Report No. 833a-NEP IFLE C:tiPNepal uAppraisal of theKulekhani Hydroelectric ProjectNovember 25, 1975

Power DivisionSouth Asia Projects DepartmentNot for Public Use

Document of the World Bank

This document has a restricted distribution and may be used by recipientsonly in the performance of their official duties. Its contents may nototherwise be disclosed without World Bank authorization.

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CURRENCY EQUIVALENT

To October 9, 1975

US$1 n 10.56 Nepal Rupees (NRs.)NR 1 - US cents 9.47NR1 - 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 voltskW - Kilowatt - 1000 wattsMW - Megawatt = 1000 kilowattskWh a Kilowatt hour 1000 watt hoursGWh = Gigawatt hour = 1000000 kilowatt hoursKVA - Kilovolt amperes = 1000 volt amperesha - hectares = 10000 square meters

ACRONYMS AND ABBREVIATIONS

HMG - His Majesty's Government of NepalED - Electricity Department of the Ministry of Water and PowerNEC - Nepal Electricity CorporationEEC 0 Eastern Electricity CorporationBPC m Butwal Power CompanyADB u Asian Development BankOECF - Japanese Overseas Economic Cooperation FundNK - 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 ................. 1The Power Sector s..*.. o.....*....ee"..0.0 2Existing Facilities .. .... * * * * ... * * *.-o-o* * * * * * * .... 3Energy Resources .o-.* ....... ....-.. o... * 4Development Strategy .. ..................... . 4Power Development Program .......... ......... 4Rural Electrification ..................... ... 5

III. THE BORROWER AND THE BENEFICIARY ...... o. .......... 5

Organization and Management .. . .............. 6Electricity Department ..... . .................. 6Nepal Electricity Corporation ............... 6System Loss ... o......................................... se 7

IV. THE PROJECT .............. . -. *.....**.....t. 7

The Project ... o........ . . . .. . . ............-.... *.*.*.. 7Cost Estimate ...........................-... 8Financing Arrangements ...................... 10Ptocurement and Disbursement ....... o...... o. 11Consulting Services ... .. .. ... *. ....... . . . . . .. 11Implementation Schedule ..................... 11Hydrology ooe ...................... o...o........ ..... se 12Geology ........................................ ........ 12Ecology ... ............ 0........ ......................... 12

V. PROJECT JUSTIFICATION ................. see ..... ... 13

The Power Market ........ . . ........................ .... ee 13The Least Cost Solution ........... . ... 14Return on Investment ............... 0...0...... 15

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Page No.

VI. FINANCIAL ASPECTS ................ **. .*..*......... 15

Past and Present Earnings ..... 000.............. 15Present Financial Position .......... ........ 16Tariffs ................................... 16Future Earnings ........ ..... 16Proposed Financing Plan * .................... 17Future Finances .. .. .. ............ ........ . 19Accounts Receivable ................ ......... 19Dividends o.*...... .***. * ..... .... 19Audit *................................ .. 20

VII. AGREEMENTS RIAChED AND RECOMMENDATION ............ 20

LIST OF ANNEXES

ANNEX 1 - Generating Facilities in NepalANNEX 2 - Principal Hydro Power StationsANNEX 3 - Principal Thermal Power StationsANNEX 4 - Power Development Program (No. 9546 R)ANNEX 5 - Organization Chart - Electricity Department (No. 8849)ANNEX 6 - Resume of Nepal Electricity Corporation ActANNEX 7 - Organization Chart - Nepal Electricity Corporation

(No. 8848)ANNEX 8 - Project DescriptionANNEX 9 - Cost EstimateANNEX 10 - Disbursement ScheduleANNEX 11 - Schedule of Implementation (No. 15252 R)ANNEX 12 - HydrologyANJNEX 13 - GeologyANNEX 14 - Proposed Detailed Investigations and StudiesANNEX 15 - Operating Statistics, Nepal Electricity CorporationANNEX 16 - Load Forecast, Nepal Electricity CorporationANNEX 17 - System Load and Generating CapacityANNEX 18 - The Least Cost SolutionANNEX 19 - Return on InvestmentANNEX 20 - Incremental Cost of EnergyANNEX 21 - Schedule of Current Tariffs - Nepal Electricity CorporationANNEX 22.1- NEC Income Statement for FY 1970/71 through FY 1982/83ANNEX 22.2- Analysis of kWh sold, Revenues and Revenues per kWhANNEX 22.3- Statement Showing Impact of Tax and Royalty on Proposed

Tariff IncreasesANINEX 23.1- NEC Sources & Application of Funds - FY 1974/75 through

FY 1982/83ANNEX 23.2- Capital Expenditure Program - FY 1974/75 through

FY 1982/83ANNEX 24 - Condensed Balance Sheet at mid-July 1971 through mid-

July 1983ANNEX 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 whichis needed to meet the rapid growth of power demand for the Central PowerSystem in Nepal. The Project will consist of a dam, a headrace tunnel, asurge tank, a penstock and an underground powerhouse containing two 30 MWgenerating units and associated 66 kV transmission line and switchyardfacilities. The Project will be the key element of the Fifth Five-Year Planof his Majesty's Government of Nepal (HMG) to provide adequate power supplyfor agricultural, industrial as well as commercial development. It wouldmeet the system requirement up to 1985/86.

ii. The total cost of the Project is estimated at about US$68.0 millionequivalent including a foreign exchange component of US$56.5 million. TheJapanese Government has approved in principle a loan of 3.0 billion Yen (aboutUS$10.0 million equivalent) to finance the foreign exchange cost of electricaland mechanical equipment. The proposed IDA credit of US$26.0 million wouldbe applied against the foreign exchange cost of civil works for main dam andspillway. The Kuwait Fund for Arab Economic Development (The Kuwait Fund)has approved in principle a loan of Kuwaiti Dinars (KD) 5.0 million (aboutUS$17.5 million equivalent) to assist in financing the cost of preliminaryworks, hydro-mechanical equipment and civil works other than main dam andspillway. UNDP has approved a grant of US$3.0 million equivalent to financethe consulting services. Any balance of foreign exchange and local costs wouldbe financed by HMG.

iii. The Borrower would be HMG. The Electricity Department (ED) ofthe Ministry of Water and Power would be the Executing Agency and the NepalElectricity Corporation (NEC), the Beneficiary, which would take over andoperate the Project upon its completion. The proposed credit would be thefirst by the Bank Group for the power sector in Nepal.

iv. ED is responsible for the planning and construction of generationand 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 largestand 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 1974/75was 30.4 MW. It has been increasing at an average rate of 22% per annum overthe past ten years. The latest load forecast indicates that maximum demandwould increase to 93.5 MW in 1983/84, an average annual rate of growth of 14%over the next decade.

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vi. ED's future expansion program for the Central System includes theconstruction of the 15 MW Gandak Hydro Project, the 14 MW Devighat HydroProject and their associated transmission lines and substations. The Gandakproject is presently under construction assisted by the Indian Government.

The technical and financial assistance for the Devighat project is beingsought from the Indian Government. The proposed Kulekhani Project is thenext logical project. Total capital investments of the Central System areestimated at US$123 million over the 1975/76 -1982/83 period. The proposedProject would account for 56% of this total.

vii. The proposed Project is the least cost solution for discount ratesup 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 constructeddownstream, utilizing the regulated flow from the reservoir. There are alsoother benefits such as downstream irrigation (about 10,000 ha.), fisheriesand recreation.

viii. The civil works contract to be financed under the proposed creditwould be awarded on the basis of international competitive bidding. NipponKoei Co., Ltd. of Japan (NK) has been engaged to provide consulting servicesfor field investigation, engineering design, procurement and constructionsupervision of the Project with the Bank acting as the Executing Agency forUNDP.

ix. A large part of NEC's plant has been donated by Nepal's neighboringC.ountries, and transferred by HMG as equity capital. As a result NEC is freefrom 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), hasbeen able to finance its distribution requirements. Power programs have notbeen carried out according to schedule and in the interim period until theKulekhani Project is completed, NEC's existing plant will not meet demand evenwith considerable high cost diesel generation and substantial load shedding.

x. NEC pays royalty (7.5 pais per kWh) and is subject to tax at about60% of net income (after interest). Its rate of return in FY 1974/75 was anegative 1.4%. Substantial tariff increases will be required to meet arate 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 DevelopmentCredit of US$26 million equivalent.

I. INTRODUCTION

1.01 This report covers the appraisal of the Kulekhani HydroelectricProject for which HMG has requested financial assistance. The Projectconsists 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 theassociated transmission line and switchward facilities. The first unit isscheduled for completion by the end of 1979/80 and the second unit within12 to 24 months.

1.02 The total cost is estimated at US$68.0 million equivalent of whichUS$56.5 million is the foreign exchange cost and US$11.5 million equivalentthe local cost. HMG has requested financial assistance from the JapaneseGovernment, 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 proposedcredit of US$26.0 million, would be applied against the foreign exchange costof civil works for the main dam and spillway. The Kuwait Fund has approvedin principle a loan of KD 5.0 million (about US$17.5 million) for a term of32 years including 7 years grace with interest at 3% per annum to apply tothe cost of preliminary works, hydro-mechanical equipment and civil worksother than main dam and spillway. UNDP has approved a grant of US$3.0 millionequivalent to finance the consulting services. Any balance of local andforeign 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 NipponKoei (NK), HMG's Consultants, on information provided by the ElectricityDepartment of HMG (ED) and Nepal Electricity Corporation (NEC) and on thefindings 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° NorthLatitude 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 widthfrom north to south about 190 km. Its northern boundary merges with theTibet region of the People's Republic of China. On the east it bordersthe 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 andUttar Pradesh.

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2.02 High mountains and rolling hills account for about 83% of thetotal area; the remaining 17% is occupied by the flat land of Terai. Thereare five well-defined regions extending from south to north: the Teraiplain; the Siwalik Hills; the Mahabharat Range; the Midland and the HimalayasRange.

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 thepopulation lives in the Terai. The Western Terai has a population densityof about 374 people per km2, while the Eastern Terai has 1,380 and theCentral Terai, 741.

2.04 Nepal has been classified by the United Nations as one of theleast developed countries. GDP was estimated at US$1,280 million in1973/74 and is growing annually at about 2.2% in real terms. Per capitaGDP is about US$90-100. The principal economic activity is agriculturewhich accounts for 70% of the GDP and provides employment for over 90% ofthe labor force. The main cash crops are rice, jute, sugar, oil seeds andtobacco, largely produced in the Eastern Terai. There is also some timberlogging in the central and western areas. Industry, which is concentratedin 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'seconomy and foreign exchange earnings.

2.05 Serious efforts towards development have been underway only sincethe late 1950's. Development expenditures have increased rapidly fromNRs. 232 million in 1964/65 to NRs. 930 million in 1974/75. The great bulkof the resources available for development have been invested in infrastruc-ture, particularly road, power and irrigation facilities. About half of theexpenditures for development during this period have been financed withexternal assistance, notably from India, the United States and the People'sRepublic 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). Grossexternal reserves as of November 1974 stood at US$139 million which declinedto US$94 million by September 1975.

The Power Sector

2.06 There are at present four organizations in the field of publicpower supply in Nepal:

(a) The Electricity Department of the Ministry of Waterand Power (ED);

(b) The Nepal Electricity Corporation (NEC);

(c) The Eastern Electricity Corporation (EEC); and

(d) The Butwal Power Company (BPC).

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2.07 ED is responsible for electric power development throughout theKingdom of Nepal. It plans and constructs new generation and transmissionfacilities and controls privately-owned utilities. At present, apart fromSunkosi HE plant (10 MW), it also operates the small government-ownedfacilities and distributes electricity in Pokhara and in about fifteen newly-electrified towns.

2.08 NEC, a government owned corporation, is responsible for generatingand distributing electricity in the area of the Bagmati Zone where theKathmandu Valley is located and, since April 1973, the Narayani Zone.

2.09 EEC, established in October 1974, has since taken over two privateentities, the Morang Hydro Electric Supply Company (MHESC) and the DharanElectricity Corporation (DESC). It is owned up to 25% by NEC and theremainder by HMG. The Butwal Power Company (BPC) is entirely a privatecompany.

2.10 There are about 64,200 consumers in Nepal, representing less than3% 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 otherconsumers. Per capita generation in 1973/74 was only 10 kWh compared to20 kWh and 120 kWh in Bangladesh and India, respectively. On the basis ofactual 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 about0f.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 entiresector 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 remaining8.2 MW are captive generating plants. The largest unit sizes are 3,350 kWhydro, 1,490 kW diesel and 1,600 kW steam.

2.13 The Central System operated by NEC is the largest and mostdeveloped electricity supply system in Nepal. Power is supplied by fivehydro and four diesel stations with a total capacity of 31.6 MW and 8.3 MWrespectively (see Annexes 2 and 3 for details). Transmission is carriedout at three voltage levels: 66 kV, 33 kV and 11 kV, with a total lengthof 276 km. A 150 km, 132 kV transmission line is now under constructionbetween Gandak and Hetauda financed under an ADB loan.

2.14 The second most important area is the Kosi zone around the cityof Biratnagar operated by EEC. The present total installed capacity in thisarea is about 6 MW which represents 43% of the power facilities outside theCentral System. The power in this area is supplied mainly from diesel andthermal generating units supplemented by a micro hydro plant at Dhankuta(240 KW) and by power exchange with India.

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2.15 The principal power facilities in the country are shown in Annexes2 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 EDthrough the installation of micro hydro plant and diesel units (about 3,065kW in total, some of which were relocated from the Central System), extensionof 33 kV transmission lines and through exchanges of power with India alongthe southern border.

Energy Resources

2.16 Nepal has no known indigenous sources of commercial energy withthe exception of hydro. Stretching between the Himalayas and the GangeticPlains, 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 schemesranging in potential capacity from 18 MW to 1,800 MW, with a total of 6,600MW for the entire basin.

Development Strategy

2.17 The Government's basic strategy for development of the sectoris based on hydroelectric power. In early years when the load is too smallto permit the economic development of large hydroelectric schemes, localrequirements will be met by micro hydro or diesel installation or, in thecase of border areas, by importing electricity from India. This strategyis 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 theincreasing power demand;

(b) to extend electric services gradually to new areas inthe country;

(c) to bring about regional balance in the production anddistribution of electric power.

PFower Development Program

2.19 ED's future expansion program (Annex 4) for the Central Systemincludes the following:

(a) the Gandak Hydro Project (3 x 5 MW) presently underconstruction by the Government of India to be completedin 1976/77;

(b) a proposed hydro project (14 MW) at Devighat downstreamof the existing Trisuli power station with technical andfinancial assistance to be arranged with the Governmentof India;

(c) the Kulekhani Hydro Project (2 x 30 MW) to becompleted by end 1979/80 for the first unit and1981/82 for the second unit. This is the project forwhich a development credit is proposed; and

(d) associated transmission lines and substations.

2.20 For purposes of future project preparation, ED is seeking UNDPassistance to undertake:

(a) the preparation of a master plan for the hydropower development of the Gandak river basin andthe completion of a feasibility study of the mostpromising scheme;

(b) a preliminary study of hydroelectric schemes onthe Seti river;

(c) a preliminary study of the Bagmati High DamHydroelectric 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 incentral Nepal while the last one is for the development of the Far WesternRegion. They are the logical schemes to be studied.

Rural Electrification

2.22 Since 1970, NEC provided supply to about 13,600 rural households inthe Kathmandu Valley. So far, NEC bears all the distribution costs, theconsumers pay only a connection charge and costs for interior wiring. NECplans to spend a total of about NRs. 30 million to electrify 30,000 morehouseholds during the next 10 years, but in view of inadequate generatingcapability and financing constraints, this program will have to be deferreduntil 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 forconstructing 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 Associationand HMG.

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Organization and Management

3.02 NEC is now operating in the Bagmati and Narayani zones. Withthe construction of 132 kV transmission line from Hetauda to Gandak and theextension 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 a132 kV transmission line from Bharatpur to Pokhara scheduled for completionin 1979. The Gandaki Zone will then be interconnected. All these facilitieswill be turned over to NEC for operation. During negotiations, it was agreedthat 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 ofthe Ministry of Water and Power, He is assisted by a Deputy Chief Engineerwho is mainly responsible for operational and administrative matters. Inthe head office in Kathmandu, there are five sections covering: investiga-tion, design and planning, finance, procurement stores and workshop, andadministration. There are also three regional construction, operation andmaintenance offices: the Kathmandu (Central) region, the Dhankuta (Eastern)region and the Pokhara-Surkhet (Western) region. The organization chart isshown in Annex 5. ED has 615 technical and 254 administrative staff outof which 60 technical and 14 administrative staff are senior officers.

Nepal Electricity Corporation (Beneficiary)

3.04 NEC was established under the Nepal Electricity Corporation Act1962 as a corporate body, having perpetual succession, and power to acquireand hold property, and to sue and be sued. It has an authorized capital ofNRs. 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 hasreceived additional assets valued at approximately NRs. 106 million for sharesto be issued to HMG. The authorized share capital will be increased toenable NEC to issue shares to HMG in respect of generation and transmissionplant to be transferred in the near future. NEC's powers and duties are setout in Annex 6.

3.05 NEC's Board of Directors has an Executive Chairman and five othermembers. The Chairman is the General Manager. The members consist of theChief Engineer (Electricity Department), representatives of the Ministry ofWater and Power, the Ministry of Industry and Commerce, the Ministry ofFinance, the Kathmandu Town Council. Under the General Manager, there arefour executive positions for Planning and Generation, Transmission andDistribution, Administration and Commercial, and Finance and EconomicAnalysis (see Annex 7). NEC also has a branch office at Hetauda which isresponsible for the operations in the Narayani Zone.

3.06 The existing management of 4 managers and 27 engineers most ofwhom are graduates of Indian Universities is competent. Together with anadditional 268 technical staff and 963 others, the total of 1,262 employeesis excessive for a utility which has a capacity of only 30 MW and about 56,000consumers. ED and NEC together own 43.5 MW generating plant and have 2,100employees, or 48 employees per 1,000 kW of plant. The transfer of TrisuliHE Plant will require NEC to take over additional operating staff whichthe Government of India, as donor of the plant, had hired and trained. Asthe number of employees is excessive a ceiling was discussed during negotia-tions. HMG and NEC recognized that the present overall staff is excessiveand would endeavor to make use of excessive staff in operating the expand-ing facilities. The problem will be kept under review and followed upduring supervision.

3.07 HMG agreed during negotiations to transfer to NEC Trisuli (2ndStage), Sunkosi and Gandak. These would be transferred as equity. Otherplant, constructed with its own funds and with funds provided on concessionalterms, would be transferred as debt. Debt would represent the cost of theplant to HMG less any amount NEC had contributed towards its cost. HMGagreed 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 theProject financed with IDA funds would be transferred as debt repayable over25 years at 8-1/2% interest. The equivalent of the Kuwait Fund loan wouldbe transferred as debt repayable over 25 years at 6%. HMG intends to usethe 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 thehigh 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 waysand means of doing this.

IV. THE PROJECT

The Project

4.01 The Project, located about 30 km southwest of Kathmandu, willconsist of the following:

(a) a 107 m high rockfill dam on the Kulekhani river witha total embankment volume of about 3.5 million m3;

(b) an open channel spillway controlled by two radialgates;

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(c) an intake structure connected to a headrace tunnelof 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 and1,340 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 powertransformers and associated switching and protectionequipment;

(i) a 66 kV 200 m long double circuit transmission lineto connect with the existing line between Kathmanduand Birganj; and

(j) extension of the existing substation at Kathmanduwith two 35 MVA transformers and switching andprotective equipment.

(Annex 8 provides project details and Map 2 shows the plan and profile ofthe Project.)

4.02 The Project will provide 60 MW of dependable peaking capacity andgenerate 165 GWh of primary energy and 46 GWh of secondary energy annuallywhich would replace use of energy in one form or another equivalent to about65,000 tons of oil per annum.

Cost Estimate

4.03 The following table summarizes the project cost based on 1974price levels:

In millions of NRs.- In millions of US$ % ofForeign 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 3.7Electro-mechanical 70.0 7.5 77.5 5.6 0.6 6.2 9.1Transmission &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% representsabout 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.

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Financing Arrangements

4.04 The Japanese Government has approved in principle a loan, to bemade through the Japanese Overseas Economic Cooperation Fund (OECF), of3 billion Yen (about US$10 million) to finance the foreign exchange costof electro-mechanical equipment (turbines, generators, cranes, instrumentationand control, etc); associated transmission line and switchyard facilities.The proposed IDA credit of US$26.0 million would finance the foreign exchangecost of civil works of main dam and spillway. The Kuwait Fund loan of KD5.0 million (about US$17.5 million) would finance the foreign exchange costof 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 millionequivalent in local currency) would finance the consulting services. Thelocal cost of approximately US$11.2 million equivalent and any balance offoreign exchange cost not covered by external financing would be financedby 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 - 10.0Transmission Line and Switch-yard facilities

IDA Civil Works (Main Dam and 26.0 - 26.0Spillway)

Kuwait Preliminary Works, Hydro- 15.9 - 15.9 /1Fund mechanical Equipment and

Civil Works other than MainDam 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, equivalentto about US$17.5 million. The Kuwait Fund has agreed to retain surplusfunds as contingencies.

- 11 -

4.06 Effectiveness of the loan agreements between HMMG and OECF and betweenHMG 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 serviceswas 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 befinanced by the proposed credit will be procured in accordance with theBank's Guidelines on the basis of international competitive bidding whileprocurement under the Kuwait Fund loan wiLl follow Kuwait Fund procedures.Due to the magnitude and nature of the works, which requires experiencedforeign 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 campand living quarters. Prequalification will be carried out for all civilworks 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 IDAare 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 anderection. Disbursements from the proposed credit will be made against100% of foreign expenditures of civil works for main dam and spillway. Anybalance remaining after completion would be cancelled unless there are goodreasons for applying the savings to related works. A disbursement scheduleis shown in Annex 10.

Consulting Services

4.08 The feasibility study was done by NK under technical assistanceprovided by the Japan International Cooperation Agency. NK has been retainedas Consultants for field investigation, detailed design, preparation ofspecifications and tender documents, procurement and construction supervisionof 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, whichallows about 16 months for phase I work including field investigation,engineering design, preparation of tender documents and tendering and 41months for construction (phase II). Tenders for civil works will be issuedby July 1976 and awarded by the end of 1976. Construction will be startedin 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 firstunit will be ready for commissioning by end 1979/80 and the second unitabout 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 madebetween the runoff and rainfall which confirmed the reliability of the flowrecords. The preliminary spillway design flood of 1,300 m3/sec may be onthe low side due to the short duration of the flood record as Creager'sequation would give a peak discharge of about 2,000 m /sec for a drainagearea of 126 sq. km. ED agreed that the adequacy of the spillway capacitywill be confirmed by further study during detailed design by the Consultants.

4.11 The annual sediment at the proposed damsite is estimated by NKat about 700 m3/sq. km., which corresponds to a sediment inflow of about88,000 m3/year. ED agreed that this will be checked by the flow durationand sediment rating curve method based on actual measurement, that debrisdams will be considered in the future to intercept the bed load and thatprovision will be made in the design of the intake structure to allow theplant to be operable even if the silting level should raise higher thanoriginally envisaged. (Further details are provided in Annex 12).

Geology

4.12 19 drill holes and seven seismic exploration lines with a totallength of 667 m and 1,600 m respectively were made at the damsite and 5drill holes with a total length of 315 m at the underground powerhousesite. The present project layout has taken the engineering geologicalconditions into consideration. However, to provide necessary informationfor detailed design and to enable prospective bidders to prepare realistictenders, ED agreed to carry out the following investigations with Consultants'assistance:

(a) Foundation grouting test at the damsite;

(b) Investigation of talus and fractured rockzone 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 ofabout 220 ha, of which 150 ha is cultivated. There are no noteworthyinfrastructure, mineral or forestry resources, nor subjects of archaeologicalinterest in the reservoir area. According to a recent survey conducted by ED,there are about 235 houses in the reservoir area and 1200 inhabitants tobe resettled. As the area of land being cultivated by each family is small

- 13 -

and living conditions poor, no resettlement problems are foreseen. A sumof US$0.6 million or about US$500 per inhabitant has been included in thecost estimate. To ensure the satisfactory execution of resettlement, itwill be essential that the Ministry of Water and Power, in cooperation withother relevant government authorities, prepare a detailed resettlement planby December 31, 1976. During negotiations assurances were obtained thatthe detailed plan will be submitted to the Association no later thanMarch 31, 1977.

4.14 A field survey of surface erosion conditions in the Kulekhanibasin was made by Japanese experts in 1963. According to the report, onlymoderate erosion of mountain slopes in the catchment area of Kulekhani canbe expected. This was confirmed during appraisal. HMG has enforced aforestry protection program in the watershed area and vegetation cover hasbeen improving.

4.15 Malaria is unknown in the watershed area and people are generallyhealthy. There are no irrigation or water supply facilities in the down-stream reach of the Kulekhani river. The diversion of water to the Raptiriver basin, an adjacent watershed, will not affect the population livingdownstream of the Kulekhani damsite. Nevertheless the Consultants willexamine the environmental, health and ecological consequences of the Projectfurther during field investigations which must be completed prior to finaldesign.

V. PROJECT JUSTIFICATION

The Power Market

5.01 At the end of 1963/64, NEC served a maximum demand of 3.5 MW andgenerated 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 therewas a sevenfold increase in power and energy requirements. Average annualgrowth rates were about 22% both for maximum demand and energy generationas shown in Annex 14.

5.02 The load forecast for the next ten years is based on the expectedincrease 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, andon the number of tourists expected in the coming years for the commercialload. The interconnection of the Western Zone after completion of the 132 kVGandak-Hetauda transmission line and the 33 kV transmission system by 1976/77has 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 MWin 1983/84, and energy requirement from 117.3 GWh in 1974/75 to 426.0 GWh in1983/84. The average annual rate of growth would be about 14%, graduallylevelling 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 inparagraph 2.19 and shown in Annex 4. This forecast is adequate as a basisfor investment and revenue projections.

5.03 Peaking capability in the dry seasons from 1975/76 through 1978/79will 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. TheProject is therefore a key element in NEC's system expansion program andHMG's Fifth five-year plan to provide adequate power supply to industrial,commercial as well as agricultural development in the Central and WesternZones. The Chitwan Valley Irrigation Project, presently under construction,alone would utilize about 7,000 KW or 12% of the Project's total generatingcapacity.

The Least Cost Solution

5.04 The existing hydro power plants in the Central System (31.6 MWinstalled) are either run-of-river or pondage plants without any seasonalregulation. Therefore, dependable peaking capacity during the dry season,November through May, is reduced to only 26.6 MW. The operation of thesystem would be greatly improved after the completion of the KulekhaniProject. The Project will contribute ultimately 60 MW in dependable peak-ing capacity, 165 GWh in primary energy and 46 GWh in secondary energyannually. The second unit will be mainly a peaking unit.

5.05 Since no other hydro schemes have been sufficiently investigatedto replace Kulekhani for completion by 1980, the only possible and real-istic alternative is a thermal development. Five alternatives consistingof different types of thermal units were compared with Kulekhani. On themain assumptions, the equalizing discount rates were found to range from12.9% to 18.5% indicating that Kulekhani would be the least cost solutionfor discount rates up to at least 12.9% (Annex 18).

5.06 The sensitivity and probability analysis between Kulekhani andthe best thermal alternative (1 - 30 MW coal-fired unit plus 2 - 15 MW gasturbines) were tested for variations in capital costs and fuel costs. Asshown in Annex 18, the range of equalizing discount rate with 95% probabilityvaries between 11.2% and 14.7Z.

5.07 Two additional power stations, Kulekhani No. 2 (35 MW) and KulekhaniNo. 3 (17 MW), could be constructed downstream of the Rapti river, utilizingthe regulated flow from the Kulekhani reservoir. Other benefits such asdownstream irrigation (about 10,000 hectares along the valley of Hetauda),fishery and recreation would result from the Kulekhani reservoir. Thesebenefits would be much greater than the losses resulting from inundatingthe reservoir area.

- 15 -

Return on Investment

5.08 Based on the present tariffs, the average revenue obtained fromdomestic sales is about USJ1.9 per Kwh. Revenue from energy exported toIndia is based on the existing agreement of power exchange between Indiaand Nepal at US41.5 per Kwh. As shown in Annex 19 the internal rate ofreturn of the Project, or the discount rate at which the present worth ofcosts attributed to the project is equal to that of the benefits from itover its life, is about 6% in constant prices. This confirms that thepresent tariffs are low. Incremental system cost of energy, based on thepower 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 toreach USi3.5 per Kwh in real terms by 1980/81 will mean that it willapproach gradually to the incremental system cost and be able to make aninternal 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 wasdonated to HMG by India, China, Russia and the USA. Part of this plant hasbeen transferred to NEC as equity. As a result, NEC has no debt and despiteits low tariffs and high system losses, its annual cash flow has financedmoderate distribution expansion.

Past and Present Earnings

6.02 In 1971 NEC's domestic tariff for Kathmandu Valley was reducedfrom 35 paise to 20 paise per kWh. In the following three years to FY 1973/74its 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 becauseHMG 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% inFY 1972/73. Despite the continuing "free supply" of energy, NEC's rate ofreturn dropped again to 0.3% in FY 1973/74. This was due to a substantialpay raise to employees and a 50% increase in royalty from 5 paise to 7.5paise per kWh sold. In FY 1974/75 NEC had a deficit of NRs. 1.77 millioncorresponding to a negative rate of return of 1.4%.

6.03 During negotiations, HMG agreed to continue to provide NEC withenergy generated by Sunkosi HE Plant up to the date of its transfer toNEC. HMG indicated its intention to treat as an equity investment thecost of energy supplied by Sunkosi during the period from FY 1971/72 toFY 1974/75 assessed to NR 7 million, subject to deduction of unpaid billsamounting to NR 3.8 million for electricity supplied by NEC to variousgovernment 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 tofailure to raise tariffs in the face of rising costs, a cash flow justsufficient to finance modest distribution expansion, and no call on earningsto finance generation or transmission plant.

Tariffs

6.05 The present tariff schedule has seven categories: domestic,transport industry, manufacturing and processing industry, commercial andservice industry, irrigation and water supply, street lighting, and temporarysupply. In addition, supplies are exported to India under a power exchangeagreement which provides for Nepal importing 5.8 MW from India and exporting5 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 inthe past, because it has no debt, were sufficient after meeting operatingexpenses to meet increased working capital requirements and finance moderatedistribution system expansion. This low average tariff compares to USJ2.4per kwh in Andhra Pradesh State in India in FY 1973/74. Recently, Bankstaff examined the tariff levels and structure in Andhra Pradesh and foundthat marginal cost based tariffs should be about US45 per kWh or double theexisting average. The incremental cost of energy in Nepal is estimated atUSU3.8 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'sfinancial performance. Internally generated funds after meeting operation,maintenance and management expenses, (including taxes) should be sufficientto cover debt service, reasonable increases in working capital, dividends(if any), and a reasonable proportion of the cost of construction. A rateof return of 8% (net income before interest expressed as a percentage ofaverage net fixed assets in operation) would accomplish this. However, asillustrated in Annex 22.3, extremely high and unrealistic tariff increaseswould 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 toexempt NEC from royalty, but not tax. In view of this, it became clearthat 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 (withthe 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 thatfurther 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 situationwill be jointly reviewed by HMG and the Association with a view to reaching8% as early as possible thereafter.

- 17 -

6.08 Annexes 22.1 and 22.2 assume that surplus power from Kulekhaniwould be exported to India at existing low rates of approximately USO1.5per kWh, until the load within Nepal builds up to fully utilize Kulekhani'spower. In the three years FY 1980/81 to FY 1982/83, the revenue from thissource is estimated at approximately 13% of NEC's total revenue from sales.These assumed prices are substantially lower than the prices in India acrossthe border and it is reasonable to expect that there will be no difficultyin exporting the power as assumed. A formal undertaking from the Indianstates adjoining Nepal for the purchase of this power is not proposed asit would be unrealistic to expect a formal agreement for short term powersupply, 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 couldbe discontinued with a resultant savings on imported fuel. The savings wouldmore than offset the reduction in revenue in FY 1976/77 and FY78/79, althoughthey 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 beginsoperations in 1980, and tariff increases slightly higher than forecastswould be necessary to satisfy the 6% return covenant.

6.10 In connection with a December 1972 loan by ADB, HMG agreed thatNEC would achieve a rate of return of 8% on its "total assets after coveringoperational expenses, charges and interest payment" not later than December31, 1977. As no substantial adjustment to the tariff schedule will be madeuntil about March 1976, this return is unlikely to be achieved. ADB has beenadvised of this.

Proposed Financing Plan

6.11 The following statement consolidates NEC's sources and applicationof funds (Annex 23.1). The transfer to NEC of the Gandak Transmission andKulekhani HE Project on their commissioning is assumed.

- 18 -

FY 1975/76 - FY 1979/80

% ofNR million US$ million Total

Internal Cash Generation 142.45 11.4 16Less Debt Service (9.21) (0.7) (1)Less Working Capital Increase (15.90) (1.3) (2)

Net Cash Generation 117.34 9.4 13Consumer's Contributions 2.50 0.2 _

Internal Funds 119.84 9.6 13

DebtH1MG Loan (re Gandak) 39.50 3.1 4HMG Loan (re Kulekhani) 417.00 33.4 47IDA Credit (onlent) 325.00 26.0 36

Total Funds 901.34 72.1 100

ConstructionDistribution 35.34 2.8 4Projects Transferred

Gandak Transmission 56.00 4.5 6Kulekhani HE Project 810.00 64.8 90

Total Plant 901.34 72.1 100

6.12 Internal cash generation is based on sales forecasts consideredadequate for investment planning (para. 5.02) and on tariff increases toachieve target rates of return discussed in para. 6.07. Although NEC isnot presently responsible for construction of its generation and trans-mission plant, it should nevertheless be expected to finance a reasonableproportion of the cost of such plant constructed by others. NEC shouldadvance 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 itsbehalf. These advances would reduce the subsequent debt when the completedplants are eventually transferred. During negotiation discussions, H1MG concurred inprinciple that NEC would make such advances each year from its surplus funds.

6.13 NEC's internally generated funds would finance 13% of constructioncost (4% for distribution and 9% as advance toward the cost of the aboveprojects). Debt would finance 87% of which the Association credit wouldrepresent 36%.

6.14 Revenue is projected assuming rates of return targets for FY1975/76 through FY 1982/83 will be met (para. 6.07). This would resultin: (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 finance13% of construction expenditures (excluding donated plant) over the periodFY 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-foldfrom 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 additionalplant as loan, NEC's debt would be NRs. 780 million (US$62 million) aftertransfer of the first 30 MW unit of the Kulekhani HE Project at the end ofFY 1979/80. Debt/Equity ratios would be 53/47 at the end of FY 1979/80reducing to 48/52 at the end of FY 1982/83. Internal cash generation wouldcover debt service by over 1.8 times in each of the FY 1980/81 through FY1982/83.

6.17 The current ratio (current assets/current liabilities) wouldincrease 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. Thefollowing 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 3.19Other 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 billingsbut current collections show some improvement. However, collections fromHMG are unsatisfactory.

6.19 During negotiations HMG agreed to settle its arrears and alsoagreed that its departments would pay their current bills promptly. Settle-ment of the unpaid bills would be made by deduction from NEC's liability forenergy supplied by Sunkosi HE plant (para. 6.03).

Dividends

6.20 Agreement was reached during negotiations that NEC would notdeclare dividends on HMG's equity for any fiscal year until the KulekhaniProject is completed.

- 20 -

Audit

6.21 NEC's books are audited by the Auditor General of Nepal, who isappointed by His Majesty. The Auditor General's powers and duties arecontained 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 verifycash balances, inventories, assets and liabilities, and to ensure that thesystems of accounting are efficient. This was agreed during negotiations.

VII. AGREEMENTS REACHED AND RECOMMENDATION

7.01 During negotiations agreement was reached on the following pointsand 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 andbetween HMG and the Kuwait Fund and implementation of tariff increases ofabout 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 ofUtility 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 1963/64river

4. Trisuli NEC Run-of- 18,000 3,000 x 6 1969/70river 3,000 x I (stand-by)

5. SunkosiL/ ED Run-of- 10,050 3,350 x 3 1972/73river

6. Godawari Private Run-of- 30river

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 nolater 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 42. Patan NEC Diesel 1,490 1,490 x 1

3. Hetauda NEC Diesel 4,470 1,490 x 34. Bharatpur NEC Diesel 600 250 x 2

100 x 15. Birganj Birganj Steam 1,6o0 1,600 x 1

Sugar Mill Diesel 272 272 x 16. Janalpur Janakpur Diesel 572 256 x 2

Cigarette 60 x 1Factory

7. Janakpur ED Diesel 750 250 x 3

Sub-total 11,454

Eastern Development Zone

8. Biratnagar EEC Diesel 1,434 1,023 x 1411 x 1

9. Biratnagar Biratnagar Steam 1,400 1,400 x 1Jute Mill Diesel 850 400 x 1

450 x 110. Biratnagar Raghupati Diesel 337 337 x 1

Jute Mill11. Dube Dube Straw Diesel 356 356 X 1

Board Co.12. Dharan EEC Diesel 200 130 x 213. Dharan British Diesel 1,200 400 x 3

MilitaryCamp

Sub-total 5,777

Western Development Zone

14. Bhairahawa Mahendra Steam 600 600 x 1Sugar Mill

15. Bhairahawa ED Diesel 500 250 x 216. Butwa' BPC Diesel 22517. Tansing ED Diesel 305 140 x 2

25 x 11a. NepaTh,un, ED Diesel 500 250 x 21?. Krishnanagar ) Diesel 135 140 x 1

25 x 1Sub- tota! 2,295

NEPALTHE CENTRAL SYSTEM

POWER DEVELOPMENT PROGRAM

150 .,___._

140 - E

130 - _X 7 _B, ytMaximum Peaking Capacity

120 rN -_ - _

E 0i110 ~~~~~~~~~~~~~~~~~~~~~~~~Z \ vailable Peaking Capacity

4 10 in' l rySeason

<

80~~~~~~~~~~~~~~~

902

go System Peak Load0 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)

NEPALELECTRICITY DEPARTMENT

ORGANIZATION CHART

CHIEF ENGINEER

DEPUTYCHIEF 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 ZONALRU-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

ZONALSUB-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 CORPORATIONORGANIZATION 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 8Page 1

NEPAL

KULEKHANI HYDROELECTRIC PROJECT

Project Description

General

1. The Kulekhani river originates in the Mahabarat mountain rangeabout 5 km west of Palung and 30 km southwest of Kathmandu. It flowsgenerally in an east-southeast direction and joins the Bagmati riverabout 20 km south-southwest of Kathmandu.

2. The catchment area above the damaite is about 126 sq. km. Inthe upstream reach, the valley is rather open and the slopes are generallystable with good vegetation cover. From the damaite to Kitini, the riverflows 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 inclinedimpervious core, about 107 m in height and with a crest length of about420 m. The crest elevation is 1,534 m which will provide a free board of4 m above the normal full water level of 1530 m. The total embankment ofthe 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 isintensively fractured. The thickness of the fractured rock zone (20 m -45 m) decreases toward upstream. The only conceivable type of dam at thesite is a fill-type dam. As sufficient granite is available in the vicinityof the dam and earth material is limited, a rockfill dam has been chosen.The inclined core type is adopted because it requires less excavation thanthe center core type to set the foundation of the core portion on the firmrock. The dam will have an upstream slope of 1:2.5 and downstream slope of1:1.7.

Spillway

5. The spillway will be located on the left abutment. It will be anopen channel chute type structure with a flip bucket provided at the lowerend. Two radial gates 11 m high and 9 m wide will be installed to controlthe discharge. The spillway is presently dimensioned to pass a flood of

ANNEX 8Page 2

31300 m /sec, but this will be checked in the detailed design stage throughthe study of maximum probable flood by the unit hydrograph method and throughflood-routing of the reservoir.

Intake Structure

6. The intake will be located on the right bank about 200 m upstreamof 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 atEl. 1471 m. In view of the difficulty in estimating reservoir sedimenta-tion, provision will be made so that the plant could still be operable evenif sedimentation would raise higher than the expected deposit level.

Headrace Tunnel

7. The pressure headrace tunnel, about 5.8 km in length, will be ofcircular cross section with an inside diameter of 2.5 m, about the practicalminimum size for effective construction. It will be concrete-lined. Noproblem is expected during construction with the exception of the upstream600 m and a downstream portion near the surge tank where the tunnel maycross a fault; heavy support may be required.

Surge Tank

8. The surge tank will be a chamber type with upper, lower and middlechambers and a surge shaft. The upper chamber will be a circular tank andthe 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 theupper 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 thepipe will decrease gradually from 1.9 m at the upper end to 1.25 m at thelower end. The lower penstock tunnel will also be used as the cable ductand the ventilation shaft for the underground powerhouse.

Powerhouse and Switchyard

10. The underground powerhouse is designed to house 2 units of 30 MWeach. It will be 43 m long, 14 m wide and 26.2 m high, consisting of mainmachine room, control room, repair workshop, storeroom and station serviceunits. The inlet valve will be located in the main machine room for easein erection and maintenance.

11. The switchyard, located on a terrace near the entrance of thelower penstock tunnel, will have the station control room so that the powerstation will normally be operated from outdoors.

ANNEX 8Page 3

Generating Equipment

12. The turbine will be of the vertical-shaft pelton type with fourjets, rated at 41,035 hp (30,600 kW) under a head of 550 m and a dischargeof 6.55 m3 /sec. The rated speed will be 600 rpm. The runner center willbe 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 typerated at 35 MVA. The high voltage windings will provide 66 kV and 132 kVterminals. It will be installed in the outdoor switchyard.

Transmission Line and Substation

15. The existing 66 kV double circuit transmission line betweenKathmandu and Birganj via Hetauda will be utilized to transmit Kulekhanioutput. The outdoor switchyard will be connected to the existing line bya 200 m long branch.

16. Two 35 MVA transformers will be added at the existingsubstation at Kathmandu consistent with the installation of generating units.

Tailrace Tunnel

17. The tailrace outlet will be located at the left bank of the Manduriver about 500 m upstream from its confluence with the Rapti river. Atailrace tunnel about 1.0 km in length will be constructed between theunderground power station and the outlet.

Tributary Diversion

18. A tributary intake will be constructed to divert the flow of Simriver from a catchment area of about 7 sq. km. It will consist of an intakeweir, an inlet, a desilting basin and a vertical shaft into the headracetunnel. Design will allow free air passage.

19. The Chakhel river, another tributary of the Kulekhani river witha catchment area of 23 sq. km., will be diverted to the Kulekhani reservoirthrough a connecting tunnel, about 2 km in length. The tunnel will be freeflow, 1.8 m in height and in width.

Schedule of Implementation

20. The Implementation Schedule is outlined in Annex 11. 1975 is the yearfor the appointment of consultants and the commencement of detailed investi-gation and construction of the access road to the damsite. Engineering designand preparation of tender documents for civil works will be started in

ANNEX 8Page 4

January 1976. Tender documents will be issued by July 1976 and contractawarded before the end of 1976. Excavation of diversion tunnel will becommenced by March 1977 which will allow about 39 months to complete themain dam. Excavation of headrace tunnel, tailrace tunnel and the accesstunnel leading to the underground powerhouse should be started about thesame time as the diversion tunnel. About 3 years will be required for theheadrace 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 tobe commissioned by end 1979/80 and the second unit by end 1981/82 or possiblyat an earlier date with a view to providing adequate system reserve capacityand to save project investment as a whole, if financing could be arranged.

Basic Data

21. The following table summarizes the principal features of theproject:

(1) Water Sources

RunoffCatchment 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

3Effective storage capacity: 73,300,000 in

ANNEX 8Page 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 reservoirhigh 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 8Page 6

(d) Penstock

Diameter: 1.6 m (mean)

Length: Open portion: 910 mUndergroundportion: 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, singlerunner-4 jets

Elevation ofrunner 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 shaftsynchronous alternator

Rated Capacity: 2 x 35,000 kVa

Voltage: 11 kV

ANNEX 8Page 7

Cycle: 50 Hz

Power factor: 0.85

(iii) Main transformer

Type: Oil immersed natural-coolingoutdoor

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 connectwith 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

NEPALKULEKHANI 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 DisbursementFiscal Year and Quarter at end of Quarter

(Thousands of US$)1977

March 31, 1977 3,300June 30, 1977 3,700

1978

September 30, 1977 4,300December 31, 1977 5,300March 31, 1978 6,300June 30, 1978 7,300

1979

September 30, 1978 8,300December 31, 1978 9,800March 31, 1979 12,300June 30, 1979 15,300

1980

September 30, 1979 17,500December 31, 1979 19,,500March 31, 1980 21,500June 30, 1980 23,509

1981

September 30, 1980 25 ,000December 31, 1980 26,000

NEPALKULEKHANI 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 WORKSCHAKHEL INTAKE .

Manufacturing and TransportationMETAL 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 12Page 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 damsiteis about 126 sq. km. Two downstream tributaries will be diverted into thereservoir or the headrace tunnel directly: namely the Chakhel river andthe 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 influenceof the sub-continental climate pattern and has two distinct seasons: thewet summer monsoon season which lasts from June to September and the drywinter season. During the wet season, the SW monsoon prevails, bringinga 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 monthlyminimum temperature at Kathmandu are 18.3'C, 30"C and 2"C, respectively. Thetemperature reaches maximum in May, occasionally rises up to about 35'C. Thecoldest 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 mmin the upper reach (based on eight years record at Daman) and 1350 mm inthe 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 1963at the proposed damsite. There is also a gauging station in the vicinityof the project area at Chobhar on the Bagmati river. Its observationrecords cover the period of 10 years from 1962 to 1971. The runoff recordat this station has been used to check the reliability of the runoff observa-tion at Kulekhani damsite. In addition, the runoff of the tributaries, theChakhel and the Sim, were measured from 1966 to 1973 at the proposed intakeweir sites.

ANNEX 12Page 2

6. The average annual runoff at the"damsite over the observationperiod is about 123 million m3 or 3.9 n3/sec in annual mean. The specificrunoff is calculated at 3.1 m3 /sec/100 sq. km. The rating curve establishedis considered to be reliable. The correlation between the annual averagerunoff and annual average rainfall within the catchment area is also'good.

7. The runoff records of the Chakhel and the Sim rivers have beenextended for the period from 1963 to 1972 by correlating the measured flowdata with the corresponding records at the Kulekhani damsite. The averageannual runoff for these two tributaries are estimated at 22.4 million m3and 11.8 million m3, or corresponding to an annual mean discharge of 0.71m3/sec and 0.37 m3/sec, respectively.

Flood Flow

8. The largest recorded flood at the Kulekhani damaite is 572 m3/secwhich occurred on July 16, 1970. Based on the past recorded annual floodpeaks over the period from 1963 through 1972, the probable flood peaks fordifferent 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 Koeicorresponds only to the 200-year flood by Iwai's probability method whichis rather low, especially taking into consideration the short duration ofthe flow record. ED agreed that at the time of detailed design, the adequacyof the spillway capacity will be checked by a study of the maximum probableflood and a flood routing through the reservoir by the consultants.

Sedimentation

10. The annual sediment at the proposed damsite is estimated byNippon 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 12Page 3

it will provide enough capacity over the project's estimated life of100 years.

11. ED agreed that the above estimated figure be checked agsin by theflow duration and sedi*ent rating curve method based on actual moeasurement,before finalizing the detailed design of the intake structure.

ANNEX 13Page 1

NEPAL

KULEKHANI HYDROELECTRIC PROJECT

Geology

General

1. The geology of the region can be divided into three formationsaccording to the chronological order:

(1) metamorphosed sedimentary facies;

(2) granitic rock intruding into the said sedimentaryfacies; and

(3) sedimentary rocks of the Tertiary Siwalik formation.

2. Metamorphosed sedimentary facies consist of sandstone and sandysemi-schist, quartzite, slate, phyllite, biotite schist, graphite schist,calcareous schist, crystalline limestone and their alternation. Theserocks are generally bluish or graying dark colored, except for whitequartzite or highly siliceous sandstone, and strongly bedded. Most ofquartzite, siliceous sandstone, slate, crystalline limestone and sandstoneare fairly hard, whereas others are moderately hard. The Kulekhani areain the northern side of the granite ridge is composed of rather thin alter-nating sandstone and slate groups and partial calcareous rocks, showing ageneral strike of NNW-SSE and a dip of NE. The southern area of thegranite ridge is mainly composed of metamorphosed sedimentary facies oflower Paleozoic Age, showing a general strike of NNW-SSE, but dippingN-S (an indication of foldings). The rock between the granite ridge andthe 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 Kholalocated about 3 km north of Hetauda.

3. Granitic rock mass is mainly composed of biotite-muscovite granitewith large crystals of potash feldspar. It forms the ridge of Daman, rising2,500 m high above sea level. Tertiary Siwalik formation is composed of mod-erately consolidated sandstone and shale alternation. However, it is notpresent 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 13Page 2

calcareous sandstone and slate, phyllite, crystalline limestone, etc. Twofaults, striking nearly parallel to one another and parallel to the courseof the Kulekhani river in the lower reach of the reservoir area fromBazarmath to Burichaur strike NW-SE and dip NE. These faults run alongthe boundary between sandstone and the alternating formation of sandstoneand slate.

5. Two problems are important in reservoir geology, one is thestability of bank slope and the other, the possibility of leakage throughthe basal rock of the reservoir. Due to the geological structure, theright bank is more viable to landslide than the left but only small-scalelandslides can be observed. There are many small talus 'eposits alongboth 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 thedam less than 1 km away and the fault which appears on the right bank ofthe 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 ofwater along the river bed, no sink holes or solution cavities are found,water leakages by pressure test are of normal magnitude through cracks ofordinary rock formation and the fractured zone of the fault is only 50 cmto 100 cm in width.

Damsite Geology

7. The foundation rock of the Kulekhani damsite is composed of sandysemi-schist, biotite schist and phyllite, strongly bedded with a commonstrike 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 theright bank rises at an inclination of 1:1.2 to 1:1.7, whereas the leftbank forms a very steep cliff inclining at 1:0.3 to 1:0.6 up to El. 1530 mwhere the rock bed outcrops. On the right bank, rock is exposed in thelower 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 avoiddeep excavation.

8. The right abutment is covered with 2.5 m - 3 m thick of talusdeposit composed of earth and rock fragments and a fractured rock zone ofvarious thicknesses. Four test adits will be excavated in the detailedinvestigation stage, three along the foundation of the impervious coreand one in the downstream area of the right abutment.

9. River deposit at the damsite ranges from 2 m to 6.5 m and biotiteschist underlying the river deposit is partly sheared and weathered to adepth of about 13 m. 5 grouting holes with a total length of 300 m willbe drilled and tested during further investigations along the foundation ofthe impervious core.

ANNEX 13Page 3

Spillway

10. At the left bank where the spillway is to be located, the toplayers of 'the base rock are covered'by a talus deposit of 5 to 10 m. Thesetop layers are intensively weathered to a depth about 10 m, underneath whichthe 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 excavatedrock can be utilized as embankment material of the dam.

Intake

12. The intake site is composed of sandstone and sandy schist coveredwith 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 granitefor 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 thefractured zone on the right bank of the damsite, heavy support will berequired. In the middle section of 2400 m, no problem will be encounteredthrough the massive granite formation. In the downstream portion of 2800 malso no problem will be expected except in the downstream-most portion nearthe surge tank where the tunnel may cross a fault and heavy support will benecessary for a length of about 300 m.

Surge Tank

15. The last stretch of the headrace tunnel will pass through analternating formation of sandstone and slate. A fault runs just upstreamof 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 inthe sandstone formation. The location of this fault will be confirmed byseismic exploration and drilling in the detailed investigation stage.

Penstock

16. The penstock line will be situated on the sandstone formationabove 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. Generallysound rock condition is expected except at the top of the slope.

ANNEX 13Page 4

Underground Powerhouse

17. The proposed underground powerhouse site is situated among thealternating sandy semi-schist, sandstone, biotite scliist and slate. Sandyrocks are generally hard to moderately hard. Biotitg schist and slate aremoderately hard and rather friable with intensive foliation. Nevertheless,the bedding of the sandstone is much thicker and dominating than that ofslate. The beds in the vicinity of the area show strike trending NW-SEand 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 undergroundpowerhouse 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 thealternating formation of sandstone and schist and the lower half mainlyin the solid sandstone formation, dipping 250-45° NE. Though the rockbeds 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 rockon the right abutment by adits;

(c) Seismic exploration and drilling in the surgetank 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 bya study of the maximum probable flood and aflood routing through the reservoir; and

(b) Estimate of reservoir sedimentation to bechecked by the "flow duration sediment ratingcurve 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 MWhFiscal 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 GrossPeak 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 22,5201974/75 30,430 13,390 - 39,250 37,820 32,770 2,340 22,5201975/76 35,227 16,557 - 39,250 37,280 32,770 -2,457 22,5201976/77 44,734-/ 21,920 Gandak + Interconnection 15,000 + 2,346 57,046 46,916 41,866 -2,868 27,3771977/78 52,170 26,085 - 57,046 46,916 41,866 -10,304 27,3771978/79 57,798 29,477 Devighat 14,100 71,146 61,016 55,966 -1,832 37,8771979/80 64,316 33,444 Kulekhani No. 1 30,000 101,146 91,016 85,966 21,650 56,6271980/81 71,677 37,272 - - 101,146 91,016 85,966 14,289 56,6271981/82 78,167 40,647 - - 101,146 91,016 85,966 7,799 56,6271982/83 85.551 44,486 Kulekhani No. 2 30;000 131;146 121;016 115,966 3fli415 56,6271983/84 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 FirmHydro Installed Peaking Capacity in dry season Output

Pharping 500 500 400 200Sundarijal 640 700 700 600Panauti 2,400 2,400 1,500 700Trisuli 18,000 18,000 18,000 12,000Sunkosi 10,050 10,050 6,000 4,700Diesel 7,660 6.170 6,170 4.320

Total 37,820 32.770 22,520Capacity of new additions (kW):

Lumbini Interconnection2,346 2,096 2,096 1,357Gandak 15,000 7,000 7,000 3,500Devighat 14,100 14,100 14,100 10,500Kulekhani No. 1 30,000 30,000 30,000 18,750

Source: Electricity Department, Ministry of Water and Power.

ANNEX 18Page 1

NEPAL

KULEKHANI HYDROELECTRIC PROJECT

The Least Cost Solution

Alternatives to the Prolect

1. The alternatives to the Kulekhani Hydroelectric Project would beeither a thermal development or a different hydro facility providing thesame service. However, no other hydro projects have advanced to such astage 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 isKulekhani 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 builtwithout 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 atleast two years from now.

2. The alternative to Kulekhani is therefore a thermal developmentlocated at Birganj near the border with India. To confirm that Kulekhaniis 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 twounits in sequential construction.

Alternative (1) - 1 - 30 MW coal-fired thermal unitfollowed by 2 - 15 MW gas turbines.

Alternative (2) - 1 - 30 MW heavy oil-fired thermalunit followed by 2 - 15 MW gasturbines.

Alternative (3) - 6 - 5 MW diesel units firing heavyoil followed by 2 - 15 MW gasturbines.

Alternative (4) - 1 - 30 MW coal-fired thermal unitfollowed by another 1 - 30 NW coal-fired unit.

Alternative (5) - 1 - 30 MW heavy oil-fired thermalunit followed by another 1 - 30 MWoil-fired unit.

ANNEX 18Page 2

General Assumptions

3. The comparison among alternatives were made on a constant valuebasis (1974 price level) and with costs net of duties and taxes. Assump-tions used in this analysis are summarized below:

AlternativesCoal- Oil-

Kulekhani fired fired Gas DieselHydro Thermal Thermal Turbines Units

(1) Plant Data

lst unit 30 Mhr 30 MW 30 MW - 6- 5 MW2nd unit 30 MI 30 MW 30 MW 2 -15 MW -

(2) Capital Cost(US$ million)

1st unit 42.5 16.5 14.4 - 9.02nd 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 peakingInvestment) operation

only)

(5) Heat Rate - 12500 12500 15500 11500(Btu/kWh)

(6) Type of Fuel - Coal Heavy Distillate Heavyoil 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 18Page 3

Results of Comparison

4. The equalizing discount rates between Kulekhani Hydro and otheralternatives were found to be as follows:

Equalizing DiscountRate

(1) Alternative 1

1 - 30 MW coal-fired thermal unit followedby 2 - 15 MW gas turbines 12.95%

(2) Alternative 2

1 - 30 HW oil-fired thermal unit followedby 2 - 15 MW gas turbines 17.65%

(3) Alternative 3

6 - 5 MW diesel units followed by 2 - 15 MWgas turbines 15.1 5%

(4) Alternative 4

1 - 30 MW coal-fired thermal unit followedby another 30 MW coal-fired unit 14.55%

(5) Alternative 5

1 - 30 MW oil-fired thermal unit followedby another 30 MW oil-fired unit 18.55%

5. The Kulekhani Hydroelectric Project was found to have a lowerpresent worth of costs at discount rates up to 12.95% by even comparingit 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 equalizingdiscount 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 atKulekhani ultimately. This demonstrates that the second unit should beinstalled in accordance with the system demand.

Sensitivity Tests

7. Sensitivity tests for changes in capital costs and fuel costs incomparing Kulekhani with two most feasible Alternatives (1) and (4) havebeen made. The results of the tests are summarized as follows:

ANNEX 18Page 4

Alternative (1) Alternative (4)

(1) On main assumPtions 12.95% 14.55%

(2) On less favorable assumptions

(a) Kulekhani capital costincreased by 10% 11.35% 12.25%

(b) Thermal units capitalcost 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 costreduced by 10% 15.15% 17.85%

(b) Thermal units capitalcost 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 18Page 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 19Page 1

NEPAL

KULEKHANI HYDROLLECTRIC PROJECT

Return on Investment

General Assumptions

(a) Plant Data

InstalIed Capacity 2 x 30 MW

Energy Output

Primary Energy 165 GwhSecondary Energy 46 OwhContribution to existing hydro plants 88 Owh

Total 299 Gwh

Life of Plant 50 years

(b) Project Cost (1974 price level) US$ Million

Foreign 37.6Local 8oTMotal 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 1.9Tariff in 1980/81 Current 509(6% rate of return) Real 3.5

Export

Primary Energy 1.5Secondary Energy 1.0

November 1975

NEPhL

KULEKHANI HYDROELECTRIC PROJECT

Unit: US$1,000Return on Investment

Cost Streams Benefit StreamsDistribution FuelSystem O&M Other Cost Domestic Export

Year Project Cost Expansion Cost Cost Total Savings Sales to India TotalC 1 C 2 C3 C C B 1 B 2 B3

1976 1,800 0 0 0 1,800 0 0 0 01977 5,500 0 0 0 5,500 0 0 0 01978 12,700 0 0 0 12,700 0 0 0 01979 15,500 0 0 0 15,500 0 0 0 01980 8,000 720 0 0 8,720 0 0 0 01981 1,600 720 640 220 3,180 540 560 3,567 4,6671982 1,000 720 640 265 2,625 540 1,070 2,917 4,5271983 0 800 640 315 1,755 540 1,657 2,471 4,6681984 0 800 640 370 1,810 540 2,297 1,874 4,7111985 0 800 640 425 1,865 540 2,962 1,268 4,7701986 0 800 640 485 1,925 540 3,673 634 4,8471987-2012 0 0 640 515 1,155 540 3,828 460 4,8682013 2,000 0 640 515 3,155 540 3,828 460 4,8682014 2,000 0 640 515 3,155 540 3,828 460 4,8682015 4,000 0 640 515 5,155 540 3,828 460 4,8682016 1,600 0 640 515 2,755 540 3,828 460 4,8682017 1,000 0 640 515 2,155 540 3,828 460 4,8682018-2025 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/Kwhand 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 PresentCosts 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 SalesOandak 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

910.7Note. 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 royaltyand income tax.

Equivalent to USC 3.8/Kvh3/ 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

NEPALNEPAL ELECTRICITY COLRPORATION

SCH-EDUJLE OF CURRENT TARIFFS BY CLASS OF CONSUMERS

A. Domestic ConsumersMin. 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)

EstimatedActual 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 97.61 140.78 211.00 215.50 273.63 526.09 526.97 538.00Diesel Gwh 0.08 .06 .05 9.80 2.00 11.34 11.34 26.59 11.34 - -Supplied by Mprt (New Plant atSunboai 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 Officeand 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 87.12Energy 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 96.67Revenue from .tucre tariff increases- - - - - 3.91 22.96 48.64 54.53 66.72 117.38 130.58 145.39Miscellaneous 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 50.36Fuel-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 36.61Purchase 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 91.31 124.92 135.20 148.75Operating 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 94.34Less: lnterest - - - -- - 2.37 2.33 2.28 54.87 54.06 53.16Dividends 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 andStations tine) as , of Operation 32 52 34 28 28 27 27 26 24 22 21 20

Rate Sane (Average Net Assets inOperation) 85 103 123 125 244 328 499 492 652 1,444 1,418 1,453

Rate of ReturnOperating 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 6.5Operating RatioOperating Expenses as 7. of Revenues 97 92 98 108 93 82 76 80 77 59 60 61Average 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

NEPALNEPAL 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 23.6Industrial 24.50 6.40 25.6 38.64 9.89 25.6 49.20 12.59 25.6 59.73 15.29 25.6Comsercial 8.33 2.00 24.0 12.89 3.09 24.0 15.70 3.77 24.0 19.13 4.59 24.0Export to India 5.84 1.08 18.5 12.26 2.27 18.5 17.52 3.24 18.5 17.52 3.24 18.5Street Lighting 1.65 0.23 14.0 2.00 0.28 14.0 2.42 0.34 14.0 2.85 0.40 14.0Lumbini 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 23.4Less Load Shedding (1.44) 0.34 - (4.88) (1.15) - (7.46) (1.76) - (15.91) (3.75) -RebateNet 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 23.6Industrial 74.15 18.98 25.6 84.15 21.51 25.6 92.75 23.74 25.6 101.35 25.94 25.6Commercial 23.30 5.59 24.0 28.33 6.80 24.0 34.50 8.28 24.0 42.02 10.08 24.0Export to India 17.52 3.24 18.5 17.52 3.24 18.5 17.52 3.24 18.5 17.52 3.24 18.5Export to India - - - 159.70 29.54 18.5 131.14 24.26 18.5 98.72 18.26 18.5Export to India - - - 33.80 1/ 4.29 12.7 33.80 4.29 12.7 41.39 5.26 12.7Street Lighting 3.40 0.48 1.40 3.97 0.56 14.0 4.56 0.64 14.0 5.25 0.74 14.0Lumbini 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 21.4Less 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 _ - 8.20Office 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) TransferredYear 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

3 3K(vyLem y - 1.50 - - - - July 1975132 Kv Transmission (Gandak-Hetauda) - - - 56.00 - - - July 1977

Generation Plant

Devighat Hydroelectric Plant - - - 167.00 - - - July 1979Gandak Hydroelectric Plant (14 MW) - - 98.00 - - - - July 1977Trisuli HE (2nd Stage) - - 126.00 - - - - - July 1975Sunkosi HE Project - - - 110.00 - - - - July 1978Kulikhani HE Project 1 60 MW - - - 810.00 - 63.00 - July 1980and 1982Kulikhani HE Project Ii - - - - - - - - - 50.00

Sub-totals - - 127.50 154.00 110.00 167.00 810.00 - 63.00 50.00Expenditure 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 1,648.68Less: Depreciation (16.12) (19.126 (23.76) (28.83) (36.66) (44.74) (69.89) (84.30) (102.43) (137.10) (172.41) (209.021Net 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 1,439.66Work 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 1,439.66Investments 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 6.86Stores 3.81 3.75 4.71 5.00 5.50 5.50 5.60 7.30 14.50 14.50 15.00 17.00Accounts Receivable (Consumers) 3.77 4.84 5.28 2.55 4.20 5.60 7.20 9.00 11.00 26.00 28.00 30.00Accounts Receivable 2.92 5.28 3.97 4.00 3.50 3.50 3.80 4.00 4.20 5.00 5.00 5.00Total - Current Assets 12.85 17.03 17.01 14.31 14.90 16.59 20.53 23.85 31.99 48.37 52.28 55.40Advances to hlMN towards Construction

of Plant - - - - 4.48 - 23.00 42.00 - 30.00 14.00 67.00Total - 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 95.25 131.99 131.27 131.27 261.97 359.97 458.97 625.97 625.97 625.97 625.97 625.97Capital Reserve 1.65 2.36 3.44 4.14 4.64 5.14 5.64 6.14 6.64 7.14 7.64 8.14ocher Reserves 0.74 1.03 1.01 1.01 1.01 1.01 1.01 1.01 1.01 1.01 1.01 1.01Net Revenue Surplus (Accumulated) 0.17 0.83 0.82 1.82 0.05 (1.27) 8.78 27.67 45.02 69.72 101.49 137.86Net Revenue Surplus (Current Year) - 0.17 1.00 (1.77) (1.32) 10.05 18.89 17.35 24.70 31.77 36.37 41.18Total - 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 34.618-1/27 Loan from uNM. - - - 325.00 321.06 316.79 312.1665 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 2.20Accounts Payable 0.73 1.67 0.76 0.80 1.00 1.20 1.20 1.30 1.30 1.40 1.50 1.60Other Accounts Payable 0.27 3.70 4.87 3.22 3.02 3.50 4.00 4.00 4.00 4.00 4.00 4.00Dividends 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 7.80Total - Liabilities 101.32 143.05 144.76 141.69 271.57 420.40 538.59 723.00 1

4 8 9.

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 Assetsto 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 25Page 1

NEPAL

KULEKHANI HYDROELECTRIC PROJECT

NEPAL ELECTRICITY CORPORATION

Assumptions for Financial Projections

1. The financial statements in this report covers NEC's electricitysupply operations. They include Income Statements (Annex 22.1), Source andApplication 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 theaudited accounts for that year.

Income Statements

Energy

2. NEC's operating plant capacity will not be sufficient to meetthe winter peak demands in 1976 through 1979 despite considerable highcost diesel generation. Substantial load shedding is forecast. Systemlosses (including NEC office and station use) of 28% are assumed inFY 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 thatsurplus energy would be exported to India.

Tariffs

5. A tariff increase of about 74% is assumed from mid April 1976 toenable NEC to achieve a rate of return of 0.8% on its average net assets inoperation in FY 1975/76. This would be equivalent to a 2.5% return whencalculated as though the tariffs had been in operation and royalty had beendiscontinued (para. 8) from the beginning of the year. Subsequent tariffincreases of 38% from July 1977 and 28% from July 1980 are assumed to achieveinterim 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 employeespay by 8%. In subsequent years, operations and maintenance costs havebeen escalated by 20% in FY 1976/77, 15% in FY 1977/78, and 10% in each

ANNEX 25Page 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 theadditional cost of operations as the following plant is taken over by NECfor 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 ofNRs 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 yearprior to the completion of Kulekhani Project.

Other Assumptions

11. (1) Plant donated to HMG from external sourcesis assumed to be transferred to NEC as equity and newplant constructed by HMG for NEC transferred as debt.

ANNEX 25Page 3

(2) Debt created by NEC for plant financed with IDA fundsis assumed to be repayable over 25 years, with interestat 8-1/2%, the same as if the Bank were making a loanto finance the project. Debt in respect of plantfinanced by capital provided by HMG or other lendinginstitutions 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 HMGto help finance construction of projects being constructedfor NEC by ED.

Debt Service Calculations

12. (1) 6% Loan for Gandak Transmission Plant Transfer.Amount (Net) NRs 39.5 million repayable 25 years at6% interest. Debt Service = NRs 77,700 100 per millionor NRs 3.07 million p.a.

0/S Loan(Beginning Principal Annual

Year of Year) and Interest Interest Principal RepaymentNRs Million NRs Million NRs Million NRs Million

1977/78 39.50 3.07 2.37 0.701978/79 38.80 3.07 2.33 0.741979/80 38.06 3.07 2.28 0.791980/81 37.27 3.07 2.23 0.841981/82 36.43 3.07 2.19 0.881982/83 35.55 3.07 2.13 0.941983/84 34.61 3.07

(2) Kulekhani HE Project (1st Unit). Net amount of loancovering the part of the Project financed by Kuwait Fund,OECF, UNDP and HMG (NRs 417,000 million), 25 years at6% p.a. interest. Debt Service = NRs 77,700 permillion = NRs 32.40 million p.a.

O/S Loan(Beginning Principal Annual

Year of Year) and Interest Interest Principal RepaymentNRs Million NRs Million NRs Million NRs Million

1980/81 417.00 32.40 25.02 7.381981/82 409.62 32.40 24.58 7.821982/83 401.80 32.40 24.10 8.301983/84 395.50

ANNEX 25Page 4

(3) Kulekhani HE Project (1st unit). Net amountof loan covering part of the Project financed byIDA 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 RepaymentNRs Million NRs Million NRs Million NRs Million

1980/81 325.00 31.56 27.62 3.941981/82 321.06 31.56 27.29 4.271982/83 316.79 31.56 26.93 4.631983/84 312.16

Balance Sheet

13. Long Term Debt:

(1) Gandak Transmission Project:

NRa Million NRs Million

Cost financed by 1M1and others 56.00

Less: Advances by NECFY 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 byIDA Funds 325.00

Advances

Amount of Loan (at 8-1/2%) 325.00

(b) Part Cost financed by HMGand others 485.00

Less: Advances by NECFY 1977/78 (23.0)FY 1978/79 (19.00)FY 1979/80 (26.00)

(68.0)

Amount of Loan (at 6%) 417.00

ANNEX 25Page 5

Gross Assets

14. Values are normally on a basis of historic cost or reasonablevalue 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% ofannual revenue.

IBRD -10107R3NOVEMBER 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 AU 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 sB 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 PROJECTGENERAL 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 - < +< IW~~~ ~ ~ ~~~~~ ~~~ SI

.55 LASS GADD>/

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