rapid growth of power demand for the Central Power System in Nepal. The Project will consist of a dam, a headrace tunnel, a surge tank, a penstock and an underground powerhouse containing two 30 MW generating units and associated 66 kV transmission line and switchyard facilities. The Project will be the key element of the Fifth Five-Year Plan of his Majesty's Government of Nepal (HMG) to provide adequate power supply for agricultural, industrial as well as commercial development. It would meet the system requirement up to 1985/86. ii. The total cost of the Project is estimated at about US$68.0 million equivalent including a foreign exchange component of US$56.5 million. The Japanese Government has approved in principle a loan of 3.0 billion Yen (about US$10.0 million equivalent) to finance the foreign exchange cost of electrical and mechanical equipment. The proposed IDA credit of US$26.0 million would be applied against the foreign exchange cost of civil works for main dam and spillway. The Kuwait Fund for Arab Economic Development (The Kuwait Fund) has approved in principle a loan of Kuwaiti Dinars (KD) 5.0 million (about US$17.5 million equivalent) to assist in financing the cost of preliminary works, hydro-mechanical equipment and civil works other than main dam and spillway. UNDP has approved a grant of US$3.0 million equivalent to finance the consulting services. Any balance of foreign exchange and local costs would be financed by HMG. iii. The Borrower would be HMG. The Electricity Department (ED) of the Ministry of Water and Power would be the Executing Agency and the Nepal Electricity Corporation (NEC), the Beneficiary, which would take over and operate the Project upon its completion. The proposed credit would be the first by the Bank Group for the power sector in Nepal. iv. ED is responsible for the planning and construction of generation and transmission facilities in Nepal. NEC, a government-owned corporation, is responsible for the operation in the Central System comprising Bagmati (Kathmandu Valley) and Narayani Zones. The Central System is the largest and most developed electricity supply system in Nepal, accounting for 73% of Nepal's installed capacity. v. By December 1974 NEC had a total generating capacity of 39.9 MW, comprising 31.6 MW of hydro and 8.3 MW of diesel. Maximum demand in 1974/75 was 30.4 MW. It has been increasing at an average rate of 22% per annum over the past ten years. The latest load forecast indicates that maximum demand would increase to 93.5 MW in 1983/84, an average annual rate of growth of 14% over the next decade. - ii - vi. ED's future expansion program for the Central System includes the construction of the 15 MW Gandak Hydro Project, the 14 MW Devighat Hydro Project and their associated transmission lines and substations. The Gandak project is presently under construction assisted by the Indian Government. The technical and financial assistance for the Devighat project is being sought from the Indian Government. The proposed Kulekhani Project is the next logical project. Total capital investments of the Central System are estimated at US$123 million over the 1975/76 -1982/83 period. The proposed Project would account for 56% of this total. vii. The proposed Project is the least cost solution for discount rates up to 13% when compared with the best thermal alternative (1-30 MW coal- f ired unit plus 2 - 15 MW gas turbines). Two additional power stations, Kulekhani No. 2 (35 MW) and Kulekhani No. 3 (17 MW) could be constructed downstream, utilizing the regulated flow from the reservoir. There are also other benefits such as downstream irrigation (about 10,000 ha.), fisheries and recreation. viii. The civil works contract to be financed under the proposed credit would be awarded on the basis of international competitive bidding. Nippon Koei Co., Ltd. of Japan (NK) has been engaged to provide consulting services for field investigation, engineering design, procurement and construction supervision of the Project with the Bank acting as the Executing Agency for UNDP. ix. A large part of NEC's plant has been donated by Nepal's neighboring C.ountries, and transferred by HMG as equity capital. As a result NEC is free from long-term debt, it pays only token dividends and its annual cash flow, despite low tariffs presently averaging 23.9 pais per kWh (USd1.9), has been able to finance its distribution requirements. Power programs have not been carried out according to schedule and in the interim period until the Kulekhani Project is completed, NEC's existing plant will not meet demand even with considerable high cost diesel generation and substantial load shedding. x. NEC pays royalty (7.5 pais per kWh) and is subject to tax at about 60% of net income (after interest). Its rate of return in FY 1974/75 was a negative 1.4%. Substantial tariff increases will be required to meet a rate of return of 2.5% in FY 1975/76 rising to 6% by FY 1980/81. xi. The proposed Project would be a suitable basis for a Development Credit of US$26 million equivalent. I. INTRODUCTION 1.01 This report covers the appraisal of the Kulekhani Hydroelectric Project for which HMG has requested financial assistance. The Project consists of a dam, a headrace tunnel, a surge tank, a penstock and an under- ground powerhouse containing two generating units of 30 MW each and the associated transmission line and switchward facilities. The first unit is scheduled for completion by the end of 1979/80 and the second unit within 12 to 24 months. 1.02 The total cost is estimated at US$68.0 million equivalent of which US$56.5 million is the foreign exchange cost and US$11.5 million equivalent the local cost. HMG has requested financial assistance from the Japanese Government, the Association, the Kuwait Fund and UNDP. The Japanese Govern- ment has approved in principle a loan of 3.0 billion Yen (about US$10.0 mil- lion) for a term of 30 years including ten years grace with interest at 2.75% per annum to finance the foreign exchange cost of electro-mechanical equip- ment, associated transmission line and switchyard facilities. The proposed credit of US$26.0 million, would be applied against the foreign exchange cost of civil works for the main dam and spillway. The Kuwait Fund has approved in principle a loan of KD 5.0 million (about US$17.5 million) for a term of 32 years including 7 years grace with interest at 3% per annum to apply to the cost of preliminary works, hydro-mechanical equipment and civil works other than main dam and spillway. UNDP has approved a grant of US$3.0 million equivalent to finance the consulting services. Any balance of local and foreign exchange costs would be covered by HMG out of its own resources. 1.03 The proposed credit would be the Association's eighth to Nepal (total commitment for the previous seven credits is US$32.7 million equiv- alent net of cancellation) and the first for the power sector. 1.04 This report is based on a feasibility report (September 1974) and a report on geological investigation (July 1975) prepared by Nippon Koei (NK), HMG's Consultants, on information provided by the Electricity Department of HMG (ED) and Nepal Electricity Corporation (NEC) and on the findings of an appraisal mission composed of Messrs. K.C. Ling and S.S. Scales, which visited Nepal in November/December, 1974. II. THE COUNTRY, THE ECONOMY AND THE SECTOR The Country and the Economy 2.01 The Kingdom of Nepal is located between 26.200 to 30.10° North Latitude and 80.150 to 88° East Longitude. It has an area of 140,797 Km2. The average length from east to west is about 880 km and average width from north to south about 190 km. Its northern boundary merges with the Tibet region of the People's Republic of China. On the east it borders the States of Sikkim and the northern part of the State of Bengal in India. On the southern and western sides it touches the Indian states of Bihar and Uttar Pradesh. -2- 2.02 High mountains and rolling hills account for about 83% of the total area; the remaining 17% is occupied by the flat land of Terai. There are five well-defined regions extending from south to north: the Terai plain; the Siwalik Hills; the Mahabharat Range; the Midland and the Himalayas Range. 2.03 The population in Nepal is presently estimated at 12.3 million, growing at about 2.2% per annum. Population distribution is closely con- trolled by topography and is very irregular. More than one-third of the population lives in the Terai. The Western Terai has a population density of about 374 people per km2, while the Eastern Terai has 1,380 and the Central Terai, 741. 2.04 Nepal has been classified by the United Nations as one of the least developed countries. GDP was estimated at US$1,280 million in 1973/74 and is growing annually at about 2.2% in real terms. Per capita GDP is about US$90-100. The principal economic activity is agriculture which accounts for 70% of the GDP and provides employment for over 90% of the labor force. The main cash crops are rice, jute, sugar, oil seeds and tobacco, largely produced in the Eastern Terai. There is also some timber logging in the central and western areas. Industry, which is concentrated in the Eastern Terai aand the Kathmandu-Hetauda-Birganj corridor, consti- tutes about 10% of GDP (including 7% for cottage industry). Tourism, growing at 30% per year, is beginning to assume importance in the country's economy and foreign exchange earnings. 2.05 Serious efforts towards development have been underway only since the late 1950's. Development expenditures have increased rapidly from NRs. 232 million in 1964/65 to NRs. 930 million in 1974/75. The great bulk of the resources available for development have been invested in infrastruc- ture, particularly road, power and irrigation facilities. About half of the expenditures for development during this period have been financed with external assistance, notably from India, the United States and the People's Republic of China. About 80% has been in the form of grants. Nepal's ex- ternal debt service has remained very low (US$1.5 million in 1974). Gross external reserves as of November 1974 stood at US$139 million which declined to US$94 million by September 1975. The Power Sector 2.06 There are at present four organizations in the field of public power supply in Nepal: (a) The Electricity Department of the Ministry of Water and Power (ED); (b) The Nepal Electricity Corporation (NEC); (c) The Eastern Electricity Corporation (EEC); and (d) The Butwal Power Company (BPC). - 3 - 2.07 ED is responsible for electric power development throughout the Kingdom of Nepal. It plans and constructs new generation and transmission facilities and controls privately-owned utilities. At present, apart from Sunkosi HE plant (10 MW), it also operates the small government-owned facilities and distributes electricity in Pokhara and in about fifteen newly- electrified towns. 2.08 NEC, a government owned corporation, is responsible for generating and distributing electricity in the area of the Bagmati Zone where the Kathmandu Valley is located and, since April 1973, the Narayani Zone. 2.09 EEC, established in October 1974, has since taken over two private entities, the Morang Hydro Electric Supply Company (MHESC) and the Dharan Electricity Corporation (DESC). It is owned up to 25% by NEC and the remainder by HMG. The Butwal Power Company (BPC) is entirely a private company. 2.10 There are about 64,200 consumers in Nepal, representing less than 3% of total population. Out of these, 56,000 are in the Central System, comprising 1.3% industrial, 98.5% domestic and 0.2%' commercial and other consumers. Per capita generation in 1973/74 was only 10 kWh compared to 20 kWh and 120 kWh in Bangladesh and India, respectively. On the basis of actual consumption per capita, the figure would come o'wn to 7 kWh. 2.11 The sector has a labor force of about 2,370, representing about 0f.05% of the country's total, and creates about 0.2% of GDP. Existing Facilities 2.12 The total present installed generating capacity in the entire sector is 54.2 MW, of which 33.4 MW is hydro, 17 MW diesel and 3.8 MW steam (Annex 1). Public service accounts for 46.0 MW or about 85%; the remaining 8.2 MW are captive generating plants. The largest unit sizes are 3,350 kW hydro, 1,490 kW diesel and 1,600 kW steam. 2.13 The Central System operated by NEC is the largest and most developed electricity supply system in Nepal. Power is supplied by five hydro and four diesel stations with a total capacity of 31.6 MW and 8.3 MW respectively (see Annexes 2 and 3 for details). Transmission is carried out at three voltage levels: 66 kV, 33 kV and 11 kV, with a total length of 276 km. A 150 km, 132 kV transmission line is now under construction between Gandak and Hetauda financed under an ADB loan. 2.14 The second most important area is the Kosi zone around the city of Biratnagar operated by EEC. The present total installed capacity in this area is about 6 MW which represents 43% of the power facilities outside the Central System. The power in this area is supplied mainly from diesel and thermal generating units supplemented by a micro hydro plant at Dhankuta (240 KW) and by power exchange with India. - 4 - 2.15 The principal power facilities in the country are shown in Annexes 2 and 3 and their locations indicated on Map 1. During the past three years, about fifteen cities or townships have been supplied with electricity by ED through the installation of micro hydro plant and diesel units (about 3,065 kW in total, some of which were relocated from the Central System), extension of 33 kV transmission lines and through exchanges of power with India along the southern border. Energy Resources 2.16 Nepal has no known indigenous sources of commercial energy with the exception of hydro. Stretching between the Himalayas and the Gangetic Plains, Nepal is one of the few countries in the world with a very high, but still undeveloped hydroelectric potential. Estimates exceed 80,000 MW. Only Karnali River Basin has so far been systematically explored. A UNDP- financed study undertaken during 1963-1966 identified ten possible schemes ranging in potential capacity from 18 MW to 1,800 MW, with a total of 6,600 MW for the entire basin. Development Strategy 2.17 The Government's basic strategy for development of the sector is based on hydroelectric power. In early years when the load is too small to permit the economic development of large hydroelectric schemes, local requirements will be met by micro hydro or diesel installation or, in the case of border areas, by importing electricity from India. This strategy is sound. 2.18 In the Fifth Five-Year l'lan (1975/76 - 1979/80), the major objec- tives of power development are: (a) to further develop hydroelectric resources to meet the increasing power demand; (b) to extend electric services gradually to new areas in the country; (c) to bring about regional balance in the production and distribution of electric power. PFower Development Program 2.19 ED's future expansion program (Annex 4) for the Central System includes the following: (a) the Gandak Hydro Project (3 x 5 MW) presently under construction by the Government of India to be completed in 1976/77; (b) a proposed hydro project (14 MW) at Devighat downstream of the existing Trisuli power station with technical and financial assistance to be arranged with the Government of India; (c) the Kulekhani Hydro Project (2 x 30 MW) to be completed by end 1979/80 for the first unit and 1981/82 for the second unit. This is the project for which a development credit is proposed; and (d) associated transmission lines and substations. 2.20 For purposes of future project preparation, ED is seeking UNDP assistance to undertake: (a) the preparation of a master plan for the hydro power development of the Gandak river basin and the completion of a feasibility study of the most promising scheme; (b) a preliminary study of hydroelectric schemes on the Seti river; (c) a preliminary study of the Bagmati High Dam Hydroelectric Project; and (d) a feasibility study of the Sarda river hydro- electric scheme. 2.21 The first three are for the development of hydro potential in central Nepal while the last one is for the development of the Far Western Region. They are the logical schemes to be studied. Rural Electrification 2.22 Since 1970, NEC provided supply to about 13,600 rural households in the Kathmandu Valley. So far, NEC bears all the distribution costs, the consumers pay only a connection charge and costs for interior wiring. NEC plans to spend a total of about NRs. 30 million to electrify 30,000 more households during the next 10 years, but in view of inadequate generating capability and financing constraints, this program will have to be deferred until the completion of the Kulekhani Project. III. THE BORROWER AND THE BENEFICIARY 3.01 HMG would be the Borrower, and the ED would be responsible for constructing the Project. Upon completion, the facilities would be trans- ferred to the NEC, the beneficiary, which would operate and maintain them. A development credit agreement would be entered into between the Association and HMG. -6- Organization and Management 3.02 NEC is now operating in the Bagmati and Narayani zones. With the construction of 132 kV transmission line from Hetauda to Gandak and the extension of 33 kV transmission system to Butwal, Tansing and Krishnanagar, the Lumbini Zone will be interconnected to the Central system by 1977. HMG is negotiating a second power loan with ADB for the financing of a 132 kV transmission line from Bharatpur to Pokhara scheduled for completion in 1979. The Gandaki Zone will then be interconnected. All these facilities will be turned over to NEC for operation. During negotiations, it was agreed that the Association will be consulted on any proposed changes in the insti- tutional organization of the power sector which relates to NEC. Electricity Department (Executing Agency) 3.03 ED is headed by a Chief Engineer, who reports to the Secretary of the Ministry of Water and Power, He is assisted by a Deputy Chief Engineer who is mainly responsible for operational and administrative matters. In the head office in Kathmandu, there are five sections covering: investiga- tion, design and planning, finance, procurement stores and workshop, and administration. There are also three regional construction, operation and maintenance offices: the Kathmandu (Central) region, the Dhankuta (Eastern) region and the Pokhara-Surkhet (Western) region. The organization chart is shown in Annex 5. ED has 615 technical and 254 administrative staff out of which 60 technical and 14 administrative staff are senior officers. Nepal Electricity Corporation (Beneficiary) 3.04 NEC was established under the Nepal Electricity Corporation Act 1962 as a corporate body, having perpetual succession, and power to acquire and hold property, and to sue and be sued. It has an authorized capital of NRs. 300 million in shares of NR.s. 100 each. By the end of FY 1973/74, 294,488 shares represented paid up capital wholly owned by HMG. NEC has received additional assets valued at approximately NRs. 106 million for shares to be issued to HMG. The authorized share capital will be increased to enable NEC to issue shares to HMG in respect of generation and transmission plant to be transferred in the near future. NEC's powers and duties are set out in Annex 6. 3.05 NEC's Board of Directors has an Executive Chairman and five other members. The Chairman is the General Manager. The members consist of the Chief Engineer (Electricity Department), representatives of the Ministry of Water and Power, the Ministry of Industry and Commerce, the Ministry of Finance, the Kathmandu Town Council. Under the General Manager, there are four executive positions for Planning and Generation, Transmission and Distribution, Administration and Commercial, and Finance and Economic Analysis (see Annex 7). NEC also has a branch office at Hetauda which is responsible for the operations in the Narayani Zone. 3.06 The existing management of 4 managers and 27 engineers most of whom are graduates of Indian Universities is competent. Together with an additional 268 technical staff and 963 others, the total of 1,262 employees is excessive for a utility which has a capacity of only 30 MW and about 56,000 consumers. ED and NEC together own 43.5 MW generating plant and have 2,100 employees, or 48 employees per 1,000 kW of plant. The transfer of Trisuli HE Plant will require NEC to take over additional operating staff which the Government of India, as donor of the plant, had hired and trained. As the number of employees is excessive a ceiling was discussed during negotia- tions. HMG and NEC recognized that the present overall staff is excessive and would endeavor to make use of excessive staff in operating the expand- ing facilities. The problem will be kept under review and followed up during supervision. 3.07 HMG agreed during negotiations to transfer to NEC Trisuli (2nd Stage), Sunkosi and Gandak. These would be transferred as equity. Other plant, constructed with its own funds and with funds provided on concessional terms, would be transferred as debt. Debt would represent the cost of the plant to HMG less any amount NEC had contributed towards its cost. HMG agreed that the Project would be transferred to NEC in two stages upon com- pletion and commissioning of the 1st and 2nd units and that the part of the Project financed with IDA funds would be transferred as debt repayable over 25 years at 8-1/2% interest. The equivalent of the Kuwait Fund loan would be transferred as debt repayable over 25 years at 6%. HMG intends to use the same terms for the balance of the cost of the Project. System Loss 3.08 NEC's system loss is exceptionally high, about 32% of gross genera- tion in 1972/73 and 34% in 1973/74. This is one of the reasons for the high tariff increases required to put NEC on a sound financial basis. The need to reduce system losses was discussed during negotiations. HMG will engage a consultant under the Second ADB Power Loan to study ways and means of doing this. IV. THE PROJECT The Project 4.01 The Project, located about 30 km southwest of Kathmandu, will consist of the following: (a) a 107 m high rockfill dam on the Kulekhani river with a total embankment volume of about 3.5 million m3; (b) an open channel spillway controlled by two radial gates; -8- (c) an intake structure connected to a headrace tunnel of about 2.5 m in diameter and 5.8 km long; (d) a surge tank; (e) a penstock about 1.6 m in average diameter and 1,340 m long; (f) an underground powerhouse equipped with two 30 MW turbo- generating units; (g) a tailrace tunnel of 1 km in length; (h) a switchyard equipped with two 35 MVA power transformers and associated switching and protection equipment; (i) a 66 kV 200 m long double circuit transmission line to connect with the existing line between Kathmandu and Birganj; and (j) extension of the existing substation at Kathmandu with two 35 MVA transformers and switching and protective equipment. (Annex 8 provides project details and Map 2 shows the plan and profile of the Project.) 4.02 The Project will provide 60 MW of dependable peaking capacity and generate 165 GWh of primary energy and 46 GWh of secondary energy annually which would replace use of energy in one form or another equivalent to about 65,000 tons of oil per annum. Cost Estimate 4.03 The following table summarizes the project cost based on 1974 price levels: In millions of NRs.- In millions of US$ % of Foreign Local Total Foreign Local Total Total A. PRELIMINARY WORKS 6.2 3.8 10.0 0.5 0.3 0.8 1.2 B. RESETTLEMENT - 7.5 7.5 - 0.6 0.6 0.9 C. CIVIL WORKS 281.3 56.2 337.5 22.5 4.5 27.0 39.6 D. EQUIPMENT Hydro-mechanical 27.5 3.7 31.2 2.2 0.3 2.5 3.7 Electro-mechanical 70.0 7.5 77.5 5.6 0.6 6.2 9.1 Transmission & Substations 15.0 3.8 18.8 1.2 0.3 1.5 2.2 Sub-total 112.5 15.0 127.5 9.0 1.2 10.2 15.0 E. ENGINEERING SERVICES 33.7 3.3 37.5 2.7 0.3 3.0 4.4 G. GENERAL EXPENSES - 12.5 12.5 - 1.0 1.0 1.5 G. DUTIES AND TAXES - 2.5 2.5 - 0.2 0.2 0.3 H. CONTINGENCIES Physical 36.3 7.4 43.7 2.9 0.6 3.5 5.2 Price 236.3 35.0 271.3 18.9 2.8 21.7 31.9 Sub-total 272.6 42.4 315.0 21.8 3.4 25.2 37.1 TOTAL PROJECT COST 706.3 143.7 850.0 56.5 11.5 68.0 100.0 /1 1 US$ = NRs. 12.50 The physical contingency allowance on civil works of about 11.5% represents about 50% for foundation treatment, 10% for dam and spillway, 20% for under- ground works and 5% for the remainder. On hydro-mechanical and electro- mechanical equipment, the physical contingency allowance averages 3.5%. The price contingencies were derived by applying the following rates of escalation: for civil works 16% in 1975, 14% in 1976, 12Z in 1977-79, and 10% after 1980; for equipment 12% in 1975, 10% in 1976, 8% in 1977-79 and 7% after 1980. This amounts to about 58% of the basic cost plus physical contingencies for civil works and 40.5% for equipment. A detailed cost estimate is given in Annex 9. - 10 - Financing Arrangements 4.04 The Japanese Government has approved in principle a loan, to be made through the Japanese Overseas Economic Cooperation Fund (OECF), of 3 billion Yen (about US$10 million) to finance the foreign exchange cost of electro-mechanical equipment (turbines, generators, cranes, instrumentation and control, etc); associated transmission line and switchyard facilities. The proposed IDA credit of US$26.0 million would finance the foreign exchange cost of civil works of main dam and spillway. The Kuwait Fund loan of KD 5.0 million (about US$17.5 million) would finance the foreign exchange cost of preliminary works, hydro-mechanical equipment (gates, hoists, screens, penstock, valves, etc) and civil works other than main dam and spillway. UNDP's grant of US$3.0 million (US$2.7 million in foreign and US$0.3 million equivalent in local currency) would finance the consulting services. The local cost of approximately US$11.2 million equivalent and any balance of foreign exchange cost not covered by external financing would be financed by HMG. 4.05 The proposed financing arrangements are summarized below: Financing Items to be (Amount (US$ million) Parties Financed Foreign Local Total OECF Electro-mechanical equipment, 10.0 - 10.0 Transmission Line and Switch- yard facilities IDA Civil Works (Main Dam and 26.0 - 26.0 Spillway) Kuwait Preliminary Works, Hydro- 15.9 - 15.9 /1 Fund mechanical Equipment and Civil Works other than Main Dam and Spillway UNDP Consulting Services 2.7 0.3 3.0 HMG Balance 1.9 11.2 13.1 Total 56.5 11.5 68.0 /1 This amount is less than the agreed loan of KD 5.0 million, equivalent to about US$17.5 million. The Kuwait Fund has agreed to retain surplus funds as contingencies. - 11 - 4.06 Effectiveness of the loan agreements between HMMG and OECF and between HMG and the Kuwait Fund is a condition of effectiveness of the proposed credit. The Project document between HMG, UNDP and the Bank for the consulting services was signed on October 31, 1975. Procurement and Disbursement 4.07 Preliminary works and resettlement will be carried out by HMG's own task force, supplemented by local contractors. Civil works to be financed by the proposed credit will be procured in accordance with the Bank's Guidelines on the basis of international competitive bidding while procurement under the Kuwait Fund loan wiLl follow Kuwait Fund procedures. Due to the magnitude and nature of the works, which requires experienced foreign contractor(s), the question of domestic preference for the local contracting industry does not arise. There are opportunities, however, for local subcontractors on such works as access road, construction camp and living quarters. Prequalification will be carried out for all civil works to be financed under the proposed credit and the Kuwait Fund loan. If all of the bidders prequalified for the parts to be financed by IDA are also prequalified for civil works to be financed by the Kuwait Fmnd loan, then bids will be invited for the total works from all prequalified bidders. Procurement guidelines established by OECF will be used for items financed by it; these are on the basis of LDC untied procurement including supply and erection. Disbursements from the proposed credit will be made against 100% of foreign expenditures of civil works for main dam and spillway. Any balance remaining after completion would be cancelled unless there are good reasons for applying the savings to related works. A disbursement schedule is shown in Annex 10. Consulting Services 4.08 The feasibility study was done by NK under technical assistance provided by the Japan International Cooperation Agency. NK has been retained as Consultants for field investigation, detailed design, preparation of specifications and tender documents, procurement and construction supervision of the Project with the Bank acting as the Executing Agency for UNDP. On-the- job training both during the design and construction stages will be provided. Implementation Schedule 4.09 A detailed implementation schedule is shown in Annex 11, which allows about 16 months for phase I work including field investigation, engineering design, preparation of tender documents and tendering and 41 months for construction (phase II). Tenders for civil works will be issued by July 1976 and awarded by the end of 1976. Construction will be started in March 1977 and completed by mid 1980. Tender documents for major equip- ment will be issued by October 1976 and awarded by March 1977. The first unit will be ready for commissioning by end 1979/80 and the second unit about 12-24 months later. This schedule is reasonable. - 12 - Hydrology 4.10 Hydrology is based on a ten-year period of flow record (1963-1972) measured at the damsite and two tributaries. A correlation study was made between the runoff and rainfall which confirmed the reliability of the flow records. The preliminary spillway design flood of 1,300 m3/sec may be on the low side due to the short duration of the flood record as Creager's equation would give a peak discharge of about 2,000 m /sec for a drainage area of 126 sq. km. ED agreed that the adequacy of the spillway capacity will be confirmed by further study during detailed design by the Consultants. 4.11 The annual sediment at the proposed damsite is estimated by NK at about 700 m3/sq. km., which corresponds to a sediment inflow of about 88,000 m3/year. ED agreed that this will be checked by the flow duration and sediment rating curve method based on actual measurement, that debris dams will be considered in the future to intercept the bed load and that provision will be made in the design of the intake structure to allow the plant to be operable even if the silting level should raise higher than originally envisaged. (Further details are provided in Annex 12). Geology 4.12 19 drill holes and seven seismic exploration lines with a total length of 667 m and 1,600 m respectively were made at the damsite and 5 drill holes with a total length of 315 m at the underground powerhouse site. The present project layout has taken the engineering geological conditions into consideration. However, to provide necessary information for detailed design and to enable prospective bidders to prepare realistic tenders, ED agreed to carry out the following investigations with Consultants' assistance: (a) Foundation grouting test at the damsite; (b) Investigation of talus and fractured rock zone on the right abutment of dam by adits; (c) Drilling in the surge tank and under- ground powerhouse area. (Further details are given in Annex 13.) Ecology 4.13 The proposed Kulekhani reservoir will inundate a total area of about 220 ha, of which 150 ha is cultivated. There are no noteworthy infrastructure, mineral or forestry resources, nor subjects of archaeological interest in the reservoir area. According to a recent survey conducted by ED, there are about 235 houses in the reservoir area and 1200 inhabitants to be resettled. As the area of land being cultivated by each family is small - 13 - and living conditions poor, no resettlement problems are foreseen. A sum of US$0.6 million or about US$500 per inhabitant has been included in the cost estimate. To ensure the satisfactory execution of resettlement, it will be essential that the Ministry of Water and Power, in cooperation with other relevant government authorities, prepare a detailed resettlement plan by December 31, 1976. During negotiations assurances were obtained that the detailed plan will be submitted to the Association no later than March 31, 1977. 4.14 A field survey of surface erosion conditions in the Kulekhani basin was made by Japanese experts in 1963. According to the report, only moderate erosion of mountain slopes in the catchment area of Kulekhani can be expected. This was confirmed during appraisal. HMG has enforced a forestry protection program in the watershed area and vegetation cover has been improving. 4.15 Malaria is unknown in the watershed area and people are generally healthy. There are no irrigation or water supply facilities in the down- stream reach of the Kulekhani river. The diversion of water to the Rapti river basin, an adjacent watershed, will not affect the population living downstream of the Kulekhani damsite. Nevertheless the Consultants will examine the environmental, health and ecological consequences of the Project further during field investigations which must be completed prior to final design. V. PROJECT JUSTIFICATION The Power Market 5.01 At the end of 1963/64, NEC served a maximum demand of 3.5 MW and generated 13.7 GWh. Ten years later, in 1973/74, maximum demand had in- creased to 25.5 MW and generation to 96.7 GWh. In the ten-year period there was a sevenfold increase in power and energy requirements. Average annual growth rates were about 22% both for maximum demand and energy generation as shown in Annex 14. 5.02 The load forecast for the next ten years is based on the expected increase in both of the number of domestic consumers and in demand per con- sumer for the residential load, on known agricultural and industrial develop- ments and the Government's Fifth five-year plan for the industrial load, and on the number of tourists expected in the coming years for the commercial load. The interconnection of the Western Zone after completion of the 132 kV Gandak-Hetauda transmission line and the 33 kV transmission system by 1976/77 has also been taken into consideration. It is forecast that the maximum de- mand for the combined system would increase from 30.4 MW in 1974/75 to 93.5 MW in 1983/84, and energy requirement from 117.3 GWh in 1974/75 to 426.0 GWh in 1983/84. The average annual rate of growth would be about 14%, gradually levelling off to 9.3% in 1983/84. Annex 15 demonstrates the operating statis- tics of NEC in the past years, Annex 16 gives the load forecast for the com- bined system and Annex 17 shows the system capability to meet the load - 14 - requirements in accordance with the power development program outlined in paragraph 2.19 and shown in Annex 4. This forecast is adequate as a basis for investment and revenue projections. 5.03 Peaking capability in the dry seasons from 1975/76 through 1978/79 will not meet system demand and load shedding will result (Annexes 4 and 17). Even if a further 10% reduction in peak demand results from tariff increases, Kulekhani's first unit would still be needed by the system by 1980. The Project is therefore a key element in NEC's system expansion program and HMG's Fifth five-year plan to provide adequate power supply to industrial, commercial as well as agricultural development in the Central and Western Zones. The Chitwan Valley Irrigation Project, presently under construction, alone would utilize about 7,000 KW or 12% of the Project's total generating capacity. The Least Cost Solution 5.04 The existing hydro power plants in the Central System (31.6 MW installed) are either run-of-river or pondage plants without any seasonal regulation. Therefore, dependable peaking capacity during the dry season, November through May, is reduced to only 26.6 MW. The operation of the system would be greatly improved after the completion of the Kulekhani Project. The Project will contribute ultimately 60 MW in dependable peak- ing capacity, 165 GWh in primary energy and 46 GWh in secondary energy annually. The second unit will be mainly a peaking unit. 5.05 Since no other hydro schemes have been sufficiently investigated to replace Kulekhani for completion by 1980, the only possible and real- istic alternative is a thermal development. Five alternatives consisting of different types of thermal units were compared with Kulekhani. On the main assumptions, the equalizing discount rates were found to range from 12.9% to 18.5% indicating that Kulekhani would be the least cost solution for discount rates up to at least 12.9% (Annex 18). 5.06 The sensitivity and probability analysis between Kulekhani and the best thermal alternative (1 - 30 MW coal-fired unit plus 2 - 15 MW gas turbines) were tested for variations in capital costs and fuel costs. As shown in Annex 18, the range of equalizing discount rate with 95% probability varies between 11.2% and 14.7Z. 5.07 Two additional power stations, Kulekhani No. 2 (35 MW) and Kulekhani No. 3 (17 MW), could be constructed downstream of the Rapti river, utilizing the regulated flow from the Kulekhani reservoir. Other benefits such as downstream irrigation (about 10,000 hectares along the valley of Hetauda), fishery and recreation would result from the Kulekhani reservoir. These benefits would be much greater than the losses resulting from inundating the reservoir area. - 15 - Return on Investment 5.08 Based on the present tariffs, the average revenue obtained from domestic sales is about USJ1.9 per Kwh. Revenue from energy exported to India is based on the existing agreement of power exchange between India and Nepal at US41.5 per Kwh. As shown in Annex 19 the internal rate of return of the Project, or the discount rate at which the present worth of costs attributed to the project is equal to that of the benefits from it over its life, is about 6% in constant prices. This confirms that the present tariffs are low. Incremental system cost of energy, based on the power development program from 1977 through 1985 including three hydro- electric projects and associated transmission and distribution, is esti- mated to be USO3.8 (Annex 20). The projected tariff increase, expected to reach USi3.5 per Kwh in real terms by 1980/81 will mean that it will approach gradually to the incremental system cost and be able to make an internal rate of return on the Project of about 10.7% in constant prices. VI. FINANCIAL ASPECTS 6.01 A large part of the generating plant in the Kathmandu Valley was donated to HMG by India, China, Russia and the USA. Part of this plant has been transferred to NEC as equity. As a result, NEC has no debt and despite its low tariffs and high system losses, its annual cash flow has financed moderate distribution expansion. Past and Present Earnings 6.02 In 1971 NEC's domestic tariff for Kathmandu Valley was reduced from 35 paise to 20 paise per kWh. In the following three years to FY 1973/74 its rates of return on average net fixed assets in operation were 0.3%, 1.0% and 0.3% respectively. Sunkosi HE Plant (10 MW), donated by China and oper- ated by HMG since April 1972 has supplied energy to NEC without charge because HMG has not determined an appropriate rate for the supply. NEC did not con- sider this a deferred liability, hence the increase in the return to 1% in FY 1972/73. Despite the continuing "free supply" of energy, NEC's rate of return dropped again to 0.3% in FY 1973/74. This was due to a substantial pay raise to employees and a 50% increase in royalty from 5 paise to 7.5 paise per kWh sold. In FY 1974/75 NEC had a deficit of NRs. 1.77 million corresponding to a negative rate of return of 1.4%. 6.03 During negotiations, HMG agreed to continue to provide NEC with energy generated by Sunkosi HE Plant up to the date of its transfer to NEC. HMG indicated its intention to treat as an equity investment the cost of energy supplied by Sunkosi during the period from FY 1971/72 to FY 1974/75 assessed to NR 7 million, subject to deduction of unpaid bills amounting to NR 3.8 million for electricity supplied by NEC to various government departments up to July 1975 (para 6.19). -.16 - Present Financial Position 6.04 NEC's financial position at July 15, 1975 (the end of FY 1974/75) shows no debt, a current ratio of 2.7, an operating ratio of 108% due to failure to raise tariffs in the face of rising costs, a cash flow just sufficient to finance modest distribution expansion, and no call on earnings to finance generation or transmission plant. Tariffs 6.05 The present tariff schedule has seven categories: domestic, transport industry, manufacturing and processing industry, commercial and service industry, irrigation and water supply, street lighting, and temporary supply. In addition, supplies are exported to India under a power exchange agreement which provides for Nepal importing 5.8 MW from India and exporting 5 MW to it at a common price of US41.5 per kWh. 6.06 NEC operates a two part tariff (Annex 21) consisting of a demand (kW) charge and an energy (kWh) charge for industrial and commercial consuxmrs. Its present tariffs, averaging 23.9 paise per kWh (USd1.9) are low, but in the past, because it has no debt, were sufficient after meeting operating expenses to meet increased working capital requirements and finance moderate distribution system expansion. This low average tariff compares to USJ2.4 per kwh in Andhra Pradesh State in India in FY 1973/74. Recently, Bank staff examined the tariff levels and structure in Andhra Pradesh and found that marginal cost based tariffs should be about US45 per kWh or double the existing average. The incremental cost of energy in Nepal is estimated at USU3.8 per kWh on a constant price basis excluding taxes (para 5.08). Future Earnings 6.07 One objective of the proposed credit would be to improve NEC's financial performance. Internally generated funds after meeting operation, maintenance and management expenses, (including taxes) should be sufficient to cover debt service, reasonable increases in working capital, dividends (if any), and a reasonable proportion of the cost of construction. A rate of return of 8% (net income before interest expressed as a percentage of average net fixed assets in operation) would accomplish this. However, as illustrated in Annex 22.3, extremely high and unrealistic tariff increases would be required to achieve this return unless tax and royalty were waived. This was discussed with HMG during the summer of 1975 and EMG decided to exempt NEC from royalty, but not tax. In view of this, it became clear that a conventional 8% return would be inappropriate in the short run. There- fore, during negotiations it was agreed that, as a condition of effectiveness, tariffs would be increased to produce a 2-1/2% return for FY-1975/76 (with the return calculated as if the increase were effective for the entire year). This will require about a 74% increase in the average price per Kwh sold, bringing this to about US43.3 per kWh. Agreement was also reached that further tariff actions would be taken to reach a 4% return for FY-1977/78, rising to 6% by FY-1980/81. After this target is reached the situation will be jointly reviewed by HMG and the Association with a view to reaching 8% as early as possible thereafter. - 17 - 6.08 Annexes 22.1 and 22.2 assume that surplus power from Kulekhani would be exported to India at existing low rates of approximately USO1.5 per kWh, until the load within Nepal builds up to fully utilize Kulekhani's power. In the three years FY 1980/81 to FY 1982/83, the revenue from this source is estimated at approximately 13% of NEC's total revenue from sales. These assumed prices are substantially lower than the prices in India across the border and it is reasonable to expect that there will be no difficulty in exporting the power as assumed. A formal undertaking from the Indian states adjoining Nepal for the purchase of this power is not proposed as it would be unrealistic to expect a formal agreement for short term power supply, five or six years in advance. 6.09 Tariff increases are not expected to affect demand significantly. If however, demand were reduced by about 10%, NEC's diesel generation could be discontinued with a resultant savings on imported fuel. The savings would more than offset the reduction in revenue in FY 1976/77 and FY78/79, although they would be slightly less in FY 1977/78 and FY 1979/80. In any event, NEC's diesel operation would be discontinued when Kulekhani HE Plant begins operations in 1980, and tariff increases slightly higher than forecasts would be necessary to satisfy the 6% return covenant. 6.10 In connection with a December 1972 loan by ADB, HMG agreed that NEC would achieve a rate of return of 8% on its "total assets after covering operational expenses, charges and interest payment" not later than December 31, 1977. As no substantial adjustment to the tariff schedule will be made until about March 1976, this return is unlikely to be achieved. ADB has been advised of this. Proposed Financing Plan 6.11 The following statement consolidates NEC's sources and application of funds (Annex 23.1). The transfer to NEC of the Gandak Transmission and Kulekhani HE Project on their commissioning is assumed. - 18 - FY 1975/76 - FY 1979/80 % of NR million US$ million Total Internal Cash Generation 142.45 11.4 16 Less Debt Service (9.21) (0.7) (1) Less Working Capital Increase (15.90) (1.3) (2) Net Cash Generation 117.34 9.4 13 Consumer's Contributions 2.50 0.2 _ Internal Funds 119.84 9.6 13 Debt H1MG Loan (re Gandak) 39.50 3.1 4 HMG Loan (re Kulekhani) 417.00 33.4 47 IDA Credit (onlent) 325.00 26.0 36 Total Funds 901.34 72.1 100 Construction Distribution 35.34 2.8 4 Projects Transferred Gandak Transmission 56.00 4.5 6 Kulekhani HE Project 810.00 64.8 90 Total Plant 901.34 72.1 100 6.12 Internal cash generation is based on sales forecasts considered adequate for investment planning (para. 5.02) and on tariff increases to achieve target rates of return discussed in para. 6.07. Although NEC is not presently responsible for construction of its generation and trans- mission plant, it should nevertheless be expected to finance a reasonable proportion of the cost of such plant constructed by others. NEC should advance reasonable funds each year to HMG towards the cost of Gandak Trans- mission and Kulekhani HE Projects and other plant being built by H1MG in its behalf. These advances would reduce the subsequent debt when the completed plants are eventually transferred. During negotiation discussions, H1MG concurred in principle that NEC would make such advances each year from its surplus funds. 6.13 NEC's internally generated funds would finance 13% of construction cost (4% for distribution and 9% as advance toward the cost of the above projects). Debt would finance 87% of which the Association credit would represent 36%. 6.14 Revenue is projected assuming rates of return targets for FY 1975/76 through FY 1982/83 will be met (para. 6.07). This would result in: (a) operating ratios of 93% in FY 1975/76 reducing to 77% in FY - 19 - 1979/80 before falling to 61% by FY 1982/83; and (b) provided the in- vestment program remains as currently forecast, a cash flow to finance 13% of construction expenditures (excluding donated plant) over the period FY 1975/76 to FY 1979/80. Future Finances 6.15 Condensed balance sheets at July 15, 1974 through July 1983 (Annex 24) show that NEC's gross plant value would increase eleven-fold from NRs. 148 million (US$12 million) in July 1974 to NRs. 1,648 million (US$132 million) by July 1983. 6.16 Assuming donated plant is transferred as equity, and additional plant as loan, NEC's debt would be NRs. 780 million (US$62 million) after transfer of the first 30 MW unit of the Kulekhani HE Project at the end of FY 1979/80. Debt/Equity ratios would be 53/47 at the end of FY 1979/80 reducing to 48/52 at the end of FY 1982/83. Internal cash generation would cover debt service by over 1.8 times in each of the FY 1980/81 through FY 1982/83. 6.17 The current ratio (current assets/current liabilities) would increase from 2.4 in FY 1973/74 to 7.1 by FY 1982/83. Accounts Receivable 6.18 At July 15, 1974, consumer accounts receivable amounted to NRs. 5.28 million, of which NRs. 3.19 million was owed by HMG departments. The following table shows the age of the accounts: FY73/74 FY72/73 FY71/72 FY70/71 Total .DMG 0.50 0.40 0.10 2.19 3.19 Other Consumers 2.09 --------no details-------- 2.09 Total 2.59 0_40 0.10 2.19 5.28 Other consumer receivables FY 1973/74 represent about seven weeks billings but current collections show some improvement. However, collections from HMG are unsatisfactory. 6.19 During negotiations HMG agreed to settle its arrears and also agreed that its departments would pay their current bills promptly. Settle- ment of the unpaid bills would be made by deduction from NEC's liability for energy supplied by Sunkosi HE plant (para. 6.03). Dividends 6.20 Agreement was reached during negotiations that NEC would not declare dividends on HMG's equity for any fiscal year until the Kulekhani Project is completed. - 20 - Audit 6.21 NEC's books are audited by the Auditor General of Nepal, who is appointed by His Majesty. The Auditor General's powers and duties are contained in the Constitution. He normally employs a professionally qual- ified independent auditor to assist him with the NEC audit and this arrange- ment is satisfactory. 6.22 NEC's financial organization requires strengthening by the appoint- ment of an internal auditor, accountable directly to the Chairman, to verify cash balances, inventories, assets and liabilities, and to ensure that the systems of accounting are efficient. This was agreed during negotiations. VII. AGREEMENTS REACHED AND RECOMMENDATION 7.01 During negotiations agreement was reached on the following points and appropriate covenants included in the agreement for the proposed credit: (a) institutional organization changes (para. 3.02); (b) transfer of Kulekhani and other plants to NEC (para. 3.07); gc) resettlement plan (para. 4.13); (d) tariff increase (para. 6.07); (e) settlement of arrears (para. 6.19); (f) dividends (para. 6.20); (g) appointment of internal auditor (para. 6.22). 7.02 Effectiveness of the loan agreements between HMG and OECF and between HMG and the Kuwait Fund and implementation of tariff increases of about 74% in FY1975/76 are conditions of effectiveness of the proposed credit (paras. 4.06 and 6.07). 7.03 The Project is suitable for a Development Credit of US$26.0 mil- lion equivalent. AlrEX 1 NIFAL GENRATING FACILITIES BY TYE OF SERVICE Installed Capacity (kW) Power Utilities Hteam Diesel Total E.D. 11,290 _ 2,470 13,760 N.E.C. 21.,540 8,260 29,800 E.E.C. - - 1,634 L,634 B.P.C 550 _ 225 775 Sub-total 33,380 - 12,589 45,969 Captive Industrial Plant 30 3,810 4,392 8,232 TOTAL 33,410 3,B10 l6,981 5k,201 Source: Electricity Department, Ministry of Water & Power. ANNEX 2 NEPAL PRINCIPAL HYDRO POWER STATIONS Station Name of Type Installed Unit Capacity Year of Utility Cpacity (kW) Commissioning (kW) & No. of Units Central Development Zone 1. Fharping NEC Storage 500 250 x 2 1911 2. Sundarijal NEC Storage 640 320 x 2 1934 3. Panauti NEC Run-of- 2,400 800 x 3 1963/64 river 4. Trisuli NEC Run-of- 18,000 3,000 x 6 1969/70 river 3,000 x I (stand-by) 5. SunkosiL/ ED Run-of- 10,050 3,350 x 3 1972/73 river 6. Godawari Private Run-of- 30 river Sub-total 31,620 Other Development Zones 7. Pokhara ED Storage 1,000 250 x 4 1968/69 (Western Zone) 8. Tinau BPC Run-of- 50 50 x 1 1969 (western Zone) ri-ver 500 500 x 1 1974 9. Dhankuta ED Run-of- 240 12u x 2 1973 (Eastern Zone) Sub-total 1,790 TOTAL 33,41o0 1/ Sunkosi is presently bein, operated by ED. It will be turned over to NEC no later than July 15, 1977. Source: Electricit- De)artmento MTTinistry oU .Jaer ancl Power. ANNEX 3 NEPAL PRINCIPAL THERMAL POWER STATIONS Location Owner Type Installed Unit Capacity (kW) Capacity & No. of Units (kW) Central Development Zone 1. Mahendra NQEC Diesel 1,700 425 x 4 2. Patan NEC Diesel 1,490 1,490 x 1 3. Hetauda NEC Diesel 4,470 1,490 x 3 4. Bharatpur NEC Diesel 600 250 x 2 100 x 1 5. Birganj Birganj Steam 1,6o0 1,600 x 1 Sugar Mill Diesel 272 272 x 1 6. Janalpur Janakpur Diesel 572 256 x 2 Cigarette 60 x 1 Factory 7. Janakpur ED Diesel 750 250 x 3 Sub-total 11,454 Eastern Development Zone 8. Biratnagar EEC Diesel 1,434 1,023 x 1 411 x 1 9. Biratnagar Biratnagar Steam 1,400 1,400 x 1 Jute Mill Diesel 850 400 x 1 450 x 1 10. Biratnagar Raghupati Diesel 337 337 x 1 Jute Mill 11. Dube Dube Straw Diesel 356 356 X 1 Board Co. 12. Dharan EEC Diesel 200 130 x 2 13. Dharan British Diesel 1,200 400 x 3 Military Camp Sub-total 5,777 Western Development Zone 14. Bhairahawa Mahendra Steam 600 600 x 1 Sugar Mill 15. Bhairahawa ED Diesel 500 250 x 2 16. Butwa' BPC Diesel 225 17. Tansing ED Diesel 305 140 x 2 25 x 1 1a. NepaTh,un, ED Diesel 500 250 x 2 1?. Krishnanagar ) Diesel 135 140 x 1 25 x 1 Sub- tota! 2,295 NEPAL THE CENTRAL SYSTEM POWER DEVELOPMENT PROGRAM 150 .,___._ 140 - E 130 - _ X 7 _B, ytMaximum Peaking Capacity 120 rN -_ - _ E 0i 110 ~~~~~~~~~~~~~~~~~~~~~~~~Z \ vailable Peaking Capacity 4 10 in' l rySeason < 80~~~~~~~~~~~~~~~ 902 go System Peak Load 0 L -J 70 < ~- 60_ ___ _ _ _ LU U) 50- 30 20 10 1973/74 1974/75 1975/75 1976177 1977/78 1978/79 1979/80 1980/81 1981/82 1982/83 18/41984/85 FISCAL YEAR World Bank-9546(R) NEPAL ELECTRICITY DEPARTMENT ORGANIZATION CHART CHIEF ENGINEER DEPUTY CHIEF ENGINEER PROCUREMENT CONSTRUCTION, CONSTRUCTION, CONSTRUCTION, ADMI1NISTRATION 2 FINANCE 1 STORES & I INVESTIGATION DESIGN & 0 & M SECTION 0 & M SECTION 0 & M SECTION SECTION 1 SECTION WORKSHOP SECTION SECTION (KATHMAN) (DHANK (POKHARA & SECTION ~ ~ ~ ~ ~ ~ ~ SETINREGION) REGION) SURKH-ET REGION) PERSONNEL ACOU|SCENTRAL PLANNING & SUNKOSI KOSI & SAGARMATA LUMBINI ZONAL ADMINISTRATION SUB-SECTION PROCUREMENT SUBSECTION BUETING HYDRO-ELECTRIC ZONAL SUB-SECTION SUB-SECTION SUB-ECIN SUB SECTION SUB-SECION PROJECT SUB-SECTION GENERAL CENTRAL ELECTRICAL TRAYUNI MECHIGANAKAL- ADMINISTRATION EN WORKSHOP DESIGN ZONALL ZONAL RU-EVEINU SUB-SECTIONOAL IO SUB-SECTION SUS SUB-SECTION SUB-SECTION SUSUB-SECTION SUB-SECTION INTERNAL ACCOUNTING CIVIL NARAYVANI MNALETi MANAGEMENT CLEARING SG OA SUB-SECTION SUB-SECTION SU-ECTION SUB-SECTIONSU-ETO BHERI-RAPTI ZONAL SUB-SECTION Source Electrmc.ty Departmenl.t M-nyotrf o' Water and Power World Bank-B849 ANNEX 6 RESUME OF NEPAL ELECTRICITY CORPORATION ACT Published in Nepal Gasette on July 25 1962 This act establishes the Nepal Electricity Corporation as: A permanents mUcessive and self-governing corporate body, with ability to receive, possess and transfer movable and imovable property, to sue and be sued. Authorized capital is NR 300,000,000 in 3,000,00 shares of NR 100 each, on sale to public. The Corporation has limited liability; can issue bonds and deberituLres, can accept loans and subsidy grants in cash or kind. Dutiest Production and distribution of electricity in a secure, efficient, orlerly, economical and proper way in areas approved by H.M.G. Rights: In addition t.o the right to undertake the work of production and distribution of' electricity: to make, repair and prz)au:e electric tools and parts for itself and for others; to determine or- charges and other dues of electricity services; to give loans with adequate security to trustworthy people; to rent, sell or make other arrangements for the property of the corporation; to provide pension, gratuity or provident funds for officers and employees; to publicize its services and to protnote public confidence; the corporation can spend capital for buying immovable property or machines or any other thing costing more than NR 1,000,000 only with the permission of H M.G. NEPAL ELECTRICITY CORPORATION ORGANIZATION CHART BOARD OF DIRECTORS EXECUTIVE CHAIRMAN GENERAL MANAGER MANAGER MANAGER MANAGER MANAGER ADMINISTRATION FINANCE PLANNING TRANSMISSION NARAYANIZONE & & & & RESIDENT ENGINEER COMMERCIAL ECONOMIC ANALYSIS GENERATION DISTRIBUTION ADMINISTRATIVE REVENUE GENERATION & T & D ASSISTANT OFFICER OFFICER SYSTEM CONTROL CONSTRUCTION ADMINISTRATIVE ______ ) ~~~~~~~ ~ ~~~~~CHIEF JCHIEF OFFICER PROCUREMENT lClUr PLANNING & T & D lNl & STORES ACCOUNTS RESEARCH MAINTENANCE ACCSENIORU OFFICER OFFICER CHIEF CHIEF ACCOUNTANT COMMERCIAL 1 INTERNAL l TRISULI OFFICER R AUDITOR POWER STATION Source- Nepal Electricity Corporation World Bank-848 ANNEX 8 Page 1 NEPAL KULEKHANI HYDROELECTRIC PROJECT Project Description General 1. The Kulekhani river originates in the Mahabarat mountain range about 5 km west of Palung and 30 km southwest of Kathmandu. It flows generally in an east-southeast direction and joins the Bagmati river about 20 km south-southwest of Kathmandu. 2. The catchment area above the damaite is about 126 sq. km. In the upstream reach, the valley is rather open and the slopes are generally stable with good vegetation cover. From the damaite to Kitini, the river flows through a gorge section; the valley is narrow and deep due to down- ward erosion. The Dam 3. The dam to be built will be a rockfill structure with an inclined impervious core, about 107 m in height and with a crest length of about 420 m. The crest elevation is 1,534 m which will provide a free board of 4 m above the normal full water level of 1530 m. The total embankment of the dam has an estimated volume ofabout 3.5 million m3, of which 2.6 mil- lion m3 is rockfill, 0.4 million m3, filter zone and 0.5 million m , imper- vious core. 4. According to the results of seismic exploration and test drilling, the rock foundation on the right abutment underneath the talus deposit is intensively fractured. The thickness of the fractured rock zone (20 m - 45 m) decreases toward upstream. The only conceivable type of dam at the site is a fill-type dam. As sufficient granite is available in the vicinity of the dam and earth material is limited, a rockfill dam has been chosen. The inclined core type is adopted because it requires less excavation than the center core type to set the foundation of the core portion on the firm rock. The dam will have an upstream slope of 1:2.5 and downstream slope of 1:1.7. Spillway 5. The spillway will be located on the left abutment. It will be an open channel chute type structure with a flip bucket provided at the lower end. Two radial gates 11 m high and 9 m wide will be installed to control the discharge. The spillway is presently dimensioned to pass a flood of ANNEX 8 Page 2 3 1300 m /sec, but this will be checked in the detailed design stage through the study of maximum probable flood by the unit hydrograph method and through flood-routing of the reservoir. Intake Structure 6. The intake will be located on the right bank about 200 m upstream of the dam. It will have a bellmouth intake structure equipped with trash- rack, stop-log groove and a roller gate. The entrance sill will be set at El. 1471 m. In view of the difficulty in estimating reservoir sedimenta- tion, provision will be made so that the plant could still be operable even if sedimentation would raise higher than the expected deposit level. Headrace Tunnel 7. The pressure headrace tunnel, about 5.8 km in length, will be of circular cross section with an inside diameter of 2.5 m, about the practical minimum size for effective construction. It will be concrete-lined. No problem is expected during construction with the exception of the upstream 600 m and a downstream portion near the surge tank where the tunnel may cross a fault; heavy support may be required. Surge Tank 8. The surge tank will be a chamber type with upper, lower and middle chambers and a surge shaft. The upper chamber will be a circular tank and the lower chamber, two circular tunnels. The surge shaft will have an in- side diameter of 2.0 m and be about 74 m high. Penstock 9. The total length of the penstock will be 1,335 m, of which the upper and lower portions of 170 m and 255 m respectively will be in tunnels; the middle portion of 910 m will be on grade. The inside diameter of the pipe will decrease gradually from 1.9 m at the upper end to 1.25 m at the lower end. The lower penstock tunnel will also be used as the cable duct and the ventilation shaft for the underground powerhouse. Powerhouse and Switchyard 10. The underground powerhouse is designed to house 2 units of 30 MW each. It will be 43 m long, 14 m wide and 26.2 m high, consisting of main machine room, control room, repair workshop, storeroom and station service units. The inlet valve will be located in the main machine room for ease in erection and maintenance. 11. The switchyard, located on a terrace near the entrance of the lower penstock tunnel, will have the station control room so that the power station will normally be operated from outdoors. ANNEX 8 Page 3 Generating Equipment 12. The turbine will be of the vertical-shaft pelton type with four jets, rated at 41,035 hp (30,600 kW) under a head of 550 m and a discharge of 6.55 m3/sec. The rated speed will be 600 rpm. The runner center will be set at 916 m. 13. The generator will be an 11 kV, 3-phase vertical-shaft revolving- field type, rated at 35 MVA. 14. The main transformer will be forced oil and forced air-cooled type rated at 35 MVA. The high voltage windings will provide 66 kV and 132 kV terminals. It will be installed in the outdoor switchyard. Transmission Line and Substation 15. The existing 66 kV double circuit transmission line between Kathmandu and Birganj via Hetauda will be utilized to transmit Kulekhani output. The outdoor switchyard will be connected to the existing line by a 200 m long branch. 16. Two 35 MVA transformers will be added at the existing substation at Kathmandu consistent with the installation of generating units. Tailrace Tunnel 17. The tailrace outlet will be located at the left bank of the Mandu river about 500 m upstream from its confluence with the Rapti river. A tailrace tunnel about 1.0 km in length will be constructed between the underground power station and the outlet. Tributary Diversion 18. A tributary intake will be constructed to divert the flow of Sim river from a catchment area of about 7 sq. km. It will consist of an intake weir, an inlet, a desilting basin and a vertical shaft into the headrace tunnel. Design will allow free air passage. 19. The Chakhel river, another tributary of the Kulekhani river with a catchment area of 23 sq. km., will be diverted to the Kulekhani reservoir through a connecting tunnel, about 2 km in length. The tunnel will be free flow, 1.8 m in height and in width. Schedule of Implementation 20. The Implementation Schedule is outlined in Annex 11. 1975 is the year for the appointment of consultants and the commencement of detailed investi- gation and construction of the access road to the damsite. Engineering design and preparation of tender documents for civil works will be started in ANNEX 8 Page 4 January 1976. Tender documents will be issued by July 1976 and contract awarded before the end of 1976. Excavation of diversion tunnel will be commenced by March 1977 which will allow about 39 months to complete the main dam. Excavation of headrace tunnel, tailrace tunnel and the access tunnel leading to the underground powerhouse should be started about the same time as the diversion tunnel. About 3 years will be required for the headrace tunnel including excavation, concrete lining and grouting. Excava- tion of the underground powerhouse will be started in late 1977 and install- ation of the electromechanical equipment by mid 1979. Tenders for hydro- mechanical and electro-mechanical equipment should be issued in September/ October 1976 and contracts awarded in early1977. The first unit is scheduled to be commissioned by end 1979/80 and the second unit by end 1981/82 or possibly at an earlier date with a view to providing adequate system reserve capacity and to save project investment as a whole, if financing could be arranged. Basic Data 21. The following table summarizes the principal features of the project: (1) Water Sources Runoff Catchment Area Annual total Mean Basin (km2) (m3) (m3/sec) Kulekhani 126 122.9 x 106 3.90 Chakhel 23 22.4 x 106 0.71 Sim 7 11.8 x 106 0.37 156 157.1 x 106 4.98 (2) Reservoir and Dam (a) Reservoir High water level: EL. 1,530 m Low water level: EL. 1,476 m Drawdown: 54 m Surface area: 2.2 km Gross storage capacity: 85,300,000 m3 3 Effective storage capacity: 73,300,000 in ANNEX 8 Page 5 (b) Dam Type: Rockfill with inclined core Crest elevation: EL. 1,534 m Dam height: 107 m Crest length: 420 m Embankment volume: 3,500,000 m3 Upstream slope: 1:2.5 in average Downstream slope: 1:1.7 in average (c) Spillway Type: Open chute with flip bucket Gate: Radial gate, 9 m wide x 11 m high x 2 nos. Flow capacity: 1,300 m3/sec at reservoir high water level (3) Power Plant (a) Intake Type: Inclined intake Gate: Roller gate, 3 m wide x 5 m high (b) Headrace tunnel Type: Circular section Length: 5,830 m Diameter: 2.5 m (c) Surge tank Type: Chamber type Diameter: 2 m in surge shaft Height: 89.5 m ANNEX 8 Page 6 (d) Penstock Diameter: 1.6 m (mean) Length: Open portion: 910 m Underground portion: 425 m (e) Power House Type: Underground type (Floor 14 m x 43 m, 26.2 m high) (f) Tailrace tunnel Type: Horse-shoe section Length: 1,000 m Dimension: 2.6 m (height) x 3.3 m (width) (g) Generating equipment (i) Turbine Type: Vertical pelton, single runner-4 jets Elevation of runner center: EL. 916 m Gross head: 614 m to 560 m Effective head: 549.9 m (rated) Maximum discharge: 6.55 m /sec Rated Capacity: 2 x 41,035 hp Revolution: 600 rpm (ii) Generator Type: 3-phase vertical shaft synchronous alternator Rated Capacity: 2 x 35,000 kVa Voltage: 11 kV ANNEX 8 Page 7 Cycle: 50 Hz Power factor: 0.85 (iii) Main transformer Type: Oil immersed natural-cooling outdoor Voltage: 10.5 kV/63-66-69 kV Capacity: 2 x 35,000 kVa (4) Transmission line and substation (a) Transmisston line (extension of 200 m long, to connect with the existing line between Kathmandu and Birganj) Voltage: 66 kV double circuit line Conductor: 154.3 mm2 (b) Existing substation in Kathmandu Capacity to be added: 2 x 35,000 kVa NEPAL KULEKHANI HYDROELECTRIE PROJECT COST ESTIMATE In Millions of NRs. In Millions of US$ % of Foreign Local Total Foreign Local Total Total A. PRELIMINARY WORKS 6.2 3.8 10.0 0.5 0.3 0.8 1.2 B. RESETTLEMENT - 7.5 7.5 - 0.6 0.6 0.9 C. CIVIL WORKS Diversion Tunnels and Coffer Dams 20.0 5.0 25.0 1.6 0.4 2.0 2.9 Main Dam 160.0 23.7 183.7 12.8 1.9 14.7 21.6 .Spil lway 23.7 3.8 27.5 1.9 0.3 2.2 3.2 Intake 2.5 - 2.5 0.2 - 0.2 0.3 Headrace Tunnel 28.8 8.7 37.5 2.3 0.7 3.0 4.4 Tributary Diversion 10.0 2.5 12.5 0.8 0.2 1.0 1.5 Surge Tank 2.5 - 2.5 0.2 - 0.2 0.3 Penstock 10.0 3.8 13.8 0.8 0.3 1.1 1.6 Powerhouse and Switchyard 18.8 6.2 25.0 1.5 0.5 2.0 2.9 Tailrace 5.0 2.5 7.5 0.4 0.2 0.6 0.9 TOTAL CIVIL WORKS 281.3 56.2 337.5 22.5 4.5 27.0 39.6 D. HYDRO-MECHANICAL EQUIPMENT Gates, Valves and Screens 10.0 1.2 11.2 0.8 0.1 0.9 1.3 Penstock 17.5 2.5 20.0 1.4 0.2 1.6 2.4 TOTAL HYDRO-MECHANICAL EQUIPMENT 27.5 3.7 31.2 2.2 0.3 2.5 3.7 E. ELECTRO-MECHANICAL EQUIPMENT 70.0 7.5 77.5 5.6 0.6 6.2 9.1 F. TRANSMISSION AND SUBSTATION 15.0 3.8 18.8 1.2 0.3 1.5 2.2 G. ENGINEERING SERVICES 33.7 3.8 37.5 2.7 0.3 3.0 4.4 H. GENERAL EXPENSES - 12.5 12.5 - 1.0 1.0 1.5 I. IMPORT DUTY & TAX - 2.5 2.5 - 0.2 0.2 0.3 J. CONTINGENCIES Physical Civil Works 32.5 6.2 38.7 2.6 0.5 3.1 4.6 Equipment 3.8 1.2 5.0 0.3 0.1 0.4 0.6 Price Civil Works 187.5 30.0 217.5 15.0 2.4 17.4 25.6 Enuipment 48.8 5.0 53,8 3.9 0.4 4.3 6.3 TOTAL CONTINGENCIES 272.6 42.4 315.0 21.8 3.4 25.2 37.1 K. TOTAL PROJECT 706.3 143.7 850.0 56.5 11.5 68.0 100.0 Kovember 1975 ANNEX 10 NEPAL KULEKHANI HYDROELECTRIC PROJECT Disbursenent Schedule for Proposed IDA Credit Cumulative Disbursement Fiscal Year and Quarter at end of Quarter (Thousands of US$) 1977 March 31, 1977 3,300 June 30, 1977 3,700 1978 September 30, 1977 4,300 December 31, 1977 5,300 March 31, 1978 6,300 June 30, 1978 7,300 1979 September 30, 1978 8,300 December 31, 1978 9,800 March 31, 1979 12,300 June 30, 1979 15,300 1980 September 30, 1979 17,500 December 31, 1979 19,,500 March 31, 1980 21,500 June 30, 1980 23,509 1981 September 30, 1980 25 ,000 December 31, 1980 26,000 NEPAL KULEKHANI HYDROELECTRIC PROJECT SCHEDULE OF IMPLEMENTATION 1975 1976 1977 1978 1979 1980 S OII J I F | AM| J | 11 JI IMAMJ|jj OII J F M A M iE JIAi OII A]MI JIISOII JII AIIIII E i 2 14i E 13 PHASE I - ---- PHASE 11 - I. a FIELD INVESTIGATION TEST BORING GROUTING TEST SEISMIC EXPLORATION _ _ * ADITS & ROCK TEST _ PIT & SOIL TEST TOPO. SURVEY ECOLOGY SURVEY _*** CONC. MATERIAL TEST 1. b DESIGN & TENDERING MAIN CIVIL WORKS mu u... it; METAL WORKS "11 .tau.. ELECTRIC WORKS olulhIloiIll *l!hhumi... COST ESTIMATE y. Study D Detailed Design R. REPORTS §||1|||||| if HYD. MODEL TEST 11. CONSTRUCTION WORKS By H MG. ACCESS ROAD _h. QUARTERS MAIN CIVIL WORKS O- - . PREPARATION . DIVERSION TUNNEL COFFER-DAMS MAIN DAM SPILLWAY INTAKE lIncludin Sim Inta HEADRACE TUNNEL SURGE TANK PENSTOCK TAILRACE TUNNEL nnel POWER HOUSE P.H. INTERIOR WORKS CHAKHEL INTAKE . Manufacturing and Transportation METAL WORKS ------- ssalols lii ii filt ELECTRIC WORKS t o _1 ||"§g >|@|| | gIa " | |§ Manufacturing and Transportation TEST OPERATION WORKS IN FIELD ufilmul HOME WORKS 0------ TENDER & EVALUATION World Bank -15252 (RI ANNEX 12 Page 1 NEPAL KULEKHANI HYDROELECTRIC PROJECT Hydrology General 1. The Kulekhani river originates in the Mahabarat mountain ranges. It is a tributary of the Bagmati river. The catchment area at the damsite is about 126 sq. km. Two downstream tributaries will be diverted into the reservoir or the headrace tunnel directly: namely the Chakhel river and the Sim river with a catchment area of 23 sq. km. and 7 sq. km. respec- tively. Climate 2. The climate of the project area is under the general influence of the sub-continental climate pattern and has two distinct seasons: the wet summer monsoon season which lasts from June to September and the dry winter season. During the wet season, the SW monsoon prevails, bringing a stream of warm humid air from the Indian Ocean, and rainfall is abundant. During the dry winter season, the area has little rainfall. 3. The annual mean temperature, monthly maximum temperature and monthly minimum temperature at Kathmandu are 18.3'C, 30"C and 2"C, respectively. The temperature reaches maximum in May, occasionally rises up to about 35'C. The coldest time is the period fron December to January, when temperatures some- times fall below freezing. 4. The annual rainfall in the Kulekhani river basin is about 1550 mm in the upper reach (based on eight years record at Daman) and 1350 mm in the downstream reach (rainfall record started since 1943 at Kathmandu). About 80% of the rain falls in the months from June to September. Runoff 5. The runoff of the Kulekhani river has been observed since 1963 at the proposed damsite. There is also a gauging station in the vicinity of the project area at Chobhar on the Bagmati river. Its observation records cover the period of 10 years from 1962 to 1971. The runoff record at this station has been used to check the reliability of the runoff observa- tion at Kulekhani damsite. In addition, the runoff of the tributaries, the Chakhel and the Sim, were measured from 1966 to 1973 at the proposed intake weir sites. ANNEX 12 Page 2 6. The average annual runoff at the"damsite over the observation period is about 123 million m3 or 3.9 n3/sec in annual mean. The specific runoff is calculated at 3.1 m3/sec/100 sq. km. The rating curve established is considered to be reliable. The correlation between the annual average runoff and annual average rainfall within the catchment area is also'good. 7. The runoff records of the Chakhel and the Sim rivers have been extended for the period from 1963 to 1972 by correlating the measured flow data with the corresponding records at the Kulekhani damsite. The average annual runoff for these two tributaries are estimated at 22.4 million m3 and 11.8 million m3, or corresponding to an annual mean discharge of 0.71 m3/sec and 0.37 m3/sec, respectively. Flood Flow 8. The largest recorded flood at the Kulekhani damaite is 572 m3/sec which occurred on July 16, 1970. Based on the past recorded annual flood peaks over the period from 1963 through 1972, the probable flood peaks for different intervals of recurrence are projected as follows: Recurrence Flood Peak (m3/sec) Interval (years) By Gumbel's By Iwai's 5 395 333 10 521 475 20 643 634 50 800 874 100 917 1,080 200 1,034 1,311 1,000 1,306 1,947 9. The spillway design flood of 1300 m3/sec adopted by Nippon Koei corresponds only to the 200-year flood by Iwai's probability method which is rather low, especially taking into consideration the short duration of the flow record. ED agreed that at the time of detailed design, the adequacy of the spillway capacity will be checked by a study of the maximum probable flood and a flood routing through the reservoir by the consultants. Sedimentation 10. The annual sediment at the proposed damsite is estimated by Nippon Koei at about 700 m3/sq. km., which corresponds to a sediment in- flow of about 88,200 m3 per year. With a dead storage of 12,000,000 m3 ANNEX 12 Page 3 it will provide enough capacity over the project's estimated life of 100 years. 11. ED agreed that the above estimated figure be checked agsin by the flow duration and sedi*ent rating curve method based on actual moeasurement, before finalizing the detailed design of the intake structure. ANNEX 13 Page 1 NEPAL KULEKHANI HYDROELECTRIC PROJECT Geology General 1. The geology of the region can be divided into three formations according to the chronological order: (1) metamorphosed sedimentary facies; (2) granitic rock intruding into the said sedimentary facies; and (3) sedimentary rocks of the Tertiary Siwalik formation. 2. Metamorphosed sedimentary facies consist of sandstone and sandy semi-schist, quartzite, slate, phyllite, biotite schist, graphite schist, calcareous schist, crystalline limestone and their alternation. These rocks are generally bluish or graying dark colored, except for white quartzite or highly siliceous sandstone, and strongly bedded. Most of quartzite, siliceous sandstone, slate, crystalline limestone and sandstone are fairly hard, whereas others are moderately hard. The Kulekhani area in the northern side of the granite ridge is composed of rather thin alter- nating sandstone and slate groups and partial calcareous rocks, showing a general strike of NNW-SSE and a dip of NE. The southern area of the granite ridge is mainly composed of metamorphosed sedimentary facies of lower Paleozoic Age, showing a general strike of NNW-SSE, but dipping N-S (an indication of foldings). The rock between the granite ridge and the proposed underground powerhouse consists mainly of thick sandstone, sandy semi-schist and alternation of sandstone and slate. The metamor- phical sedimentary facies is terminated with the Tertiary Siwalik forma- tion by a thrust fault running WNW-ESE along the line of Kiseri Khola located about 3 km north of Hetauda. 3. Granitic rock mass is mainly composed of biotite-muscovite granite with large crystals of potash feldspar. It forms the ridge of Daman, rising 2,500 m high above sea level. Tertiary Siwalik formation is composed of mod- erately consolidated sandstone and shale alternation. However, it is not present in the proposed project area. Reservoir Geology 4. The geological formation in the Kulekhani reservoir area is com- posed mainly of metamorphosed sedimentary facies of alternation of sandstone, sandy semi-schist, slate, biotite schist, siliceous sandstone, quartzite, ANNEX 13 Page 2 calcareous sandstone and slate, phyllite, crystalline limestone, etc. Two faults, striking nearly parallel to one another and parallel to the course of the Kulekhani river in the lower reach of the reservoir area from Bazarmath to Burichaur strike NW-SE and dip NE. These faults run along the boundary between sandstone and the alternating formation of sandstone and slate. 5. Two problems are important in reservoir geology, one is the stability of bank slope and the other, the possibility of leakage through the basal rock of the reservoir. Due to the geological structure, the right bank is more viable to landslide than the left but only small-scale landslides can be observed. There are many small talus 'eposits along both banks. As a whole, the possibility of large-scale landslide is low. 6. About 1 - 2 km upstream of the damsite, there is a bank of crys- talline limestone. As it outcrops in the Chakhel river downstream of the dam less than 1 km away and the fault which appears on the right bank of the Chakhel river might be associated with the fault system in the reser- voir, there could be a possibility of leakage through this formation. Further investigation carried out by ED indicates that there is no loss of water along the river bed, no sink holes or solution cavities are found, water leakages by pressure test are of normal magnitude through cracks of ordinary rock formation and the fractured zone of the fault is only 50 cm to 100 cm in width. Damsite Geology 7. The foundation rock of the Kulekhani damsite is composed of sandy semi-schist, biotite schist and phyllite, strongly bedded with a common strike of NW 25-30' and a dip towards upstream at an angle of 30-40' NE. Along the newly-located dam axis, the river is about 50 m wide and the right bank rises at an inclination of 1:1.2 to 1:1.7, whereas the left bank forms a very steep cliff inclining at 1:0.3 to 1:0.6 up to El. 1530 m where the rock bed outcrops. On the right bank, rock is exposed in the lower part and overburden is thin at higher elevation. The inclined im- pervious core will be set on the firm rock in a semi-oval shape to avoid deep excavation. 8. The right abutment is covered with 2.5 m - 3 m thick of talus deposit composed of earth and rock fragments and a fractured rock zone of various thicknesses. Four test adits will be excavated in the detailed investigation stage, three along the foundation of the impervious core and one in the downstream area of the right abutment. 9. River deposit at the damsite ranges from 2 m to 6.5 m and biotite schist underlying the river deposit is partly sheared and weathered to a depth of about 13 m. 5 grouting holes with a total length of 300 m will be drilled and tested during further investigations along the foundation of the impervious core. ANNEX 13 Page 3 Spillway 10. At the left bank where the spillway is to be located, the top layers of 'the base rock are covered'by a talus deposit of 5 to 10 m. These top layers are intensively weathered to a depth about 10 m, underneath which the rock is fresh and sound. 11. The construction of the spillway requires a deep cut, thus in- volving a large volume of excavation, but a large portion of the excavated rock can be utilized as embankment material of the dam. Intake 12. The intake site is composed of sandstone and sandy schist covered with a layer of fractured sub-angular rock fragments and talus deposit. Headrace Tunnel 13. The headrace tunnel will pass through slaty rock and sandstone - slate alternation for the upstream portion of 600 m, then through granite for the middle portion of 2400 m, and finally through metamorphosed sedi- mentary facies consisting mostly of sandstone and quartzite for the down- stream portion of 2800 m. 14. In the upstream 600 m where the tunnel route is close to the fractured zone on the right bank of the damsite, heavy support will be required. In the middle section of 2400 m, no problem will be encountered through the massive granite formation. In the downstream portion of 2800 m also no problem will be expected except in the downstream-most portion near the surge tank where the tunnel may cross a fault and heavy support will be necessary for a length of about 300 m. Surge Tank 15. The last stretch of the headrace tunnel will pass through an alternating formation of sandstone and slate. A fault runs just upstream of the surge tank site, about WNW-ESE. Although this fault is not large, it will be advisable to locate the surge tank downstream of the fault in the sandstone formation. The location of this fault will be confirmed by seismic exploration and drilling in the detailed investigation stage. Penstock 16. The penstock line will be situated on the sandstone formation above El. 1300 m, and on the sandstone and schist alternation below El. 1300 mn. The rock is covered by a few meters of talus deposit. Generally sound rock condition is expected except at the top of the slope. ANNEX 13 Page 4 Underground Powerhouse 17. The proposed underground powerhouse site is situated among the alternating sandy semi-schist, sandstone, biotite scliist and slate. Sandy rocks are generally hard to moderately hard. Biotitg schist and slate are moderately hard and rather friable with intensive foliation. Nevertheless, the bedding of the sandstone is much thicker and dominating than that of slate. The beds in the vicinity of the area show strike trending NW-SE and dip 30 - 400 to NE in the southern part and to SW in the northern part, which suggests the existence of gently warping syncline. The underground powerhouse will be located in the northern side of the syncline axis, dip- ping gently to SW. Tailrace Tunnel 18. The upper half of the tailrace tunnel will be situated in the alternating formation of sandstone and schist and the lower half mainly in the solid sandstone formation, dipping 250-45° NE. Though the rock beds form a wing of folding in this part, no fault or any serious dis- turbance is observed at the outcrops on the ground surface. ANNEX 14 NEPAL KULEKHANI HYDROELECTRIC PROJECT Proposed Detailed Investigations and Studies 1. Further Field Investigations (1) Geology (a) Foundation grouting test at the damsite; (b) Investigation of talus and fractured rock on the right abutment by adits; (c) Seismic exploration and drilling in the surge tank area; and (d) Drilling and aditing in the underground power- house area. (2) Ecology (a) Environmental, health and ecological con- siderations of the Project. 2. Further Engineering Studies (1) Hydrology (a) Adequacy of spillway capacity to be checked by a study of the maximum probable flood and a flood routing through the reservoir; and (b) Estimate of reservoir sedimentation to be checked by the "flow duration sediment rating curve method" based on actual measurement. NEPAL NEPAL ELECTRICITY CORPORATION OPERATING STATISTICS Maximum demand Generation (GWh) Energy Sales (GWh) Load Factor % of /% of Year (MW) growth Hydro Diesel Total growth Domestic Commercial Industrial Others Total (%) 1962/63 - - 3.68 7.53 11.21 - 3.87 - 0.62 - 4.49 - 1963/64 3.55 - 5.55 8.39 13.74 22.5 5.32 - 0.87 0.21 6.40 44.2 1964/65 3.80 7.0 5.77 9.92 15.69 14.2 5.83 - 1.55 0.66 8.04 44.8 1965/66 4.80 26.0 11.47 8.15 19.62 25.0 7.45 - 1.77 0.66 9.82 40.6 1966/67 6.65 38.5 24.66 0.86 Z5.52 30.U 8.89 1.51 1.6Z 0.65 1Z.68 44.1 1967/68 8.21 23.5 29.90 0.46 30.36 18.9 11.61 2.09 1.86 1.26 16.82 42.1 1968/69 9.60 16.9 35.73 0.39 36.12 19.0 13.66 2.62 2.77 2.04 21.09 42.0 1969/70 11.56 20.5 44.73 0.14 44.87 24.8 15.54 3.53 3.08 4.98 27.13 44.0 1970/71 13.86 19.9 53.57 0.08 53.65 19.5 21.15 4.65 3.60 5.93 35.33 44.0 1971/72 17.50 26.3 65.87 0.08 65.35 22.7 28.14 5.09 4.32 7.57 45.17 44.4 1972/73 21.28 21.6 81.26 0.01 81.27 24.0 32.63 5.91 6.71 10.26 55.51 43.6 1973/74 25.50 22.6 96.68 0.05 96.73 19.0 40.92 6.39 10.56 5.35 63.22 43.3 Average rate of growth 22.3% 22.0% Source: Nepal Electricity Corporation. NEPAL NEPAL ELECTRICITY CORPORATION LOAD FORECAST Energy Consumption in MWh Fiscal 2/ Street Station Export Lumbini System Energy Average Load Max. Year Domestic Industry Commerce Lighting Service to India Zone Total Loss Generation Load Factor Demand (%) (MWh) (kW) (7%) (kW) 1974/75 51,260 17,450 8,690 1,390 1,510 5,260 - 85,610 27 117,270 13,390 44 30,430 1975/76 58,750 25,770 10,580 1,650 1,820 8,760 - 107,330 26 145,000 16,550 47 35,220 1976/77 66,890 38,640 12,890 2,000 2,450 12,260 8,890 144,020 25 192,000 21,920 49 44,730 1977/78 75,540 49,200 15,700 2,420 3,410 17,5201/ 10,880 173,670 24 229,000 26,140 50 52,280 1978/79 82,240 59,730 19,130 2,850 3,830 17,520 13,530 198,830 23 258,000 29,450 51 57,750 1979/80 90,000 74,150 23,300 3,400 4,110 17,520 16,040 228,520 22 293,000 33,450 52 64,320 1980/81 98,590 84,150 28,330 3,970 4,300 17,520 21,080 257,940 21 326,500 37,270 52 71,680 1981/82 106,800 92,750 34,500 4,560 4,550 17,520 24,180 284,860 20 356,000 40,640 52 78,150 1982/83 117,480 101,350 42,020 5,250 4,890 17,520 27,150 315,660 19 389,700 44,490 52 85,550 1983/84 129,230 109,950 51,180 6,040 5,180 17,520 30,330 349,430 18 426,000 48,630 52 93,520 Average annual rate of growth 14.0% 1/ Based on present commitment of 5,000 kW. 2/ Consumption for agricultural use is included under the category of Industry. Source: Electricity Department, Ministry of Water and Power. NEPAL NEPAL ELECTRICITY CORPORATION SYSTEM LOAD AND GENERATING CAPACITY System Maximum Available peaking Gross Peak Average New Added Installed Peaking capacity Reserve Firm Year Load Load Plant Capacity Capacity Capacity in dry season Capacity Output (kW) (kW) (kW) (kW) (kW) (kW) (kW) (kW) 1973/74 25,500 11,042 - 39,250 37,820 32,770 7,270 22,520 1974/75 30,430 13,390 - 39,250 37,820 32,770 2,340 22,520 1975/76 35,227 16,557 - 39,250 37,280 32,770 -2,457 22,520 1976/77 44,734-/ 21,920 Gandak + Interconnection 15,000 + 2,346 57,046 46,916 41,866 -2,868 27,377 1977/78 52,170 26,085 - 57,046 46,916 41,866 -10,304 27,377 1978/79 57,798 29,477 Devighat 14,100 71,146 61,016 55,966 -1,832 37,877 1979/80 64,316 33,444 Kulekhani No. 1 30,000 101,146 91,016 85,966 21,650 56,627 1980/81 71,677 37,272 - - 101,146 91,016 85,966 14,289 56,627 1981/82 78,167 40,647 - - 101,146 91,016 85,966 7,799 56,627 1982/83 85.551 44,486 Kulekhani No. 2 30;000 131;146 121;016 115,966 3fli415 56,627 1983/84 93,548 48,645 - - 131,146 121,016 115,966 22,418 56,627 1/ Considering interconnection of Lumbini Zone. 2/ Capacity of the existing system (kW): Maximum Available peaking capacity Firm Hydro Installed Peaking Capacity in dry season Output Pharping 500 500 400 200 Sundarijal 640 700 700 600 Panauti 2,400 2,400 1,500 700 Trisuli 18,000 18,000 18,000 12,000 Sunkosi 10,050 10,050 6,000 4,700 Diesel 7,660 6.170 6,170 4.320 Total 37,820 32.770 22,520 Capacity of new additions (kW): Lumbini Interconnection2,346 2,096 2,096 1,357 Gandak 15,000 7,000 7,000 3,500 Devighat 14,100 14,100 14,100 10,500 Kulekhani No. 1 30,000 30,000 30,000 18,750 Source: Electricity Department, Ministry of Water and Power. ANNEX 18 Page 1 NEPAL KULEKHANI HYDROELECTRIC PROJECT The Least Cost Solution Alternatives to the Prolect 1. The alternatives to the Kulekhani Hydroelectric Project would be either a thermal development or a different hydro facility providing the same service. However, no other hydro projects have advanced to such a stage that could be completed within the time frame to replace Kulekhani. Based on a study made by Nippon Koei (Master Plan of Hydroelectric Develop- ment in Nepal, September 1974), the optimum sequence of hydroelectric devel- opment for the Nepal Central System which gives the least cost solution is Kulekhani No. 1 Project (60 MW), followed by Kulekhani No. 2 Project (35 MW) and then Dev-Ghat Project (150 MW). Kulekhani No. 2 Project cannot be built without the Kulekhani No. 1 Project and Dev-Ghat is still in the early in- vestigation stage, the feasibility study of which would not be ready at least two years from now. 2. The alternative to Kulekhani is therefore a thermal development located at Birganj near the border with India. To confirm that Kulekhani is the least cost solution, the following alternatives based on the instal- lation of different types of thermal generating units and different combi- nations were compared with the Kulekhani Hydroelectric Project with two units in sequential construction. Alternative (1) - 1 - 30 MW coal-fired thermal unit followed by 2 - 15 MW gas turbines. Alternative (2) - 1 - 30 MW heavy oil-fired thermal unit followed by 2 - 15 MW gas turbines. Alternative (3) - 6 - 5 MW diesel units firing heavy oil followed by 2 - 15 MW gas turbines. Alternative (4) - 1 - 30 MW coal-fired thermal unit followed by another 1 - 30 NW coal- fired unit. Alternative (5) - 1 - 30 MW heavy oil-fired thermal unit followed by another 1 - 30 MW oil-fired unit. ANNEX 18 Page 2 General Assumptions 3. The comparison among alternatives were made on a constant value basis (1974 price level) and with costs net of duties and taxes. Assump- tions used in this analysis are summarized below: Alternatives Coal- Oil- Kulekhani fired fired Gas Diesel Hydro Thermal Thermal Turbines Units (1) Plant Data lst unit 30 Mhr 30 MW 30 MW - 6- 5 MW 2nd unit 30 MI 30 MW 30 MW 2 -15 MW - (2) Capital Cost (US$ million) 1st unit 42.5 16.5 14.4 - 9.0 2nd unit 3.5 13.5 12.0 7.5 - US$ per kW Installed 766 550/450 480/400 250 300 (3) Life of Plant 50 25 25 15 15 (years) (4) 0 & M Costs 0.5 2.5 2.5 2.0 4.5 (% of Capital (for peaking Investment) operation only) (5) Heat Rate - 12500 12500 15500 11500 (Btu/kWh) (6) Type of Fuel - Coal Heavy Distillate Heavy oil oil oil (7) Heat Value of Fuel - 8500 18000 19200 18000 (Btu/lb) (8) Unit Fuel Consumption - 0.66 0.32 0.37 0.29 (kg/kwh) (9) Fuel Cost (US$/ton) - 16 100 156 100 (USVkWh) - 1.05 3.2 5.8 2.9 ANNEX 18 Page 3 Results of Comparison 4. The equalizing discount rates between Kulekhani Hydro and other alternatives were found to be as follows: Equalizing Discount Rate (1) Alternative 1 1 - 30 MW coal-fired thermal unit followed by 2 - 15 MW gas turbines 12.95% (2) Alternative 2 1 - 30 HW oil-fired thermal unit followed by 2 - 15 MW gas turbines 17.65% (3) Alternative 3 6 - 5 MW diesel units followed by 2 - 15 MW gas turbines 15.1 5% (4) Alternative 4 1 - 30 MW coal-fired thermal unit followed by another 30 MW coal-fired unit 14.55% (5) Alternative 5 1 - 30 MW oil-fired thermal unit followed by another 30 MW oil-fired unit 18.55% 5. The Kulekhani Hydroelectric Project was found to have a lower present worth of costs at discount rates up to 12.95% by even comparing it with the cheapest thermal development (Alternative 1). Kulekhani is, therefore, the least cost solution. 6. Due to the high investment cost in civil works, the equalizing discount rate would reduce to 9.55% in comparing it with a 1 - 30 MW coal- fired thermal alternative, if only one unit of 30 MW would be installed at Kulekhani ultimately. This demonstrates that the second unit should be installed in accordance with the system demand. Sensitivity Tests 7. Sensitivity tests for changes in capital costs and fuel costs in comparing Kulekhani with two most feasible Alternatives (1) and (4) have been made. The results of the tests are summarized as follows: ANNEX 18 Page 4 Alternative (1) Alternative (4) (1) On main assumPtions 12.95% 14.55% (2) On less favorable assumptions (a) Kulekhani capital cost increased by 10% 11.35% 12.25% (b) Thermal units capital cost reduced by 10% 12.05% 12.95% (c) Fuel cost reduced by 10% 12.45% 14.15% (d) Combination of assumptions (a) - (c) 10.05% 10.65% (3) On more favorable assumptions (a) Kulekhani capital cost reduced by 10% 15.15% 17.85% (b) Thermal units capital cost increased by 10% 14.05% 16.45% (c) Fuel cost increased by 10% 13.45% 15.05% (d) Combination of assumptions (a) - (c) 17.15% 21.15% Probability Analysis 8. Probability Analysis for comparing Kulekhani with Alternatives (1) and (4) have also been made. The range of cost variations and the probabili- ties associated with each variable are as follows: High Basic Low Range of cost variations probability +10% 0 -10% Kulekhani Hydro 0.15 0.70 0.15 Thermal alternatives 0.20 0.65 0.15 Fuel prices 0.25 0.65 0.10 ANNEX 18 Page 5 9. Results of Analysis Alternative (1) Alternative (4) Distribution Mean 13.11% 14.78% Standard Deviation 0.88% 1.32% Range (95% probability) 11.2%-14.7% 12.1%-17.2% ANNE 19 Page 1 NEPAL KULEKHANI HYDROLLECTRIC PROJECT Return on Investment General Assumptions (a) Plant Data InstalIed Capacity 2 x 30 MW Energy Output Primary Energy 165 Gwh Secondary Energy 46 Owh Contribution to existing hydro plants 88 Owh Total 299 Gwh Life of Plant 50 years (b) Project Cost (1974 price level) US$ Million Foreign 37.6 Local 8o TMotal 44e tc) System Loss 1981 21% 1982 20% 1983 19% 1984 18% 1985 17% 1986 on 16% (d) Expected Average Revenue US) per Kwh Domestic Present tariff 1.9 Tariff in 1980/81 Current 509 (6% rate of return) Real 3.5 Export Primary Energy 1.5 Secondary Energy 1.0 November 1975 NEPhL KULEKHANI HYDROELECTRIC PROJECT Unit: US$1,000 Return on Investment Cost Streams Benefit Streams Distribution Fuel System O&M Other Cost Domestic Export Year Project Cost Expansion Cost Cost Total Savings Sales to India Total C 1 C 2 C3 C C B 1 B 2 B3 1976 1,800 0 0 0 1,800 0 0 0 0 1977 5,500 0 0 0 5,500 0 0 0 0 1978 12,700 0 0 0 12,700 0 0 0 0 1979 15,500 0 0 0 15,500 0 0 0 0 1980 8,000 720 0 0 8,720 0 0 0 0 1981 1,600 720 640 220 3,180 540 560 3,567 4,667 1982 1,000 720 640 265 2,625 540 1,070 2,917 4,527 1983 0 800 640 315 1,755 540 1,657 2,471 4,668 1984 0 800 640 370 1,810 540 2,297 1,874 4,711 1985 0 800 640 425 1,865 540 2,962 1,268 4,770 1986 0 800 640 485 1,925 540 3,673 634 4,847 1987-2012 0 0 640 515 1,155 540 3,828 460 4,868 2013 2,000 0 640 515 3,155 540 3,828 460 4,868 2014 2,000 0 640 515 3,155 540 3,828 460 4,868 2015 4,000 0 640 515 5,155 540 3,828 460 4,868 2016 1,600 0 640 515 2,755 540 3,828 460 4,868 2017 1,000 0 640 515 2,155 540 3,828 460 4,868 2018-2025 0 0 640 515 1,155 540 3,828 460 4,868 Equalizing discount rate = 6.15%. I/ Other costs including consumer's services at NRs. 0.02/Kwh and allocated administration and general expenses at NRs. 2.2 million per annum, November 1975 NEPAL. KULEKHANI HYDROELECTRIC PROJECT INCREMENTAL COST OF ENERGY Unit: Million NRa. Year C A P I T A L C 0 S T S 0 & M Other Revenue Total Net Present Present Total Total Present Costs Operating From Costs Worth Worth of Energy Energy Worth of ( P. RN I R A T T 0 N TRANSMISSION DISTRIBUTION Expenses Energy Charged To Factor Total Net Cenerated Sales Energy Sales Oandak Devighat Kulekhani @0.07/Kwh Exported Domestic (@ 87). Costs (Gwh) (Cwh) (C.uh) To India Consumers - - - - - - - - - - - - - Million NRS - - - - -- 1975 30 16 - 2 - 0 - - 48 0.926 44.5 - - 1976 30 44 23 23 6 0 - - 126 0.857 108.1 - - - 1977 38 50 69 41 6 2 1 - 207 0.794 164.4 21 16 12.7 1978 - 44 159 30 10 3 2 - 248 0.735 182.3 43 33 24.3 1979 - 13 194 25 9 4 4 - 249 0.680 169.3 83 64 43.5 1980 - - 100 12 9 5 7 (341 99 0.630 62.4 123 96 60.5 1981 - - 17 . 9 8 11 (28) 17 0.583 9.9 210 166 96.8 1982 _ 16 - 9 8 13 (25) 20 0.540 10.8 240 192 103.7 1983 - - - - 10 8 16 (17) 17 0.500 8.5 280 227 113.5 1984 - - - 10 8 18 (10) 26 0.463 12.0 288 236 109.3 1985 - - - 10 8 20 (6) 32 0.428 13.7 288 239 102.3 1986-2031 - - - - 8 22 (6) 24 5.205 124.9 288 242 1,259.6 98 167 577 133 88 62 114 (126) 1,112 910.7 1,926.2 910.7 Note. 1/ On constant price and tax free basis. Levelized Energy Cost e- = NRS.0.473/Kvh 2/ Other operating expenses include consumer services, administration and general expenses but exclude royalty and income tax. Equivalent to USC 3.8/Kvh 3/ Revenue from the export of energy to India Primary Energy @ 18.5 pais/Kwh Secondary Energy @ 12.7 pais/Kwh. November 1975 10 ANNEX 21 NEPAL NEPAL ELECTRICITY COLRPORATION SCH-EDUJLE OF CURRENT TARIFFS BY CLASS OF CONSUMERS A. Domestic Consumers Min. Monthly Consumption at Place Rate Fixed Charge ein. Ghar,e (Pai'skW7h) (NRs.) (TM-4h) 1. Kathmandu 20 5.00 22 2. Hetauda and Birganj 35 6.oo 17 B. Transport Industry XRs. 7.50/month/installed kW + 15 pais per kWh. C. Manufacturing and Processing Industry Up to 100 kW NRs. 5/month/installed kW + 15 pais per k'`dh. 100 - 500 kW NRs. 7.50/month/installed kW + 12 pais per kWh. Above 500 kW NRs. 10/month/kVA/max. demand + 10 pais per unit to 100,000 kWh. 9 pais per unit next 200,000 kWdh. 8 pais per unit above 300,000 k'Wh. D. Commercial 50 - 500 kW NRs. 7.50/month/installed kW + 18 pais per kWh. Bulk above 500 kW NRs. 10/month/kVA maximund demand + 15 pais per kWh. E. Irrigation and '71ater Supply Off-peak use 10 pais per kWh. Other items 15 pais per kWh. F. Street Lighting Metered 14 pais per kWh. Unmetered 5 pais per watt/month. . Temporary Supply Metered 60 pais per kWh. Unmetered 18 pais per watt/month. Source: Nepal Electricity Corporation NEPAL NEPAL ELECTRICITY CORPORATION TIco.e Statements for PT 1971/72 through FY 1972/73 (Actual). P1937thogPT91/2Frcast (In Millions of Nepal Rupees, except where otherwise stated) Estimated Actual Actual Forecast (2028/29) (2029/30) (2030/31) (2031/32) (2032/33) (2033/34) (2034/35' (2035/36) (2036/37) (2037/38) (2038/39) (20394) Year toiJly15 1971/ 72 197 2 /73 1973/74 1974/75 1975/76 1976/77 19 77./78 1978/79 1979/80 1980/81 1981/82 1982/83 Energy Generated Nydro Cwh 62.45 49.30 59.01 63.47 97.61 140.78 211.00 215.50 273.63 526.09 526.97 538.00 Diesel Gwh 0.08 .06 .05 9.80 2.00 11.34 11.34 26.59 11.34 - - Supplied by Mprt (New Plant at Sunboai not transferred) Cwh 3.42 31.97 36.68 44.00 14.00 35.00 - - - - - lotal 65.95 81.33 95.74 117.27 123.61 187.12 222.34 242.09 284.97 526.09 526.97 538.00 System tosses (including NEC Office and Station Use) C.wh 20.83 25.82 32.22 33.22 30.81 50.43 59.54 63.00 68.59 78.95 81.72 87.12 Energy Sales (Asses 22.2) 45.12 55.51 63.52 84 .05 980 136.69 162.80 179.09 216.38 447.14 445.25 450.88 Average Revenue (Paise Kwh) (excloding )Sales to India) 21.0 21.0 23.9 23.9 42.2 43.4 57.4 57.7 57.5 73.6 73.6 73.6 Operating R evenu Sale of Electricity (Annex 22.2) I/ 9.32 11.67 14.96 19.84 22.21 33.30 37.96 41.90 50.86 93.43 94.27 96.67 Revenue from .tucre tariff increases- - - - - 3.91 22.96 48.64 54.53 66.72 117.38 130.58 145.39 Miscellaneous 01 fu 050.53 0.53 C.00.uj u.67 i/I 0.75 0.78 0.83 Total - Operating Revenu-.3 121 58 20.37 26.65 56.86 87.23 97.10 118.29 211.56 225.63 243.09 Operating Expenses Oper8 tine and Maintenance 3.83 4.56 7.18 9.18 11.30 12.51 16.75 21.17 29.38 42.60 45.33 50.36 Fuel-j/ 1.01 0.02 0.02 1.59 1.03 6.74 6.74 15.82 6.74 - - - Royalty-3/ 2.25 2.78 3.16 6.30 - - Depreciatios 3.00 3.46 4.64 5.07 7.83 8.08 14.15 14.41 18.13 34.67 35.31 36.61 Purchase of Energy - - - - 1.80 4.40 - - - - - - Tax 0.27 0.33 0.43 - 2.81 15.08 28.33 26.02 37.06 47.65 54.56 61.78 2o.tal - Operating Expenses 9.36 11.15 15.43 22.14 24.77 46.81 65.97 77.42 91.31 124.92 135.20 148.75 Operating Income (before interestS 0.27 0.98 0.38 (1.77) 1.88 10.05 21.26 19.68 26.98 86.64 90.43 94.34 Less: lnterest - - - -- - 2.37 2.33 2.28 54.87 54.06 53.16 Dividends 0.05 0.10 0.50 - - - Adjustment (see Note 5) -. - - 3.20 ---. - - - Net Income 0.22 0.88 0.28 (1.77' (1.32) 10.05 18.89 17.35 24.70 31.77 63 System Losses (including office and Stations tine) as , of Operation 32 52 34 28 28 27 27 26 24 22 21 20 Rate Sane (Average Net Assets in Operation) 85 103 123 125 244 328 499 492 652 1,444 1,418 1,453 Rate of Return Operating Income as 7. of Rate Base 0.3 1.0 0.3 (1.4) 0.8 3.1 4.3 4.0 4.1 6.0 6.4 6.5 Operating Ratio Operating Expenses as 7. of Revenues 97 92 98 108 93 82 76 80 77 59 60 61 Average Revenue US Cents/Kwh Sold in Nepal 2.0 2.0 2.3 2.3 3.3 3.5 4.6 4.6 4.6 5.9 5.9 5.9 I/ Assumes tarif inras 47. from April 1976, 387. from July 1977 and 28%/ from July 1980. 2/ i01 Fuel Cenerarion will cease when the first unit (30 MWZ) of Kulekhani Hydroelectric plant is commnissioned by the end of FY 1979/80. 3/Assumes that royalty is discontinued from mid-July 1975. -4/ "he rate of return would he 2.55. if calculated as though the tariff increase were effective from the beginning of the fiscal year. ~5/ Unpaid bills for energy supplied to HMW (Rs 3.8 million) in set off at iMO's request, against the bill for energy supplied by HMil (Sunkosi lIE Plant) over period FT 1972-75 (Rs 7.0 million). 7he balance due by NEC is transferre.d as equity investment in NEC by 5MG. November 1975 NEPAL NEPAL ELECTRICITY CORPORATION Analysis of kWh Sold. Revenues, and Revenue in Pais Per kWh (in millions of Nepal Rupees) (1975/76 (2032/33) 1976/77 (2033/34) 1977/78 (2034/35) 1978/79 (2035/36) Year to 15 July kWh Sold Revenue Pais/kWh kWh Sold Revenue Pais/kWh kWh Sold Reverue Pais/kWh kWh Sold Revenue Pais/kWh (Millions) (Rs Millions) (Millions) (Rs Millions) (Millions) (Rs Millions) (Millions) (Rs Millions) Type of Consumer Domestic 53.92 12.84 23.6 66.89 17.14 23.6 74.54 17.60 23.6 82.24 19.42 23.6 Industrial 24.50 6.40 25.6 38.64 9.89 25.6 49.20 12.59 25.6 59.73 15.29 25.6 Comsercial 8.33 2.00 24.0 12.89 3.09 24.0 15.70 3.77 24.0 19.13 4.59 24.0 Export to India 5.84 1.08 18.5 12.26 2.27 18.5 17.52 3.24 18.5 17.52 3.24 18.5 Street Lighting 1.65 0.23 14.0 2.00 0.28 14.0 2.42 0.34 14.0 2.85 0.40 14.0 Lumbini Zone - - - 8.89 1.78 20.0 10.88 2.18 20.0 13.53 2.71 20.0 TOTALS 94.24 22.55 23.9 141.57 34.45 24.3 170.26 39.72 23.3 195.00 45.65 23.4 Less Load Shedding (1.44) 0.34 - (4.88) (1.15) - (7.46) (1.76) - (15.91) (3.75) - Rebate Net Totals from Sales 92.80 22.21 23.9 136.69 33.30 24.3 162.80 37.96 23.3 179.09 41.90 23.4 Miscellaneous 28.99 53- - 0.60 - - 0.63 - - 0.67 - System Losses (kWh) - 47.98 - _ 56.13 - - 59.17 - Used by NEC Offices and Station Use 1.82 - - 2.45 - 3.41 _ _ 3.83 - TOTALS - Generation/Revenue 123.61 22.74 187.12 33.90 222.34 38.59 242.09 42.56 (1979/80 (2036/37) 1980/81 (2037/38) 1981/82 (2038/39) 1982/83 (2039/40) kWh Sold Revenue Pais/kWh kWh Sold Revenue Pais/kWh kWh Sold Revenue Pais/kWh kWh Sold Reverue Pais/kWh (Millions) (Es Millions) (illions) (Es Millions) (Millions) (Rs Millions) (Millions) (Rs Millions) Type of Consumer Domestic 90.0 21.26 23.6 98.59 23.27 23.6 106.80 25.20 23.6 117.48 27.72 23.6 Industrial 74.15 18.98 25.6 84.15 21.51 25.6 92.75 23.74 25.6 101.35 25.94 25.6 Commercial 23.30 5.59 24.0 28.33 6.80 24.0 34.50 8.28 24.0 42.02 10.08 24.0 Export to India 17.52 3.24 18.5 17.52 3.24 18.5 17.52 3.24 18.5 17.52 3.24 18.5 Export to India - - - 159.70 29.54 18.5 131.14 24.26 18.5 98.72 18.26 18.5 Export to India - - - 33.80 1/ 4.29 12.7 33.80 4.29 12.7 41.39 5.26 12.7 Street Lighting 3.40 0.48 1.40 3.97 0.56 14.0 4.56 0.64 14.0 5.25 0.74 14.0 Lumbini Zone 16.04 3.21 20.0 21.08 4.22 20.0 24.18 4.84 20.0 27.15 5.43 20.0 TOTALS 224.41 52.76 23.5 447.14 93.43 21.3 445.25 94.49 21.2 450.88 96.67 21.4 Less Load Shedding (8.03) (1.90) - - - - - - - - - - Rebate - - - - - - - - - - Net Totals from Sales 216.38 50.86 23.5 447.14 93.43 21.3 445.25 94.49 21.2 450.88 96.67 21.4 Miscellaneous - 0.71 - - 0.75 - - 0.78 - - 0.83 - System Losses (kWh) 64.48 - - 67.65 - - 71.21 - - 74.03 - System Losses (kWh) _ - - 7.00 2/ - - 5.96 _ - 8.20 Office and Station Use (kWh) 4.11 - - 4.30 - - 4.55 - - 4.89 - TOTALS - Generation/Revenue 284.97 51.57 526.09 94.18 526.97 95.27 538.00 97.50 January 1975 > 1/ Additional Energy (Primary) from Rulekhani H.E. Station 159.70 GWhs @ 18.5 pais - Rs 29.54 (Secondary) 33.80 12.7 pais 4.28 193.50 33.82 2/ Estimated Losses in Transmission of Additional Energy Supplies to India at 3ks% of Generation. NEPAL NEPAL ELECTRICITY CORPORATION Statement showing Impact of Tax and Royalty on Hypothetical Tariff Increases (In Millions of Rupees except where otherwise stated) Includes Includes No Tax includes Includes No Tax Tax and Tax and Tax and Iax and Based on FY 1975/76 Royalty (No Royalty) No Royalty Royalty (No Royalty) No Royalty Energy Sold To Consumers in Nepal Gwh 87.0 Export to India Cwh 5.8 Total - Energy Cwh 92.8 Operating Revenue Consumers in Nepal - (per existing tariffs) 21.13 21.13 21.13 21.13 21.13 21.13 (proposed tariff increase) 55.92 48.02 18.74 22.37 14.47 5.32 Export to India 1.08 1.08 1.08 1.08 1.08 1.08 Miscellaneous 0.53 0.53 0.53 0.53 0.53 0.53 Total - Operating Revenue 78.66 70.76 41.48 45.11 37.21 28.06 Operating Expenses Operating Expenses 20.16 20.16 20.16 20.16 20.16 20.16 Royalty (7.5 paise/Kwh sold) 7.90 _ - 7.90 _ _ Purchase of Energy 1.80 1.80 1.80 1.80 1.80 1.80 Tax 29.28 29.28 - 9.15 9.15 - Total - Operating Expenses 59.14 51.24 21.96 39,01 31.11 21.96 Operating Income (before interest net of tax) 19.52 19.52 19.52 6.10 6.10 6.10 Less: Interest on Debt - _ _ _ _ _ Operating Income (after interest and net of tax) 19.52 19.52 19.52 6.10 6.10 6.10 Rate Base 244 244 244 244 244 244 Rate of Return (Operating Income as Z of Rate Base) 8.0 8.0 8.0 2.5 2.5 2.5 Increase in Revenue Required (as % of revenue from existing tariffs) 260 227 87 106 68 25 Average Revenue (US Cents/Kwh) from Sales in Nepal 7,0 6.2 3.6 3.9 3.2 2.4 November 1975 NEPAL NEPAL ELECTRICITY CORPORATION Statement of Sources and Application of Funds - FY 1974/75 through FY 1982/83 (In Millions of Nepal Rupees) (2031/32) (2032/33) (2033/34) (2034/35) (2035/36) (2036/37) (2037/38) (2038/39) (2039/40) Year to July 15 1974/75 1975/76 1976/77 1977/78 1978/79 1979/80 1980/81 1981/82 1982/83 Sources Internal Cash reneration Operating Income (1.77) 1.88 10.05 21.26 19.68 26.98 86.64 90.43 94.34 Depreciation 5.07 7.83 8.08 14.15 14.41 18.13 34.67 35.31 36.61 Total - Cash Generation 3.30 9.71 18.13 35.41 34.09 45.11 121.31 125.74 130.95 Sale of Investments 1.70 - - - - - _ _ _ New Consumers - Contribution for Connections 0.70 0.50 0.50 0.50 0.50 0.50 0.50 0.50 0.50 Total - Sources 5.70 10.21 18.63 35.91 34.59 45.61 121.81 126.24 131 45 Applications Capital Expenditure by NEC (Annex 21.2) 6.40 5.14 5.70 6.40 9.50 8.60 8.60 8.60 8.60 Advances to ED towards Construction: Candak Hetauda Transmission (132 K') - 4.48 12.02 - - - - - Kulekhani Hydroelectric Project 1 (60 MW) - - - 23.00 19.00 26.00 30.00 47.00 - Kulekhani Hydroelectric Project II (35 MW) - - - - - - - - 53.00 Debt Service: Interest - randak Transmission 6% Loan - - - 2.37 2.33 2.38 2.23 2.19 2.13 - Kulekhani HE Project 6% Loan - - - - - - 25.02 24.58 24.10 - Kulekhani HE Project 8-1/27% Loan - - - - - - 27.62 27.29 26.93 - Kulekhani HE Project 6% Loan - - - - - - - - - Aiwrtization - randak Transmission 6% Loan - - - 0.70 0.74 0.79 0.84 0.88 0.94 - Kulekhani HE Project 6% Loan - - - - - - 7.38 7.82 8.30 - Kulekhani HE Project 8-1/2% Loan - - - - - - 3.94 4.27 4.63 - Kulekhani HE Project 6% Loan - - - - - - - 'otal - Debt Service - - - 3.07 3.07 3.07 67.03 67.03 67.03 Working Capital Increase in Current Assets (2.70) 0.59 1.69 3.94 3.32 8.14 16.38 3.91 3.12 (Increase) in Current Liabilities 2.00 - (0.78) (0.50) (0.30) (0.20) (0.20) (0.30) (0.30) Total - Application 5.70 10.21 18.63 35.91 34.59 45.61 121.81 126.24 131.45 Times Debt Service Covered by Cash Generation - - - 11.5 11.1 14.7 1.8 1.9 2.0 November 1975 NEPAL NEPAL ELECTRICITY CORPORATION Capital Expenditure Program - FY 1974/75 through FY 1982/83 (In Millions of Nepal Rupees) Work in Dates to be Progress (2031/32) (2032/33) (2033/34 (2034/35) (2035/36) (2036/37) (2037/38) (2038/39) (2039/40) Transferred Year to JUlY 15 July 1974 1974/75 1975/76 1976/77 1977/78 1978/79 1979/80 1980/81 1981/82 1982/83 to NEC Expenditure by Electricity Department on Plant Transferred to NEC System Expansion 33 K(vyLem y - 1.50 - - - - July 1975 132 Kv Transmission (Gandak-Hetauda) - - - 56.00 - - - July 1977 Generation Plant Devighat Hydroelectric Plant - - - 167.00 - - - July 1979 Gandak Hydroelectric Plant (14 MW) - - 98.00 - - - - July 1977 Trisuli HE (2nd Stage) - - 126.00 - - - - - July 1975 Sunkosi HE Project - - - 110.00 - - - - July 1978 Kulikhani HE Project 1 60 MW - - - 810.00 - 63.00 - July 1980 and 1982 Kulikhani HE Project Ii - - - - - - - - - 50.00 Sub-totals - - 127.50 154.00 110.00 167.00 810.00 - 63.00 50.00 Expenditure Incurred by NEC Distribution 1.55 6.40 5.14 5.70 6.40 9.50 8.60 8.60 8.60 8.60 TOTAL CAPITAL EXPENDITURE 1.55 6.40 132.64 159.70 116.40 176.50 818.60 8.60 71.60 58.60 November 1975 NEPAL NEPAL ELECTRICITY CORPORATION Condensed Balance Sheets at Mid-July 1971 and Subsequent Years through PY 1973/74 (Actual) and through FY 1982/83 Forecast (In Millions of Nepal Rupees except where otherwise stated) Estimated Actual Actual Forecast (2028/29) (2029/30) (2030/31) (2031/32) (2032/33) (2033/34) (2034/35) (2035/36) (2036/37) (2037/38) (2038/39) (2039/40) At .ruly 15 1971/72 1972/73 1973/74 1974/75 1975/76 1976/77 1977/78 1978/79 1979/80 1980/81 1981/82 1982/83 ASSETS Cross Fixed Assets 101.10 140.70 148.09 155.04 288.68 448.38 564.78 741.28 1,559.88 1,568.48 1,640.08 1,648.68 Less: Depreciation (16.12) (19.126 (23.76) (28.83) (36.66) (44.74) (69.89) (84.30) (102.43) (137.10) (172.41) (209.021 Net Fixed Assets in Service 84.98 121.58 124.33 126.21 252.02 403.64 494.89 656.98 1,457.45 1,431.38 1,467.67 1,439.66 Work in Progress 1.27 2.87 1.55 1.00 - - - - - - - - Total - Fixed Assets 86.25 124.45 125.88 127.21 252.02 403.64 494.89 656.98 1.457,45 10431.38 1.467.67 1,439.66 Investments 2.22 1.57 1.87 0.17 0.17 0.17 0.17 0.17 0.17 0.17 0.17 0.17 Current Assets Cash and Bank 2.35 3.16 3.05 2.76 1.70 1.99 3.93 3.55 2.29 3.98 6.54 6.86 Stores 3.81 3.75 4.71 5.00 5.50 5.50 5.60 7.30 14.50 14.50 15.00 17.00 Accounts Receivable (Consumers) 3.77 4.84 5.28 2.55 4.20 5.60 7.20 9.00 11.00 26.00 28.00 30.00 Accounts Receivable 2.92 5.28 3.97 4.00 3.50 3.50 3.80 4.00 4.20 5.00 5.00 5.00 Total - Current Assets 12.85 17.03 17.01 14.31 14.90 16.59 20.53 23.85 31.99 48.37 52.28 55.40 Advances to hlMN towards Construction of Plant - - - - 4.48 - 23.00 42.00 - 30.00 14.00 67.00 Total - Assets 101.32 143.05 144.76 141.69 271.57 420.40 538.59 723.00 1489.64 1,509.922 1,534.12 1,562.23 LIABILITIES Capital and Reserves Equity Shares 95.25 131.99 131.27 131.27 261.97 359.97 458.97 625.97 625.97 625.97 625.97 625.97 Capital Reserve 1.65 2.36 3.44 4.14 4.64 5.14 5.64 6.14 6.64 7.14 7.64 8.14 ocher Reserves 0.74 1.03 1.01 1.01 1.01 1.01 1.01 1.01 1.01 1.01 1.01 1.01 Net Revenue Surplus (Accumulated) 0.17 0.83 0.82 1.82 0.05 (1.27) 8.78 27.67 45.02 69.72 101.49 137.86 Net Revenue Surplus (Current Year) - 0.17 1.00 (1.77) (1.32) 10.05 18.89 17.35 24.70 31.77 36.37 41.18 Total - Eauity and Reserves 97.81 136.38 137.54 136.47 266.35 374.90 493.29 678.14 703.34 735.61 772,48 814.16 Long 'e rm Deb t 67. Loan from NM.C - . - . 39.50 38.80 38.06 37.27 36.43 35.55 34.61 8-1/27 Loan from uNM. - - - 325.00 321.06 316.79 312.16 65 Loan from KM( , - - - - - - - 417.00 409.62 401.80 393.50 Corrent Liabilities Consumers Deposits 2.00 .87 1.16 1.20 1.20 1.30 1.30 1.50 1.70 1.80 2.00 2.20 Accounts Payable 0.73 1.67 0.76 0.80 1.00 1.20 1.20 1.30 1.30 1.40 1.50 1.60 Other Accounts Payable 0.27 3.70 4.87 3.22 3.02 3.50 4.00 4.00 4.00 4.00 4.00 4.00 Dividends and Staff Bonus 0.51 0.43 - - - - - 'otal Current Liabilities 3.51 6.67 7.22 5.22 5.22 6.00 6.50 6.80 7.00 7.20 7.50 7.80 Total - Liabilities 101.32 143.05 144.76 141.69 271.57 420.40 538.59 723.00 1 489.61 __ 509 1534.1 07 3T Debt/Equity Ratio - - - - - 10/90 7/93 5/95 53/47 51/49 49/51 48/52 Current Ratio (Current Assets to Liabilities 3.7 2.6 2.4 2.7 2.9 2.8 3.1 3.7 4.6 6.7 7.0 7.1 M November 1975 ANNEX 25 Page 1 NEPAL KULEKHANI HYDROELECTRIC PROJECT NEPAL ELECTRICITY CORPORATION Assumptions for Financial Projections 1. The financial statements in this report covers NEC's electricity supply operations. They include Income Statements (Annex 22.1), Source and Application of Funds (Annex 23.1) and condensed Balance Sheets at July 15, 1971 through 1981 (Annex 24). The FY 1972/73 results are based on the audited accounts for that year. Income Statements Energy 2. NEC's operating plant capacity will not be sufficient to meet the winter peak demands in 1976 through 1979 despite considerable high cost diesel generation. Substantial load shedding is forecast. System losses (including NEC office and station use) of 28% are assumed in FY 1974/75 gradually reducing to 20% by FY 1982/83. Forecasts of sales, adjusted for load shedding, is also detailed in Annex 22.2. 3. After Kulekhani HE Project is commissioned, it is assumed that surplus energy would be exported to India. Tariffs 5. A tariff increase of about 74% is assumed from mid April 1976 to enable NEC to achieve a rate of return of 0.8% on its average net assets in operation in FY 1975/76. This would be equivalent to a 2.5% return when calculated as though the tariffs had been in operation and royalty had been discontinued (para. 8) from the beginning of the year. Subsequent tariff increases of 38% from July 1977 and 28% from July 1980 are assumed to achieve interim target returns of not less than 4% in FY 1977/78 and 6% in FY 1980/81. Operating Expenses 6. The FY 1974/75 expenses were based on modified budgeted estimates. For FY 1975/76 cost of materials has been escalated by 20%, and employees pay by 8%. In subsequent years, operations and maintenance costs have been escalated by 20% in FY 1976/77, 15% in FY 1977/78, and 10% in each ANNEX 25 Page 2 of the succeeding years. Additional provision has also been included to cover the purchase of power from Sunkosi HE Plant from July 1977 and the additional cost of operations as the following plant is taken over by NEC for operation; Gandak HE Plant from July 1977, Devighat HE Plant from July 1978 and Kulikhani HE Plant from July 1980. Depreciation 7. NEC's depreciation is based on the straight line method. Accrual rates are calculated on the gross value of plant in service: System Reinforcement 3% Rural Electrification 3% New Connections 7% Civil Construction, e.g. S/S and Office Buildings 2% Furniture and Office Equipment 20% Vehicles 20% Transmission (33KV and 132 KV) 3% Generating Plant (Hydro) 2% Narayani Zone 5% Royalty 8. HMG raised its levy for royalty on energy sold from 5 pais to 7.5 pais per Kwh from July 1974. Royalty will be discontinued from July 1975. Income Tax 9. HMG levies tax on NEC's net income (after interest) in excess of NRs 40,000 at the rate of 60%. Revenue appropriate for construction would be subject to a prior tax charge. This means that for every NRs 1 million of revenue required for construc- tion, tariffs should be set to earn NRs 2.5 million (before tax). Dividends 10. Assumes NEC would not declare dividends on equity in any year prior to the completion of Kulekhani Project. Other Assumptions 11. (1) Plant donated to HMG from external sources is assumed to be transferred to NEC as equity and new plant constructed by HMG for NEC transferred as debt. ANNEX 25 Page 3 (2) Debt created by NEC for plant financed with IDA funds is assumed to be repayable over 25 years, with interest at 8-1/2%, the same as if the Bank were making a loan to finance the project. Debt in respect of plant financed by capital provided by HMG or other lending institutions is assumed to be repayable over 25 years, with an interest rate of 6% per annum. (3) NEC would advance funds from its surplus revenue to HMG to help finance construction of projects being constructed for NEC by ED. Debt Service Calculations 12. (1) 6% Loan for Gandak Transmission Plant Transfer. Amount (Net) NRs 39.5 million repayable 25 years at 6% interest. Debt Service = NRs 77,700 100 per million or NRs 3.07 million p.a. 0/S Loan (Beginning Principal Annual Year of Year) and Interest Interest Principal Repayment NRs Million NRs Million NRs Million NRs Million 1977/78 39.50 3.07 2.37 0.70 1978/79 38.80 3.07 2.33 0.74 1979/80 38.06 3.07 2.28 0.79 1980/81 37.27 3.07 2.23 0.84 1981/82 36.43 3.07 2.19 0.88 1982/83 35.55 3.07 2.13 0.94 1983/84 34.61 3.07 (2) Kulekhani HE Project (1st Unit). Net amount of loan covering the part of the Project financed by Kuwait Fund, OECF, UNDP and HMG (NRs 417,000 million), 25 years at 6% p.a. interest. Debt Service = NRs 77,700 per million = NRs 32.40 million p.a. O/S Loan (Beginning Principal Annual Year of Year) and Interest Interest Principal Repayment NRs Million NRs Million NRs Million NRs Million 1980/81 417.00 32.40 25.02 7.38 1981/82 409.62 32.40 24.58 7.82 1982/83 401.80 32.40 24.10 8.30 1983/84 395.50 ANNEX 25 Page 4 (3) Kulekhani HE Project (1st unit). Net amount of loan covering part of the Project financed by IDA credit (NRs 325.00 million), 25 years at 8-1/2% p.a. interest. Debt Service - NRs 97,100 per million = NRs 31.56 million p.a. 0/S Loan (Beginning Principal Annual Year of Year) and Interest Interest Principal Repayment NRs Million NRs Million NRs Million NRs Million 1980/81 325.00 31.56 27.62 3.94 1981/82 321.06 31.56 27.29 4.27 1982/83 316.79 31.56 26.93 4.63 1983/84 312.16 Balance Sheet 13. Long Term Debt: (1) Gandak Transmission Project: NRa Million NRs Million Cost financed by 1M1 and others 56.00 Less: Advances by NEC FY 1975/76 (4.48) FY 1976/77 (12.02) Amount of Loan (at 6%) (16.50O 39.50 (2) Kulekhani HE Project (1st unit): (a) Part Cost financed by IDA Funds 325.00 Advances Amount of Loan (at 8-1/2%) 325.00 (b) Part Cost financed by HMG and others 485.00 Less: Advances by NEC FY 1977/78 (23.0) FY 1978/79 (19.00) FY 1979/80 (26.00) (68.0) Amount of Loan (at 6%) 417.00 ANNEX 25 Page 5 Gross Assets 14. Values are normally on a basis of historic cost or reasonable value if historic cost is not known. Stores 15. From FY 1976/77 assumed at 1% of gross plant. Account Receivables (Consumers) 16. Assumed at a level equivalent to about six weeks or 12-1/2% of annual revenue. IBRD -10107R3 NOVEMBER 1975 NE PAL LOCATION OF EXISTING AND FUTURE POWER INSTALLATIONS 3~~~~~~~~~~~~ ,nero c~~~~~~~~~~~~~~~~~~~~~~ S lo f - . I DIESEL 1 ...0 NO CIMHEDR 5 EXSTEAM MAJRBN THEmA POWRGN ST GATIN FATR Ph___KtnrrkhVle 6 DISEL 572 JAE KPU CCl IGARFTE FCTOR 1 DIESEL 750 N.E C.TMRICT EN ARA M AAKU KALGGA.D8T O2' DIESEL 1,490 N. E.C. BIATNAN A 4 DIESEL 550 N.E.ATNBGARAJTEU MILLECTS BATkry 9 STeAM TURBINE GOD0 BIRHATNAGARA J ACTERYIL KLI IgKHMOh'... 1N DIESEL 5372 RANHUATIPURCGETTE M ACTORY MA K97K7INM 11 DIESEL 3550 DUELECTRICIT BOEARTRO .JNRU . . \ o' 12B N DIESEL 1,43 P E, C. BHARATNAAROPO ERSATO (UNDE CON,IAODL tr,uli 13 DIESEL 1B20 BNGIRATNAD IARYJT CMPI 'HRAA'-~ -.' C ..~" KMWIo MARCH 197 FF /7 14STEAM TURBINE 1400 BIATENDASGAR MLE ILL BHA F9RA9HAWAW GANA UAKI LILLLoIAT(. 15 DIESEL 5G UELESTRAWIT BOPARDMET\HARAHWA N YDR PWEBSTTIN CONEMLAED 12 DIESEL DOG BUEWC. POWAAERY OPWRSAIO UDRCOSRCIN COedNkB'L. j 3k 13DIESEL 30,00 ELECDR MIITY EARYTCMPENT TBAANSN DoEVIGHATC 14PCI IMW MACH 974)G-097-,eo IS DIESEL 5OS ELECTR CITY DEPARTMENT, TEANGUN J KUEYKHANI 14 Pr R Ioo 19.-n1 or Moog 19 IESL 15 LECA CTYDEPRTMNT RIHNAAGA [HYDRO POWER STATION (STUDIED AND PROPOSED) A A 92 JoIso.1,h C' o 1 15 OIGEL OB ELCTR CTY OPARTNNT KISHNAAGARaI Eeararr,nr epeoy 17/I DE /97. FAR097......__ Rhd9oE -1 C AAN A, TherI-I power RItBtGoC (eeSfe4ing)oke C. LAKARPATA 1,1001 E Hydra power stai-SBi (eBisfnog)Rrangr.0 "' U H Aro p-owr tIStIOn (Under oonstr,EctionI 3. SUREKHET 940 Coyrerplte d hydro eleOIria prleOBs A A U ES STING HYDRO POWER STAT 0ONS 4. TRAPNA 949 [ Hydra po-er NstofonS Iesud,ed and proposed) A s N. ER h_ 500 P I PW , 0Cr DO-r B. SETI 395 0132 KV Transmiss,on Ifie (Under -nstrAocton) I PHrARPING 500 BAGBATI N. E. C. 6BTANAKOT 1l13 RR 66 V t-srrn-N oo AlMns (exOsBing)26 -2' GUNDARIUAL 440 BAGMATI N. C. C. 7 POLIOARNI 41 - 33 KSV rn r-m Ssan Iee- (.IefinIgI 3 PANAUTI 2,400 SUNKCS] N. E. C. 8. SAMILA 45 ------- 33 KV tonsmis, on ,,. (Under c.nSt,.i,.n)~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~ 5 IV roSrrloln CR(ude ofllrOln 4 TANAUTIO 3,400 GANDAKI N. E. C.B.AILAI KV tranlsmissior lIneN (ee,lulng) 2 TROGULO 14,000 GANOARI N. B. C. ~~ ~~~~~~9.RAIlN OS0 Po-er ep.rt SlId ir,Iports K 5 5 5 IMTOERS00 IT 0 O SLNKGOS. 10,GBO SUNEDGI E. 0. 10 UIHN1 olh.q.e~02 01 L5OMBTEB2 B POKHARA 1,000 GANDAKI E. 0. TOTAL BOB65 - ZO...O boundarIes __________________________________ 7 TONAL 55G TINAU B. P. C. (oh- -. - nterroional boardories MILBE KABRAI 35 RiAoTh M-,lAe, h.10 0I~ roa A s B OHANKOUTA 240 DH,ANEUTA B. E C. OEYGHAT 150 -"- R-Iv-rs BC' ~~~~~~~~~~~~ ~~~KALIGANDAKI - B'Wl,,0AOo,B-k ~YO11it0l-r99 IBRD 1931 N E PA L KULEKHANI HYDROELECTRIC PROJECT GENERAL PLAN AND PROFILE .vW~~~~ ~~~~~~~~~~~~~ ~~ ~~~~~~~~~~~~~~~~~~~~~~~ - .-t, ,._ _ AOCEBS ROAD ( ___._____. OPE OWA DIR .5 --t.,--_,&J ES tX ~ ; \ 9'< --1 l r _ TE RSTICNAL BOUNDARIE- d \ . ' . F - , z f > P C 'N 2100 COLNROJRO IN METERS -0 I kX t - < +< I W~~~ ~ ~ ~~~~~ ~~~ SI .55 LASS GADD>/ ,t S t ,. X f'0'~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~S -TsI' A., Y~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~AS 0,I'S 25 ~ ~ ~ ~~~~~T