Nepal - Kulekhani Hydroelectric Project

Document of The World Bank FOR OFFICIAL USE ONLY Report No. 6177 PROJECT PERFORMANCE AUDIT REPORT NEPAL KULEKHANI HYDROELECTRIC PROJECT (CREDITS 600-NEP AND 600-1-NEP) May 8, 1986 Operations Evaluation Department This document has a restricted distribution and may be used by recipients only in the performance of their official duties. Its contents may not otherwise be disclosed without World Bank authorization. THE WORLD BANK FOR OFFICIAL USE ONLY Washmgton. D.C. 20433 U.S.A. O91ce of D"ectfr-Cmnera Opeatn* Evaluatrn May 8, 1986 MEMORANDUM TO THE EXECUTIVE DIRECTORS AND THE PRESIDENT SUBJECT: Project Performance Audit Report on Nepal - Kulekhani Hydroelectric Project (Credits 600-NEP and 600-1-NEP) Attached, for information, is a copy of a report entitled "Project Performance Audit Report on Nepal - Kulekhani Hydroelectric Project (Credits 600-NEP and 600-1-NEP)" prepared by the Operations Evaluation Department. Attachment This document has a restricted distribution and may be used by recipients only in the performance of their official duties. Its contents may not otherwise be disclosed without World Bank authorization. FOR OFFICIAL USE ONLY PROJECT PERFORMANCE AUDIT REPORT NEPAL KULEKHANI HYDROELECTRIC PROJECT (CREDITS 600-NEP and 600-1-NEP) TABLE OF CONTENTS Page No. Preface .......................................................... £ Basic Data Sheet ........ iii Evaluation Summary and Conclusions ................................. v PROJECT PERFORMANCE AUDIT MEMORANDUM Background ................................................... 1 Project Implementation ........................................ 1 Landslide ............................................ 2 Movement in Dam 2.....................,....................... 2 Project Cost .............................................. 3 Project Financing ............................................. 4 Project Justification ......................................... 4 Cofinancing Experience ........................................ 5 Resettlement Experience ....................................... 6 Environmental Considerations .................................. 6 Tariffs ...........6.......................................... 6 Performance of Consultants ................................. 7 Conclusions ................ ............................. 7 Appendix A: Comments from the Kuwait Fund for Arab Economic Development 8...................................... 8 Appendix B: Comments from the Commission of the European Economic Communities ......................................... 9 Appendix C: Comments from the United Nations Develoment Program in Nepal ........................................... 10 PROJECT COMPLETION REPORT I. Introduction ........................................... 12 II. Power Subsector ........................................ 12 III. Project Formulation .................................*.... 13 IV. Project Implementation ................................... 20 V. Project Justification .................................... 28 VI. Project Impact ... .................................. 29 VII. Performance of the Bank and Borrower ..................... 29 VIII. Conclusion ..........................................***** 30 This document has a restricted distribution and may be used by recipients only in the performance of their ofical duties. Its contents may not otherwise be disclosed without World Bank authorisation. TABLE OF CONTNTS (Continued) Page No. ANNEXES: 1. Cost Estinate ....................... 32 2. Summary of Main Contracts ............ ................ 33 3. Operating and Financial Data .............................. 34 4. Income Statement ................................. .. 35 5. Balance Sheets ........................................ 36 6. Source and Application of Funds ........................... 37 7. Econoic Internal Rate of Return .......................... 38 PROJECT PERFORMANCE AUDIT REPORT NEPAL KULERHANI HYDROELECTRIC PROJECT (CREDITS 600-NEP AND 600-1-NEP) PREFACE This report presents the results of a performance audit of the Kulekhani Hydroelectric Project for which the Bank Group provided two credits totalling US$40.8 million: Credit (600-NEP) for US$26 million Vas approved on December 23, 1975, signed on January 9, 1976, and became effective on May 18, 1976; and a Supplementary Credit (600-1-NEP) was approved on May 10, 1979, signed on June 18, 1979 and became effective January 21, 1980. The credits for this project were the first lending operations of the Bank Group for the power sector of Nepal. They were made to His Majesty's Government of the Kingdom of Nepal (HMG), with the Electricity Department (ED) of the Ministry of Water and Power as the Executing Agency. Actual implementation was to be through the Kulekhani Hydro-Power Development Board, which reports to ED. Nepal Electricity Corporation (NEC)1/ was to be the ultimate beneficiary which would take over and operate the project upon completion. Although the appraisal indicated that the first generating unit was expected to be commissioned in June 1980, it was placed in service in March 1982, 21 months late. The Supplementary Credit was required to help cover the cost overrun, about 80% above the estimate. The Closing Date of Credit 600-NEP was extended from December 31, 1981 to December 31, 1982, although the last disbursement was made in January 1981. The Closing Date for Credit 600-1-NEP, orivinally December 31, 1982, was extended to December 31, 1983, but the last disbursement was actually made on December 20, 1982; an undisbursed balance of US$1,932 of this credit was cancelled. The project was cofinanced by the following agencies: Agency US$ Million Japanese Overseas Economic Cooperation Fund (OECF) 20.3 Organization of Petroleum Exporting Countries (OPEC) 10.3 Kuwait Fund for Arab Economic Development (KFAED) 24.9 European Economic Community (EEC) 3.0 United Nations Development Program (UhDP) 5.9 His Majesty's Government of the Kingdom of Nepal (HMG) 17.4 1/ On August 17, 1985, a new organization-Nepal Electricity Authority (NEA) was created by combining three other small power supply entities with NEC. - ii - The Project Performance Audit Report (PPAR) consists of a Project Performance Audit Memorandum (PPAM), prepared by the Operations Evaluation Department (OED), and a Project Completion Report (PCR) dated June 28, 1985, prepared by the South Asia Regional Office's Power and Transportation Division. The audit has looked into Bank reports, records and files,2/ and an OED mission visited the project site in November 1985. The results have been discussed with some of the staff associated with the project. The audit finds that, in general, the PCR describes the project experience in sufficient detail to support the lessons and conclusions which emerged and the PPAR generally sumarizes pertinent information contained in the PCR. The PPAM adds discussion about the construction schedule, however, because the audit considers that the appraisal was unrealistic. It also contains a brief description of how the operation of this new facility will be integrated into the existing system, includes current data not previously available, and covers some new topics. Following standard procedures, OED sent copies of the draft PPAR to the Government and the Executing Agency. Comments were received from KFAED, EEC and UNDP and these have been reflected in the report and attached as Appendices A, B and C, respectively. 2/ The Appraisal Report (No. 833a-NEP), dated November 25, 1975; the President's Report (No. P-1728-NEY), dated November 25, 1975; the Development Credit Agreement, dated January 9, 1976; the President's Memorandum IDA/R79-39, dated April 30, 1979; the Amendment to the Credit Agreement, dated June 18, 1979; Transcripts of the meetings of the Executive Directors when the credits were approved; correspondence with the Borrower; the PCR, prepared by the consultants; and internal Bank memoranda on project issues, - iii - PROJECT PERFORMANCE AUDIT BASIC DATA SHEET NEPAL KULEKHANI HYDROELECTRIC PROJECT (CREDITS 600-NEP AND 600-1-NEP) KEY PROJECT DATA Original Amended Actual or Item Plan Plan Reestimated (11/75) (06/79) Total Project Cost (US$ million) 68.0 115.9 /a 122.6 Overrun (Z) - - 80 Credit Amount (US$ million) 26.0 - 26.0 Supplementary Credit - 14.8 14.8 Disbursed - 40.8 Cancelled - - /b Date for Completion of Physical Components 06/80-06/82 10/81-06/82 03/82 /c Proportion Completed by Target Date 60% 60% 100% Internal Financial Rate of Return (%) 6.0 3.0 3.0 /d Financial Performance Fair Institutional Performance Fair Estimated and Actual Cumulative Credit Disbursements (US$ million) Association FY 1977 1978 1979 1980 1981 1982 1983 (i) Appraisal Estimate (11/75) 3.7 7.3 15.3 23.5 26.0 26.0 26.0 (ii) Actual 0 6.0 10.9 20.2 33.4 37.1 40.8 /e (iii) (ii) as % of (i) 0 82 71 86 128 143 157 /a Includes an estimated US$7.1 million equivalent in duties and taxes imposed after appraisal. /b US$1,932 were cancelled. TE The appraisal report forecast the first unit complete in June 1980 with the second 12 to 24 months later depending on system demand. Both were commissioned in March 1982. /d About 6% with tariff increases implemented in April and August 1985. 7Te The difference with the PCR is due to a difference it. the records of NEC on which the PCR is based and the disbursement data from the Bank's Loan Department as shown here. - iv - OTHER PROJECT DATA Credit 600-NEP Credit 600-1-NEP Original Plan Actual Original Plan Actual First Mention in Files - 05/--/74 - Appraisal - 12/-/74 - -- Negotiations - 10/--/75 - 04/--/79 Board Approval 06/75 12/23/75 - 05/10/79 Credit Agreemrnt Signed - 01/09/76 - 06/18/79 Effectiveness - 05/18/76 09/18/79 01/21/80 Closing Date 12/31/81 12/31/82 12/31/82 12/31/83 Borrower: Kingdom of Nepal Executing Agency: Ministry of Water and Power Follow-on Project: Name Marsyangdi Hydroelectric Project Credit Number 1478-NEP Credit Agreement Date 09/30/85 MISSION DATA Month/ No. of No. of Man- Date of Year Weeks Persons weeks Report Feasibility 12/73 - - - - Appraisal 11/74 2 2 4 11/25/75 Supervision I 07/76 2 2 4 08/24/76 Supervision II 02/77 1 2 2 04/14/77 Supervision III 12/77 1 2 2 02/09/78 Supervision IV 03/78 1 1 1 04/03/78 Supervision V 07/78 2 1 2 08/04/78 Supervision VI 02/79 2 2 4 04/04/79 Supervision VII 10/79 3 1 3 12/14/79 Supervision VIII 10/80 1 2 2 12/12/80 Supervision IX 04/81 2 1 2 06/16/81 Supervision X 02/82 2 2 4 05/06/82 EXCHANGE RATES (Nepal Rupees - NRs) Appraisal Estimate (1975) US$1 - NRslO.6 Average Intervening Years US$1 - NRa12.0 Project Completion (1982) US$1 - NRsl3.O FISCAL YEAR OF BORROWER July 16 - July 15 PROJECT PERFORMANCE AUDIT REPORT NEPAL KULEKHANI HYDROELECTRIC PROJECT (CREDITS 600-NEP AND 600-1-NEP) EVALUATION SUMMARY Introduction i. The partial funding of this 60 MW project in 1975 was the first lending operation of the Bank Group to the power sector of Nepal. The continuing need for electrical energy has been recognized by the Bank Group, resulting in further lending: Marsyangdi Hydroelectric Power Project (Credit 1478-NEP for US$107 million), and the Karnali Project Preparation (Credit 1452-NEP, US$11 million). At present, the Bank Group is considering the possibility of providing funds for the development of additional projects in the power sector, Bo as to meet the continuing increase in the demand for electrical energy. i. Electricity is distributed to consumers in Nepal through a number of separate isolated transmission systems, the largest being the area around Kathmandu, commonly referred to as the Central Nepal Power System (CNPS), The Kulekhani generating station is one of the sources of electrical energy for CNPS. Objectives iIi. The prime objective of the project was to construct a facility to satisfy the expected demand for electrical energy in the CNPS by 1980, which-based on the Government's fifth Five-Year Plan-was expected to grow at an average rate of 14% until 1984 (SAR,1/ 4.02; PCR, 3.01). The project contained no formal institutional objectives. However, through association with consultants and contractors, it was expected that Nepalese engineers and technicians would be trained in the handling and management of major hydro- electric power developments and build up staff for future projects (President's Report, 33). A further objective, through the condition of effectiveness on tariff increases, was to improve NEC's financial performance (SAR, 6.07). The Project iv. The project, about 30 km from Kathmandu, consists of a rock-fill dam and spillway on the Kulekhani River, 114 m in height, creating a reser- voir with 73 million m3 of storage. Water is taken from the reservoir to t7ie powerhouse, through an intake, a tunnel, 5.8 km in length, and a 1,335 m long 1/ Staff Appraisal Report. - vi - penstock. Electric power from the underground powerhouse's two 30-MW electric generating units is transmitted at 66 kv from the switchyard to an existing transmission line only 5 km away (PCR, 3.03). Results v. Although tht project was completed and is now operating success- fully, the scheduled completion date for the production of power, June 1980, was not achieved. The two 30 MW units were placed into service for the first time in March 1982, 21 months after the target date (SAR, 4.09; PCR, 4.06; PPAM, 3). About eight months of the delay was attributable to a late call for tenders, and a subsequent controversy over the acceptance of the low tenderer. A further delay of 13 months occurred during the tunnel construc- tion (PPAM, 4). vi. The most significant effect on the CNFS resulting from the comple- ton of the project, is the ability to meet the peak demand, particularly .uring the winter months when the combination of lighting, cooking, and heating cause the evening peak to rise about 20% above the summer peak demand. The other six hydro plants in the system (total 37 MW) are run-of- river plants, and with no reservoirs, their output is reduced considerably during the dry season. At this time, Kulekhani, with its 73 million m3 of live storage, is able to supply the demand. During the summer monsoon period, the smaller plants are operated at full capacity, while the output from Kulekhani is curtailed so as to ensure the filling of the reservoir. The five diesel stations (total 18 MW) are now used only in emergency situations. vii. The forecast that additional electrical energy would be needed was correct, and because the project failed to meet the target date, NEC was forced to continue a program of shedding load during peak periods, as well as curtailing the connection of new consumers. Indeed, load shedding began in the 1978/79 period and it is estimated that up to 16 MW of load (15% to 20%) was disconnected from the transmission grid during the peak periods until the units were placed in service (PCR, 5.02). During 1981/82 (the year of commissioning), the demand for energy in the CNPS was 211.2 Gwh while by 1984/85, the demand had risen to 333 Gwh, an average annual increase of about 16%. Kulekhani provided 105 Gwh (32%) of the total requirements in 1984/85. viii. During the general scarcity of electrical energy (1978/79 to 1981/82), the number of consumers in the CNPS rose from 83,120 to 103,141, an average annual rate of about 6,700. However, with the availability of Kulekhani, the number of consumers rose to 150,000 (provisional figure) during the period 1981/82 to 1984/85, an average annual increase of about 15,600. The present program foresees the connection of 25,000 new consumers annually. ix. The effect of the storage on the system will be greatly enhanced when the Kulekhani II project (32 MW) (funded by OECF) comes into service at the end of 1986. It draws its water supply from the tailrace of the project, and will utilize the same stored water. - vii - x. The rate of return on investment for this project (3%), was well below a desirable level. Even with the significant increases in tariff in 1985 (PCR, 5.03; PPAM, 22), the rate has been computed to be about 6%, equal to the appraisal forecast but still less than the 8% to 10% normally expected for Bank Group financed projects of this type. xi. The construction of the various facilities has disturbed the envi- ronment in the immediate area, but HMG has taken care to resettle the dis- placed persons (PCR, 3.11; PPAM, 18) and with the help of lending agencies, has embarked on a program of reforestation and soil conservation (PPAM, 20). As pointed cat by UNDP (Appendix C, Item 4), however, it is clear that the initial project design did not take full cognizance of soil conservation and watershed management problems. Sustainability xii. Two critical factors determine whether the benefits which may accrue from this project would be sustained over the potential useful life (35 to 50 years) of the project: the quality and technical competence of the operating and maintenance personnel, and the availability of foreign exchange for the purchase of replacement parts subject to normal wear, or for items which may be damaged through accident, and adverse weather conditions. xiii. NEC had no formal training program during the project construction period. However, 14 officers, including 12 engineers, visited the offices of the consultant (54 man-months), where they were instructed in design and construction activities, while operation and maintenance personnel received on-the-job training during the erection and commissioning of the equipment (SAR, 4.08; PCR, 6.02). One of the agreements reached with NEC for the Marsyangdi Hydroelectric Power Project was that a plant maintenance program would be furnished to IDA by March 31, 1985, but this has not been received.2/ xiv. With regard to spare and replacement parts, the contracts for the various items of equipment contained clauses requiring the delivery of suffi- cient spares to last about five years. Some have been used in the past three years, and NEA will have to find the funds required for the purchase of additional parts when needed. xv. Since commissioning, there have been two landslides which could have affected the sustainability of the project benefits. A major slide occurred near the intake in November 1983, while the reservoir was being filled. The repairs now underway are scheduled to be completed by April 1986, at a cost of about US$2.6 million (PCR, 4.14; PPAM, 6). A second slide near the valve house at the end of the headrace tunnel occurred during August 1985, but posed only a minor threat to the installations. Instruments have been installed to detect any further movement and the consultant is expected to visit the site in January 1986, to make recommendations on the course of action to be taken in order to prevent further deterioration in the area.3/ 2/ See also Appendix C, Item 2. 3/ See also Appendix C, Item 4. - viii - xvi. Initially, the appraisal expressed concern about the possibility of silt building up in the reservoir to an extent that would interfere with the intake (SAR, 4.11). However, considering that the river empties into the lake about 10 km upstream of the Intake (at high water), that there is dead storage of about 12 million i3, and that the sill of the intake is more than 30 a above lake bottom, the possibility of blockage which would limit the benefits seems negligible. xvii. The operation of the generating station would soon be interrupted if adequate access to the various facilities were not maintsined. Thus, using surplus funds from the OECF loan, NBC purchased US$400,000 worth of equipment from the civil contractor for the maintenance of about 50 km of gravel roads under its jurisdiction* This is a continuing operation, partic- ularly during the monsoon season. Findings xviii. In view of the cost increase (80% above estimate) and the long delay in completion (21 months), this audit finds that the execution of this project was below the standards set for the average hydroelectric project financed by the Bank Group. The main cause appears to have been insufficient preparation due to inadequate field investigations and sub-surface explora- tion. Nevertheless, when completed, the expected power and energy output was achieved and the facilities are operating in a satisfactory manner. New consumers are being served, and the existing consumers are enjoying a reliability in service that was never achieved previously. xix. Although there were no formal institutional targets, the NBA staff, both technical and administrative, gained considerable experience in project management e-id administration, which is being used to good advantage now on succeeding projects (PCR, 6.02). xx. The experience gained on this project indicates that an allowance of only six months in the schedule (PPAM, 3), between the call for bids and award of contract, was not reasonable in the light of the size and remoteness of the project, the time required for the analysis of bids, and the required approvals of the owner and lending agencies. The construction schedule also appears to have been optimistic, and should have been extended to take into account the difficulties associated with work in a land-locked country. Conclusions xxi. T spite of delays and cost overruns, the project's target was eventually achieved and it can now be considered a successful endeavor, except for current financial returns. xxiis The audit concludes that although the cost of this project was high, NEA now has an efficient reliable facility, and in general, all proj- ects except the very large scale developments, will continue to have high unit costs (PPAM, 24-25). Also, while the economy of Nepal has deteriorated in the past three years, the industrial sector has performed better than average, with a significant increase in output, partly as a result of a better electricity supply (PPAM, 26). - ix - Lessons Learned xxiii. Some of the lessons learned on this project are already in effect in many Bank Group operations of similar complexity. Notable among these are: (a) do not appraise until reasonably precise field information is available and the detailed design stage is completed; (b) approve the loan after receipt of civil tenders (PCR, 8.06). Costs for equipment can be estimated fairly accurately. The cost of civil works, however, is more difficult to assess before bids because of remoteness of site, the risks involved in underground works, and uncertainty about the interest by competent contractors (c) employ a panel of experts (PCR, 8.06). In this case, independent expert advice was brought in, but after the project was underway. Some of the problems regarding scheduling, design changes, delays and cost overruns may have been avoided or mitigated had a panel been available to review the project on a continuous basis. With both expatriate consultants and contractors on a project, the actual needs and interests of the owner of the facility sometimes are not fully understood, and it is the panel's prime responsi- bility to act for the owner, and to make certain that he receives the type of facility that best suits the country's requirements. It may have been desirable to retain a project management firm to act for the owner in this case; and (d) careful attention must be given during project planning to problems with soil conservation and watershed management, particularly in areas with unstable geological conditions (PPAM, para. 20). - 1 - PROJECT PERFORMANCE AUDIT MEMORANDUM NEPAL KULEKHANI HYDROELECTRIC PROJECT (CREDITS 600-NEP AND 600-1-NEP) Background 1. Although the potential for the development of hydroelectric power in Nepal is estimated to be over 80,000 MW, by 1974 only 54 MW had been installed, and only about 3% of the population had access to electricity, almost all in Kathmandu and vicinity. In the 10 years preceding 1974, the average annual growth in the demand for electrical energy was 22% and it was evident to HMG that additional generating facilities were needed to meet that growth (PCR, 3.01). 2. Thus, the Bank Group was requested to provide part of the funds for the construction of the Kulekhani Hydroelectric Project with an installed capacity of 60 MW, to be completed by June 1980, and an IDA credit of US$26 million was made. Funds were also received from OECF, Kuwait, and the UNDP1/ (PCR, 3.09; PPAM, 12). Project Implementation 3. The project was placed in service 21 months after the target date partly because of delays in engineering and primarily due to problems with executing the civil construction works. The appraisal scheduled the call for bids for the civil works on July 1, 1976, with the contract to be signed by December 31, 1976 (SAR, 4.09). However, the call for bids was not issued until about the end of August, and received on December 22, 1976. Contro- versy arose over the acceptability and competence of the low bidder to com- plete the works satisfactorily, and it was not until August 31, 1977 that a contract was signed with the low bidder (PCR, 4.02). Construction subse- quently began about January 1, 1978, about eight months late. The major delays occurred during the construction of the headrace tunnel. It was scheduled to be completed in 38 months (April 1, 1977 to June 1, 1980), but 51 months were actually required (January 1, 1978 to March 1982)-a further delay of 13 months. 4. There were several reasons for the delay in tunnel construction. In the initial stages, the contractor's apparent inexperience resulted in him being unprepared to deal with poor rock formations and large inflows of water (PCR, 4.09). This led a Bank mission to recommend that the contractor employ an zngineer familiar with modern tunnelling methods, and the contractor com- plied with this recommendation. A general scarcity of fuel was experienced throughout Nepal and India during the early months of 1980, and at one time 1/ See Appendices A and C. - 2 - the total project was shut down for a month due to lack of fuel. Most of the work was completed with an expectation of placing the units in service in December 1981, when a major failure of the tunnel lining occurred during filling. Upon inspection, it was found that grouting of the space between the concrete lining of the tunnel and the rock was inadequate, and the internal pressure had burst the lining in two places (PCR, 4.12). 5. Repairs to the tunnel were carried out in two stages. During the first stage, November to January 1982, extensive grouting was carried out, sufficient only to enable the units to be placed in service to meet the high winter power demand. The tunnel was filled and the units were placed into service for the first time in March 1982. The units were again shut down from May 15, 1982 until August 5, 1982, so the tunnel could be drained to permit the repairs (PCR, 4.13). Landslide 6. Very heavy rainfall was experienced during the June-October monsoon in 1983, and when the impoundment of water in the reservoir reached its full level for the first time in November, a large landslide occurred, extending some 170 a in width along the shore, and beginning about 150 m above the water level (PCR, 4.14). Immediate investigations were undertaken and appro- priate measuring gauges and equipment were installed to monitor movement, and to initiate both short-term and long-term solutions to the problem. The boundary of the slide appeared to be at the intake gate shaft, and any pos- sible damage to the structure could have resulted in the interruption of power for a considerable length of time. A large scale landslide also could cause waves of sufficient height to overtop and damage the dam. Fortunately, neither of these adversities occurred. 7. The short-term measures consisted of limiting the reservoir level to 5 m below the maximum level, the removal of about 40,000 m3 of material from the top of the slide area in order to reduce the weight of the sliding mass, the filling and sealing of cracks, and the improvement of surface drainage. A grid of 30 cable anchors extending 40 a to solid rock upstream of the intake, each post tensioned to 100 tonnes, has been installed to anchor the slope and restrict movement. The foregoing items of work have been completed at a cost of US$1.65 million, and the reservoir was filled to its maximum level in the fall of 1985. 8. The longer-term measures now underway, consist of driving a drain- age tunnel 185 m long in a sweeping curve through the rock downstream of the intake shaft, and drilling drainage holes upwards from the inside of the tunnel to relieve any build-up of water pressure in the slope above the intake. The drainage scheme (estimated cost US$1.0 million) is expected to be completed by April 1986. Neither of the foregoing costs, financed by OECF, have been included in the project cost used for analysis. Movement in Dam 9. While the water level in the reservoir was approaching its maximum level in October 1983, several cracks were observed in the top of the dam, - 3 - the largest extending about 100 a and having a width of about 200 mm. There was also some horizontal displacement, as well as local settlement (PCR, 4.14). Appropriate instrumentation was installed to measure the movements and upon detailed investigation and repair, the consultants concluded that this phenomenon was due to differential settlement of the various types of material in the dam, and that there was no real safety threat. Project Cost 10. The significant cost overrun on this roject was due almost entirely to the cost of civil works as shown below: Cost Estimate (US$ million) Appraisal Actual Foreign Local Total Foreign Local /a Total Preliminary works 0.5 0.3 0.8 - 1.7 1.7 Resettlement - 0.6 0.6 - 1.1 1.1 Civil works 39.6 7.9 47.5 /b 75.6 13.3 88.9 Equipment Hydro-mechanical 3.4 0.3 3.7 2.4 0.3 2.7 Electro-mechanical 8.5 0.6 9.1 11.9 0.5 12.4 Transmission & substations 1.8 0.3 2.1 2.5 0.4 2.9 Engineering services 2.7 0.3 3.0 4.7 0.6 5.3 General expenses - 1.0 1.0 - 4.9 4.9 Duties and taxes - 0.2 0.2 - 2.7 2.7 Total project cost 56.5 11.5 68.0 97.1 25.5 122.6 /a The following exchange rates were used to convert annual local expendi- ture in NRs to US$: US$1.0 - NRa 12.02 (FY76), NRs 12.5 (FY77), NRa 12.36 (FY78), NRe 12.0 (FY79, FY80, FY81), NRs 12.96 (FY82), NRs 13.86 (FY83) and NRa 15.3 (FY84). /b This includes the contingencies estimated for the civil works in the appraisal report, namely physical contingencies at 11.5% and price contingencies at 58% of base cost including physical contingencies. The difference between the foregoing and total estimated contingencies in the SAR has been allocated on a prorata basis for the items shown under equipment. 11. The lowest tender for the civil works was US$64.8 million, which was US$37.8 million above the estimated cost, Design modifications which were required following a more extensive site examination were estimated to have contributed US$7.4 million to the cost increase, and the BMG decision to impose an estimated US$7.1 million in duties and taxes on the total project added another US$4.7 million to the civil works. Most of the remainder was due to an underestimation of the cost involved in the construction of a project in this remote location, and the difficulty of access (PCR, 4.03). In addition, the mechanical and electrical equipment and engineering services were paid for in yen, and part of the cost increase was due to the apprecia- tion in the value of the yen relative to the US dollar. Project Financing 12. As a result of the significant increase in the estimated costs, first upon the receipt of tenders, and later as construction progressed, each of the original co-lenders were asked to provide supplementary funds, and each agreed to increase the amount of their loans. Two other lending agencies, OPEC and EEC, also provided funds to cover the cost overruns, as shown below: Sources of Financing (US$ millions) Appraisal Final Foreign Local Total Foreign Local Total IDA 26.0 - 26.0 40.8 - 40.8 OECF 10.0 - 10.0 20.3 - 20.3 UNDP a/ 2.7 0.3 3.0 4.8 1.1 5.9 OPEC - - - 6.0 4.3 10.3 KFAED b/ 15.9 - 15.9 24.9 - 24.9 EEC c/ - - - - 3.0 3.0 HKG 1.9 11.2 13.1 0.3 17.1 17.4 Total 56.5 11.5 68.0 97.1 25.5 122.6 XNEZE= VWN= SPENOM a/ See Appendix C, Item 1. b/ See Appendix A. c/ See Appendix B. Project Justification 13. Upon receipt of tenders, indicating that costs would greatly exceed the original estimate, resulting in a reduction of the forecast return on investment from the initial 6% to about 3%, a detailed review of the project was undertaken. Several other factors were taken into account in the review, viz: (a) the benefits accruing to the future Kulekhani developments II and III downstream of the project, using the regulated flow; and (b) the increase in river flow for irrigation during the dry season. Moreover, HMG was reluctant to face the alternative of importing high-cost fuel and its uncertain deliveries, which a thermal alternative would have required. In view of the critical power shortage, the Bank Group concurred with HMG and approved the supplementary credit (Cr. 600-1-NEP) in the amount of US$14.8 million in May, 1979. -5 - 14. Frequent and significant reductions in the supply of electric power to consumers occurred during the construction period of the project. How- ever, since it was commissioned, the project has provided a more reliable service and the peak demands of the system can be satisfied easily. For example, in 1984/85, the demand for electricity reached 79.6 MW, and the project provided 59 MW of the total. Thus, the project has fulfilled its function. Its high cost, however, resulted in a reestimated internal rate of return on investment of only 3.0% using the then existing tariff. As a result of two tariff increases in April and August 1985 (PPAM, 22), a rate of return on investment of about 6.0% should be achieved, if the tariff is main- tained in real terms. Cofinancing Experience 15. During the initial stages of the project, early in 1974, the cost was estimated to be US$35 million for one 32 MW installation. Financing was to have been provided by IDA and OECF with HMG providing the local funds and the balance of foreign funds. During a review of the draft SAR, there was some uncertainty regarding the adequacy and competence of the talus slope forming the right abutment of the dam, and the water tightness of the lime- stone formation and the associated fault on the left bank, which might affect the economic and technical viability of the project. As a result, IDA requested further investigations, which would result in a delay of credit approval from its initial proposed June 1975 date. A disagreement arose between the Bank Group on one hand, and the OECF and HMG on the other regard- ing the need for the additional sub-surface exploration. The OECF loan had been approved on the basis that the IDA credit would be forthcoming, and the delay would indicate that the credit might not be approved, or at least significantly delayed. The disagreement was resolved when it was disclosed that the delay in credit approval would not affect the project, because IDA funds would not be required until payments were due to the civil contractor. 16. By the time appraisal was complete, estimated project costs had risen to US$68 million for a 2 x 30 MW generating facility. As a result, HMG approached the Kuwait Fund for assistance to cover the cost of mechanical equipment, and the UNDP to cover consulting engineering services. Both agreed. EEC also agreed to contribute and the financing arrangements were confirmed as shown in para. 12.2/ CIDA was also interested in providing funds, but when no Canadian firm submitted a bid for equipment, the offer was withdrawn. 17. Close cooperation was maintained between the various agencies during the construction period, with the result that when it became apparent that additional funds would be required to complete the project, additional amounts ware made available (PPAM, 12). 2/ See Appendices A, B, and C. -6- Resettlement Experience 18. HKG realized that the construction of the dam and the raising of the water level would inundate about 220 ha. and '"d estimated that about 235 houses with 1,200 inhabitants would have to be relocated (PCR, 3.11). Even- tually, over 500 families, including some downstream of the dam, were suc- cessfully moved. Sixty percent accepted payment for their land, and moved further south where they were able to purchase land on much flatter slopes. The remainder were given land in excess of their original holdings. Environmental Considerations 19. The diversion of water from the Kulekhani River to another water- shed has presented no problems in the valley immediately downstream of the dam, because in the 16 km to its confluence with the Bagmati River, there are few people dependent on Kulekhani River water. 20. From 1978-1981, USAID funded the Kulekhani Watershed Soil Conserva- tion Project whose objectives were to reduce soil erosion in order to prolong the life of the reservoir, to uplift the living standards of the villagers, to manage the watershed by reforestation, and improve planting and cropping methods. Since 1981, funds have been provided by the UNDP, PAO, and HMG and to date, over five million trees have been planted. Continued funding for the program from 1986 onward is expected from FINNIDA and HMG.3/ 21. Although there are many fast flowing streams in Nepal, there are few lakes where fish may grow to an appreciable size. Thus, with the new reservoir available, the OECF is carrying out two separate fish culture experiments with a view to the eventual provision of a new source of protein in the diet of the local population. Tariffs 22. At the start of the project, a tariff study indicated that the long run marginal cost of electrical energy in Nepal was about 3 to 5 times the average revenue from existing tariffs (PCR, 4.23). Since then, several tariff increases have been made, the latest being in April and again in August 1985. The results of these two recent increases, amounting to about 65%, have yet to be assessed, although preliminary estimates indicate that the average revenue per kwh would be about US%8.4. Although the financial performance of NEA is still somewhat below a desirable level, the selling price of energy is high in absolute terms, and further increases in tariff in the immediate future might be difficult to obtain. 3/ As pointed out by UNDP (Appendix C, Item 4), however, these soil conservation efforts were started as an afterthought; the project design did not pay sufficient attention to soil conservation and watershed management aspects. -7- Performance of Consultants 23. The engineering services rendered by the consultant varied in quality (PCR, 4.27). There was a general lack of adequate project prepara- tion and sub-surface exploration, although part of the explanation for this may have been a scarcity of necessary funds in the early stages of prepara- tion. Nevertheless, the fact that the cost of civil works were estimated at US$27.0 million, whereas the lowest tender came in at US$64.8 million, reflected the incomplete early planning, and showed a lack of appreciation of the difficulties which would arise due to the remoteness of the site from sources of materials, plant and equipment. The detailed design, however, is excellent, with a converkent arrangement of equipment and controls, and with adequate space for proper maintenance and repair. The delays in construction were primarily due to the civil contractor, although it would appear that the consultant's construction schedule was overly optimistic. There seemed to be a lapse in project supervision, however, because the failure of the tunnel lining, which delayed commissioning of the units by four months, was in part the result of inadequate inspection (PCR, 4.27). Conclusions 24. The audit concludes that the cost of developing the electrical generating potential of Nepal is high and evidently will continue to be above that of most countries in the world. This is caused partially by the remote- ness of the country from world markets and the difficult access to the sites, and in part by the small size of the developments. Large scale developments which would bring the unit cost of electricity down, require very large investments, which can only be justified when there is a ready market for the surplus energy generated. Agreements on export would be required prior to the start of any large scale development, and because most countries are reluctant to be dependent on others for electrical energy, negotiations on such matters may last over extended periods of time. 25. The audit also concludes that although the cost of this project was high, NEA evidently has received an excellent facility, and good value for the money expended. 26. :t has been noticed that in spite of the new generating capacity placed into service, the economy of Nepal declined rapidly since 1982/83, with an unacceptable trade balance as a result of declining exports and growing imports. While the benefits resulting from the completion of tie project have not retarded the decline in the economy, the availability of a reliable supply of electrical power has enabled the industrial sector to perform somewhat better than average. Exports from the formal industrial sector have grown at an annual rate of 11% from 1982/83 to 1984/85. In addition, exports from cottage and small scale industries have shevn a remarkable growth, from less than 1% of the merchandise exports in 1>41/82, to about 27% in 1984/85. -6- APPENDIX A COMeMs FROM KUWAIT FUND FOR ARAB ZCZC DISTS625 JU90695 ECONOMIC DVELOPMENT * REF t TCP HC JUS0695 ZJP260 IN 30/03t55 OUT 30/03t57 KFAED 22613 KT REF t KF/GEN/1012 30/3/1986 FROM t KUWAIT FUND FOR ARAB ECONOMIC DEVELOPMENT# KUWAIT TO t THE WORLD BANKP WASHINGTON D.C. ATTENTION t MR. WATANABEP OPERATIONS EVALUATION DEPT. SUBJECT t PROJECT PERFORMANCE AUDIT REPORT ON KULEKHANI HYDROPOWER PROJECT - NEPAL WE ACKNOWLEDGE WITH THANKS RECEIPT OF THE ABOVE MENTIONED DOCUMENT SENT TO US UNDER COVER OF YOUR LETTER DATED FEBRUARY 5p 1986. WE HAVE REVIEWED THE SAID REPORT AND FIND IT SATISFACTORY# AND HENCE HAVE NO COMMENTS TO MAKE. OED Note: PPAM, paras. 2, BEST REGARDS 12 and 16 cross- referenced to these coments. ABDULNAHAB AL-BADER DIRECTOR OF OPERATIONS KFAED 22613 KT KFAED 22613 KT =03300935 ALT RTD FROMtOEDM NNNN 0z7 T2896 RCA9402 . SREFDt T FCA C 3 Il.3SCU P U RCA9402 249423 WORLDBANK 21877 COMEU 8 DE :CC.E. BRUXELLES - TLX1 - SFRVICF TVLFX A t INSAFRAD WORLOSANK - WASHINSTON REF' 14t23 13-03-86 000084417 - 000087525 TELEX NO 59042-1 248423 : IPRD ATTN t Y. WATANABE# DIR. (JP. EU. DEP* WASHINGTON OUREFS I/H/3 6909 SUPJ: PROJECT PERFORMANCE AUDIT RFPORT KULEKHANI HYDROELECTRIC PROJECT NO. 600-1-NEP. REFo YOUR TELEX OFDD3 OF 7.3.86 AND OUR LFTTER NO 04504 OF 17.3.86 THANK YOU FOR COPY OF AUDIT REPORT. EEC PARTICIPATION OF 3M DLR FINANCED UNDER SPECIAL ACTION PROURANE WHICH WAS PUT AT DISPOSAL OF IDA CONTRIBUTED TO BRIDGIND SUBSTANTIAL COST INCREASE OF PROJECT EXPERIENCE [N 19.79. COMMISSION PtFASED TO NOTE THAT PROJECT IS NOW OPERATING SUCCESSFUJI.t.Y AND IS ASSI)MING VITAI. ROLE IN SUPPORTING NEPAl'S FCONOhY. COMMISSION HAS NO SPFCIAL COMMFNTS AND CONSIDFRS THAT REPORT PROV(D0S A FAXR AND VALANi,F0 VI90W OF PROBLEMS AND . ACHIEVFMFNTS OF PROJECT. OID Nots PPAN, pars. 12 RtGARDS mad 16 emse- - * FOSSAT1 referenced to these dEAD OF DIVISION commts. Par&. 16 also ameded. =0313085b ALT RID FROM'0EWf NNNN - 10 - APPENDIX C Page 1 of 2 UNITED NATIONS NATIONS UNIES OFRpCe OF Uas RSeNsr RNaafNTATIV OF THE UNITEM NATIONS DEVLOPMUNT PROGRAMME IN NEPAL "MMMRTINM F.LM1.113ANKA.WA geNaZP/75/010 18 March 1986 Dear Mr. Watanabe, NEP/75/010 - Kulekhani Hydroelectrit Project OED Notes Thank you for your letter of 5 February 1986 forwarding the Project Performance Audit Report concerning the above-mentioned project. We have reviewed the report and find that it is well prepared. However, we wish to make the following comments of a general nature. 1. The Rulekhani Hydroelectric Project represents the single largest PPAM, project of this nature funded by UNDP against the country IPF so far piras. 2, In Nepal. The total UNDP contribution amounted to $6,100,000, of which 12 & 16' $5,923,175 had been actually expended at the closing of the project cross- accounts in June 1985. The project was approved in October 1975 with refettuc- an initial UDP contribution of $3,000,000. Over a period of 10 years, ed to two major project revisions were approved the first in January 1979 these to increase the budget by $1,000,000 and the second in January 1980 comments. to increase the budget by $2,100,000, thus bringing the total UNDP allocation to US$6,100,000. These successive increases in UNDP budgetary provisions were mainly due to cost overruns for the consultancy services as a result of delays in project completion, to depreciation of the US dollar vis-a-vis the Japanese Yen and to additional consultancies required. While accommodation of cost increases within the country IPF resources greatly facilitated the project work, it had a negative effect on the overall UNDP programse in that some of the projects identified as priority were either deleted or deferred. The January 1980 version of the revipion increasing the UNDP contribution by $2,100,000 was signed by the parties with the explicit understanding that UNDP would not provide any additional funds to accomodate further cost increases. Be that as it may, UNDP is pleased to have been involved in this joint undertaking and to see this facility, which almost doubled the country's installed power capacity, established. 2. Although a total of 54 am training in the fields of design and Evaluation construction took place at the consultant's home office, there was Summary, insufficient concern for t*.e more crucial institutional building aspects. para. xiii cross- Mr. Tukinori Watanabe referenced Director to these Operational Evaluations Department comments. World Bank Washington D.C. .1 3115 APPENDIX C -1 Page 2 of 2 UNITED NATIONS NATIONS UNIES UNDPs assistance was seen more as an instrument for supervision of the implementation of the investment activities and less as a mechanism for strengthening the institutional capability. In future, where UNDP's assistance is involved, it will be necessary to design the project so as to address the institution building concerns first in order to sustain the project's potential in the long term. 3. The UNDP periodic progress reporting requirements were largely met by the consultants although they were not received in the desired sequence and format. 4. The project design did not take full cognizance of soil conservation and watershed management problems as is evidenced by the large borrow pits indiscriminately dug out close to the upper reaches of the reservoir which are profusely eroded and could threaten the life of the reservoir. The project area is prone to landslides as demonstrated by occurrence of two landslides since project coimissioning, and there is no guarantee that such natural events may not occur in future. In view of the youthful nature of the Himalayan belt and unstable geological conditions, the highest level of precaution needs to be exercised to maintain soil and slope stability through appropriate soil conservation and watershed management techniques. In the case of Kulekhanl Project, efforts at soil conservation have started as an after-thought, from 1978-81, under the USAID funded Kulekhani Watershed Soil Conservation Project and the BMG/UNDP/PAO Watershed Management and Conservation Project since 1981. One of the important lessons learned from the Kulekhani experience is that environmental considerations must be given due priority and that meticulous environmental planning should be included from the project design stage. Inputs intended to conserve soil conditions should flow concomittantly with construction activities. A/ We trust you will find our comments useful, and we look forward to receiving the finalised version of the Report. Yours ncerely, kToo i ident Representative a/ OED Note: Evaluation Summary, paras. xi, vv and xxiii amended to reflect these comments, including the addition of the soil conservation/watershed management problem as a lesson learned. PPAM, para. 20 also amended. - 12 - NEPAL PROJECT COMPLETION REPORT KULEKHANI HYDROELECTRIC PROJECT Credit 600-NEP I. INTRODUCTION 1.01 The Kulekhani Hydroelectric Project, Credit 600-NEP, 1976, for US$ 26 million, was the first in the power subsector financed by the Bank Group in Nepal. IDA credits aggregating US$32 million had been made for seven projects in other sectors. 1.02 The Kingdom of Nepal has an area of about 140,000 km2 with a popula- tion of over 12 million. In 1974, when the project was appraised, per capita income was about US$100. In that year, agriculture accounted for 70% of GDP and 90% of employment, and industry for 10% of GDP. The bulk of investment expenditure was for infrastructure projects: in particular roads, irrigation and power, and was financed largely by India, the United States of America and the People's Republic of China, in addition to the Association. 1.03 A predominant factor for the development of Nepal is the geography of the country. The high mountains of the Himalayas and their foothills account for 83% of the area of the country, in which about two-thirds of the people live. The remainder live on the Terai plain where the population density is high. In 1974 electric power was provided on a very small scale, serving only about 3% of the population and average consumption was only a fraction of that in neighboring India. II. POWER SUBSECTOR 2.01 In 1974, the Nepal Electricity Corporation (NEC), which operated in the central area of the plain and supplied over 80% of all power consumers, generated about 100 GWh, had sales of approximately 65 GWh and a maximum demand of about 26 MW. Although this was a small demand for a country of Nepal's size, both maximum demand and energy generation had increased at the average annual growth rate of about 22% over the period 1964-1974. It was evident that there was a considerable potential market for sales of elec- tricity. - 13 - 2.02 In 1974 the organization of the power subsector was fragmented, with the Electricity Department (ED) of the Ministry of Water and Power mainly responsible for planning and construction of generation and transmission facilities. The Government-owned NEC was responsible for generating and distributing power in its territory, and the Government-owned Eastern Elec- tricity Corporation (EEC) for providing service elsewhere. The NEC system comprised small hydro and diesel stations with a total installed capacity of 40 MW, (including 32 MW hydro), and 276 km of transmission lines operating at 6( kV, 33-kV and 11-kV. The NEC and EEC systems were not interconnected. 2.03 The existing installed capacity was minute when compared with Nepal's hydroelectric potential. Potential developments located on the rivers rising in the Himalayas, and given the extensive snow melt, monsoon, and enormous drops in river elevation, are estimated to exceed 80,000 MW. Most of this is in large sites, exceeding 1,000 MW. The Karnali River basin had been sys- tematically explored, under a UNDP study conducted in 1963-66 which iden- tified 10 developments ranging from small size to 1,800 MW, and aggregating to 6,000 MW. Karnali is presently being reviewed under a Bank Group techni- cal assistance credit to Nepal (Credit 1452-NEP). The Kulekhani site was first identified in the 1950's by a Swiss-Nepalese team, leading to prelimi- nary field investigations and design in 1963-1967 by Nippon Koi, a Japanese financed consulting engineering firm. In 1973 a feasibility study was financed by the Japanese, employing the.same consultants, and this became the basis for project preparation. III. PROJECT FORMULATION Load Forecast 3.01 Load forecasts prepared at the time of appraisal for the planned interconnected system and based on the Government's Fifth Five Year Plan projected an average annual growth rate of 14Z for electricity sales for the period 1975-1984. These forecasts took into consideration the expected demand from industrial consumers, agricultural developments, and expectations for the rapidly growing tourist industry. Peak demand was forecast to increase from 30 MW in 1975 to 93 MW in 1984. This demand was to be supplied by the 15 MW Gandak hydroelectric project provided by India, which was expected to be commissioned in 1977, a second hydroelectric plant of 14 MW at Devighat, also to be built with Indian assistance, which was projected for commissioning in 1978, and by the commissioning of the Kulekhani station in 1980. -14- The Project 3.02 The Kulekhani hydroelectric project, located 30 km from Kathmandu, the main center of population, was to have a capacity of 60 MW. A storage reservoir impounded by a large embankment dam across the Kulekhani River, into which tributaries from two other smaller watersheds were to be diverted, would provide a firm annual energy capacity of 165 GWh at a plant factor of 30%. The main features of the hydroelectric plant and storage system are described in para 3.03. 3.03 A rock-fill dam, 107 m high, with an embankment volume of 3.5 million cubic meters; An open-channel s?illway, gate controlled; An intake stucuture, connected to a head race tunnel of approximately 6 km length; A tailrace tunnel, 1 km long; St2rage reservoir and basin diversions with a catchment area of 156 km' and a live storage of 73 million m , including the flow of the Chakhel and Sim tributaries which were to be diverted to the reser- voir by a 2.3 km long connecting tunnel; An underground powerhouse, equipped with 2x30 MW generators and Pelton turbines each rated for 550 meter high head and a maximum discharge rate of 13.1 cubic meters per second; and Substations and 66-kV transmission line facilities, the latter were of short length to connect to existing lines. 3.04 The lengths of the tunnels and use of an underground powerhouse design are indicative of the rugged mountainous location of the Project, as is the operating head of about 600 m for the turbines. The Himalayan range is one of the newest mountain cains in the world, and the geological charac- teristics are far from ideal for the construction of hydroelectric projects, since faults and other problem traits are rampant. The first unit was to be commissioned in June 1980, allowing a construction period of 3.5 to 4 years. Transportation 3.05 All construction materials and equipment, with the exception of goods made in India, had to be transported over a long distance from the port of Calcutta. At the outset, it was thus clear that most cargos would require both a relatively long shipping time to Calcutta and would experience delays at the port due to lighterage. In addition, some transportation problems - 15 - problems were expected as a result of changes in the railway gauge and limited weight bridges on the route from Calcutta to the Project site. Field Investigations 3.06 The initial field investigation in 1967-68, at prefeasibility study level, was carried out by Nippon Koi (Japan). It included 338 m of exploratory core drilling at the site. A second field investigation was undertaken in 1973, at feasibility study level. This was also undertaken by Nippon Koi, and included reconnaissance of the main features of the Project area, inspection and further core drilling. Project cost estimates were based on these field investigations. Following Project approval in December, 1975, the detailed engineering investigation was carried out by the same consultant under a new contract, funded by UNDP. The Bank Group was appointed Executing Agency on behalf of UNDP. At this stage it was found necessary to make important changes to the Project design, since detailed geological findings indicated that there had been insufficient field work undertaken under the feasibility study and other investigations. The most important design changes were as follows: Diversion Works - the two entrances for the river diversion tunnels were moved 60 m and 26 m respectively, and the connecting open channel extended; Main Dam - extra embankment was provided, together with improved slope stability in the area of the main dam and upstream coffer dam; the height of the dam was increased from 107 m to 114 a as the founda- tion rock was deeper than expected in the riverbed portion of the core zone of the dam; and the axis of the dam was shifted to locate the dam on better rock. These cha,,es increased the volume of the embankment from 3.5 to 4.4 million cubic feet; Spillway - many changes were made to the spillway structurea; in addition some structures were relocated away from the area where a landslide occurred after the start of construction; Tributaries - the Chakhel River connecting tunnel was strengthened considerably, the location of the Sim river intake weir and appurtenances were changed completely, and their foundations strengthened; - 16 - Intake Tunnel - the open slope was changed for the intake tunnel and approaches from a 1:1 to 1:1.5 gradient to improve stability; the intake gate shaft was shifted 17 m, and provision was made for a concrete lining; Headrace Tunnel - the intake slope was changed to a more gentle gradient, the tunnel lining was strengthened in the poorer geological areas, and the location of the intake tunnel was shifted 17.5 m downstream; Underground Powerhouse - the rock chamber excavation for the underground powerhouse was lined with concrete and generally strenghtened; - the location of the entrance to the adit to the powerhouse from the access tunnel was moved 60 m; Tailrace Tunnel - the design of the powerhouse outlet tunnel was changed and two outlet openings provided instead of one; and Electrical Works - instead of one 66-kV substation of 70 MVA transformer capacity, two substations were added which necessitated extending the 66-kV transmission line. These changes increased the Project cost substantially above the originally estimated US$68 million (paras 4.03 and 4.16). Project Cost 3.07 The estimated Project cost was US$68 million, including US$0.2 mil- lion for duties and taxes, and foreign exchange cost of US$56.5 million. Physical contingency of 11.5% was included for the civil works, which accounted for three-fourths of the base cost, and of 3.5% on equipment; price contingencies for civil works were 16% for 1975, 14% for 1976 and 12% for each year 1977-79, for equipment 12% in 1975, 10% in 1976, 8% in 1977-79 and 10% from 1980. Total contingencies were 58% of base cost. Details of the cost estimate, and actual costs, are given in Annex 1. - 17 - 3.08 The Project was the first major infrastructure project in Nepal, a country in which both the access to the isolated site and site conditions were difficult, and knowledge 'f and experience with the geology in this Himalayan area was limited. Financing Plan 3.09 The proposed financing plan was as follows: IDA OBCF KFAED UNDP Government lotal ---------------US$ million---------------- Electro-mechanical 10.0 equipment Civil works for main 26.0 dam & spillway Hydro-mechanical equipment 15.9 a other civil works Consulting services 3.0 Balance, including local 13.1 funds TOTAL 26.0 10.0 15.9 3.0 13.1 68.0 The Association Credit of US$26.0 million represented 38% of total cost and 46% of foreign cost. The Government was to provide all local currency financing. However the actual costs were higher than the estimated costs; the revised costs and financing arrangements are discussed in para 4.20. Procurement 3.10 Prequalification of contractors was to be carried out for the civil works with the understanding that if the same contractors prequalified for both IDA and KFAED works, bids would be invited from them under a single contract for the works. The equipment financed by OECF was to be awarded on the basis of its procurement regulations. UNDP provided a grant for the consulting services to carry out detailed engineering and supervision of construction. The contract for the latter works was awarded to the firm which had prepared the prefeasibility and feasibility studies. Details of the main contracts are given in Annex 2. - 18 - Relocation and Environment 3.11 An appropriate sum was allocated for resettlement of the 1200 inhabitants affected by the Project. No important ecologica or environmen- tal problems were foreseen as a result of the Project. Organisation 3,12 The Kulekhani Hydroelectric Development Board (KHDB) was the Govern- ment's executing agency for the Project. NEC, the beneficiary, was to manage, operate and maintain the Project along with its existing facilities. ED functioned as a Government Department, headed by a Chief Engineer, and had the standard departments; engineering, finance, purchasing, administration and planning studies, together with three regional construction and main- tenance offices. In 1974 ED had a payroll of 900 technical and administra- tive staff. 3.13 In retrospect, it is clear that neither ED nor KHDB were likely to have the technical resources and experience expected from an owner of a major hydroelectric plant under design and construction. Although the consulting firm represents the interests of the owner in dealings with the contractor, it can not really function as the owner in overseeing the spectrum of activities associated with the project and making critical decisions. The Bank Group, acting as UNDP's Executing Agency's for the detailed engineering work, became involved in implementation details. On the suggestion of the Bank Group, the Borrower amployed short term experts whenever construction and design problems arose. There was thus a lack of a fully capable and responsible authority in charge of the Project. However, the exposure of ED, NEC, KME to the complexities of a project of this nature assisted in the development of these institutions. NEC Finances 3.14 The forecast and actual accounting statements of NEC for the period 1976/77-1982/83 are given in Annexes 3, 4, and 5. The salient points of NEC's finances at the time of appraisal were as follows: - NEC had no debt, since its facilities had been acquired as equity; - its tariffs were very low, averaging only US 1.9 cents/kWh. One reason for the low tariffs was that NEC did not have any debt to service; - its internal cash generation was modest and was averaging about US$2.0 million a year; and - NEC's rate of return on historic valued assets was about 3%. - 19 - It was considered desirable to increase tariffs to a level sufficient to generate funds to finance a substantial proportion of the costs of its investment program. Tariff increase were also required to move tariff rates closer to the economic cost of supply. 3.15 An increase in the average tariff rate from US 1.9 cents/kWh to about US 3.3 cents/kWh was planned, and this was to be followed by further tariff increases to give NEC a rate of return, based on historic valued assets, of 4% by 1977/78 and 6% by 1980/81. The achievement of these targets also required the abolition of the Government imposed royalty tax equivalent to US 0.08 cents/kWh. The Government agreed at negotiations to discontinue this tax (para 4.21). 3.16 NEC's system losses (par& 4.25) averaged about 30% during the five years preceding the project. This very high level undoubtedly reflected substantial theft of power by consumers. The Association projected losses of 27% in 1974/75 gradually declining to 18% by 1983/84. These reductions reflected the recommendations of a field study made by a consultant funded by ADB. Project Justification 3.17 Kulekhani was determined to be the least-cost solution to the development of generating capacity, partly because no other hydro schemes of compatible size had been studied sufficiently to enable them to be commis- sioned at the required date. The least cost thermal alternative had an equalizing discount rate of 13%. The internal rate of return (IRR) of the project was estimated to be 6% based on existing tariffs. The IRR was estimated to be 10.7% on the basis of planned tariff increases. The IRR, at the time of the completion of the Project, has been estimated to be 3.3% on the basis of existing tariffs and 6.1% on the basis of planned tariff rates (para 5.03). Covenants 3.18 The main covenants covered the following (pars 4.30): - tariffs would be increased to enable NEC to earn a rate of return of 4% for FY77/78, increasing to 6% by FY80/81 (para 4.20); - the Association would be consulted on any changes to the organiza- tion of the power subsector relating to NEC (para 6.02); - certain small existing hydro plants would be transferred to NEC as equity; plants financed with concessional funds and internal cash generation would be transferred as debt; - 20 - - a resettlement plan for persons affected by the Project would be finalized in consultation with IDA; - the settlement of Government arrears for power supplied would be offset against NEC's obligations to Government (para 4.26); and - dividends would only be paid on NEC equity following project completion. IV. PROJECT IMPLEMENTATION Overview 4.01 Serious difficulties were experienced during Project implementation. The first unit was only placed in permanent service in August, 1982, two years behind schedule (para 4.05) and there was an increase of 80% in the Project cost. The delay and cost overrun were mainly due to weaknesses in project design and construction. There were serious power shortages until Kulekhani commenced operations, and the delay resulted in a substantial reduction in NEC's forecast sales and revenues. Contract Award 4.02 Nineteen firms applied for prequalification for the civil works; however, only six firms were prequalified, and only two of these firms sub- mitted bids. The remaining four prequalified firms declined to bid. One of these firms suggested a target price contract in view of the many risk fac- tors involved: geology, weather conditions, availability of labor, and the need to transport all equipment and supplies across India. The contract prices of the two bids which were received were 10% apart, but the lowest bid was 140% higher than the price estimated at appraisal. Both firms bid about the same amount for the foreign exchange component of the Project, and thus the difference concerned the price of the local component for which one firm bid only half the amount of the other firm. The consultant criticized the construction plan of the lowest bidder as not being sufficiently definitive and suggested accepting the higher bid. However, the supervision mission advised acceptance of the lower bid as "the technical problems in the con- struction plan all appeared to be negotiable." The award for the entire civil works was made accordingly (para 3.10). 4.03 The much higher price of the civil works contract reflected: - changes in design and quantities arising from detailed project engineering (US$ 7.3 million); - higher unit prices reflecting the factors of risk and project difficulty (para 4.02); - 21 - - imposition of taxes and duties on the contractor, which the Government originally stated would not be levied (US$2.7 million); - the grossly understated cost estimate in the pre-feasibility study; and - appreciation of the value of the yen, the currency in which much of the procurement was contracted. 4.04 In general, it is highly advisable in major civil works involving large dams, extensive tunnelling and/or questionable or unknown geology, to obtain bids before committing the project or approving a loan for it. Clearly, this should have been done for this Project 1/. The objection is that it does not permit an early start on the preliminary works, access roads and so forth, since it is not certain that the project will proceed. In this instance, there was also pressure from the Borrower to move ahead with the Project. Construction Schedule 4.05 The appraisal report stated that the first unit would be commissioned in June 1980 and the second in the period June 1981 to June 1982 depending on system requirements. However, the civil works contract schedule provided 45 months to carry out the work, beginning September 1977 and finishing June 1981, and the first generator was to commence operation in December 1980. 4.06 Operation of the generators began on a temporary basis in March 1982, but was discontinued in May 1982 to complete repairs to the headrace tunnel, which was found to be defective when it was filled. This was repaired par- tially in the period November 1981-February 1982 (para 4.12). The units finally commenced regular commercial operation in August 1982, more than one year behind the civil works contract schedule. Construction History, River Diversion 4.07 Initially, both the amount of construction equipment and the quality and suitability of some plant was inadequate. Tunnelling for the river diversion occurred at the slow rate of 0.85 m per day as a result of a number of factors, including: the use of poor tunnelling techniques, insufficient pumping capacity to dispose of random water, inadequate supply of tunnel workers, and late delivery of supplies and equipment. As a result, the diversion of the river was delayed by 10 months to February 1978. 1/ In October 1978 the Bank prescribed in OMS 2.28, para 3, the circumstan- ces in which this procedure was required. - 22 - Main Dam 4.08 Construction of the main dam started in March 1979, and the entire embankment was completed in June 1982. The design provided for the removal of river bed deposits in the upstream rock fill zone. However, this material was found to be dense and the excavation was subsequently cancelled. This was an important factor in enabling work on the embankment, which had been progressing slowly, to be completed on schedule. On the whole, dam construc- tion proceeded smoothly. Pressure Tunnel and Surge Tank 4.09 Three adits were used to speed up construction. Construction dif- ficulties were experienced as a result of poor rock formations, water leakage, the contractors's apparent inexperience, inadequate facilities and, at times, poor performance by the labor force. Poor rock and water in adit number three necessitated suspension of the work for several months. Tunnel excavation proceeding from adit number one was interrupted by a flood in July 1978 which submerged the approach roads. Tunnelling of the intake shaft was very slow due to the poor labor force (which was replaced), lack of skilled workmen, and poor ventilation and air supply. In August 1979, when excava- tion work was being undertaken from the intgke side, work stopped when very poor geological conditions were met and 3 m per minute of water gushed from the rock. Eventually the fault zone was backfilled and grouted, a concrete bulkhead was constructed, and excavation proceeded from the side of adit number one. Underground Powerhouse 4.10 Considerable difficulty was experienced with the excavation of the underground chamber containing the power generating facilities. Work in the access tunnel was hampered by geological conditions, lack of steel supports and inadequate drainage pump capacity. Additional pumps and supports were ordered and the work proceeded satisfactorily after a four month period of very slow progress. As to the excavation itself, considerable stress occurred in the arch (roof) of the chamber and subsequently in the walls, and a number of cracks developed in the concrete linings of both. This appeared to have been partly due to the design, and partly to a failure to fully anticipate likely problems when planning the construction strategy. Remedial measures had to be taken, and the completion of this component was delayed until February 1980. 4.11 The other main civil works construction, including the spillway and penstock, experienced some problems, but these were less difficult and serious than those considered above. - 23 - Plant Commissioning 4.12 The 6,300 m long headrace tunnel was filled with water for the first time in November, 1981 when the plant was being prepared for service. Leakage of the tunnel occurred. On draining the water it was found that the roof of the tunnel was damaged in two places and that there were voids in the concrete lining due to inadequate grouting. It was agreed by a panel of geologist, civil engineer and a construction engineer constituted by the Borrower on the advice of IDA that conditions throughout the tunnel would be checked, and full grouting where required would be undertaken. This took until mid-February, 1982 when all but the upper 600 a of the tunnel had been repaired and reinforced. Since this top section of the tunnel operates under ..nly a small water pressure, the remaining work was deferred to the future and the plant was placed in service in March 1982. This enabled NEC to meet the peak demand and avoid load shedding. 4.13 The station was subsequently shut-down from mid-May, 1982 to end-August, 1982 to repair the upper section of the tunnel. On August 6, 1982 the plant was finally put into regular commercial operation, nine months after the tunnel leakage was detected. The extensive reinforcement of the tunnel in nine months represented a considerable achievement. Plant Operation 4.14 After commissioning the plant functioned normally. However, two important developments occurred in November 1983, when the level of water in the storage reservoir reached the maximum operating level (1,530 a) for the first time. First, a differential settlement of the main dam embankment was observed. Subsequent measurements of this indicated that it was within the range of expected settlement. Second, a large land slide occurred a little upstream of the headrace tunnel intake structure. The slide fell into the storage reservoir without causing serious damage and did not cause overtop- ping of the dam through wave action - which sometimes has caused serious damage and loss of life in downstream valleys. However, there was con- siderable concern that since the slope upstream of the intake structure had proved to be unstable, the slope adjacent to it, immediately overloading the intake structure, might also be unstable. A landslide there would block the intake structure, shutting down the Kulekhani plant for an indefinite period. Investigation of the situation was made by consultants in soil mechanics, obtained by the Borrower on advice of the Bank Group, and by the consulting firm which had designed and supervised construction of the Project. Monitor- ing equipment to measure soil movements was installed and exploratory holes were drilled. In addition, the level of the reservoir was lowered to enable shore line inspection and reduce hydrostatic pressure on the soil. These investigations concluded that it was unlikely that the slide would extend further. - 24 - 4.15 Remedial work carried out included the removal of 40,000 cubic meters of the upper part of the slide area, installation of anchor cables to stabi- lize the slopes, filling minor cracks in the soil with clay, and the provi- sion of either drainage galleries or simple horizontal drains in the slope to prevent water building-up, which would lubricate slides. Inspection work and monitoring by consultants are to be continued. The Japanese aid agency, OECF, agreed to meet the cost (about US$2 million) of the investigations and remedial works. Although the power station reached its designed capacity of 60 MW, the level of the reservoir has not been permitted to exceed elevation 1515 to 1522 m, which has reduced the annual storage and firm energy capacity by about 15-20%. However, it is expected that this restriction will be lifted following completion of the remedial work. Project Cost 4.16 The cost of the Project was US$122.6 million compared with the appraisal estimate of US$68.0 million, an increase of about 80%. Details of the costs are given in Annex 1. The reasons for the increased costs are discussed in para 4.03. Supplementary Financing 4.17 The very large cost increase necessitated the raising of substantial additional funds. The Association provided Supplementary Financing to Credit 600-NEP of US$14.8 million in June, 1979. The OECF, UNDP, and KFAED also provided additional funds to their original loans. OPEC and the EEC, which had not participated in the original financing of the Project now provided loans, OPEC toward the civil works component and EEC towards local costs. The original and final financial arrangements are shown below: SOURCES OF FINANCING (US$ million) Original Final Foreign Local Total Foreign Local Total IDA 26.0 - 26.0 40.8 - 40.8 OECF 10.0 - 10.0 20.3 - 20.3 UNDP 2.7 0.3 3.0 4.8 1.1 5.9 OPEC - - - 6.0 4.3 10.3 KFAED 15.9 - 15.9 24.9 - 24.9 EEC - - - - 3.0 3.0 HMG 1.9 11.2 13.1 0.3 17.1 17.4 TOTAL 56.5 11.5 68.0 97.1 25.5 122.6 - 25 - Operational and Financial Performance Comparison of Actual and Forecast Data 4.18 The initiation of the Kulekhani Project in 1975 occurred at a time when the power subsector in Nepal was in an infant stage of development. The lack of experience in executing power projects in Nepal, together with the inherent physical difficulties in the country, created formidable problems which were difficult to assess. It is with this background that the rather wide divergence between the financial estimates at the time of appraisal and the actual results is preseated. 4.19 NEC's operating and financial data is summarised in Annex 3. Forecast and actual income statements, balance sheets and sources and applications of funds statements for FY77-83, are given in Annexes 4, 5, and 6. The figures show that NEC's operating results were generally depressed with the result that targets established at the time of appraisal were lar- gely not achieved. The main reasons for this were: (i) a reluctance to make timely tariff icreases; (ii) continued high system losses; (iii) a delay in eliminating the royalty surcharge on electricity sold, (iv) the delays in the commissioning the project, and (v) large arrears, especially those owed by the Government (para 4.26). 4.20 The appraisal estimates assumed tariff increases of 74%, 38% and 28% in FY76, FY78 and FY81, respectively. However, tariff adjustments were delayed by an average of two years, and actual increases were 45% in FY77, 35% in FY79 and 56% in FY83. 4.21 The Government levied a royalty surcharge of 7.5 paisa per kWh sold; during FY76-FY79, this amounted to about 25% of operating expenses and was equivalent to about 30% of the average revenue/kWh. The surcharge was to have been eliminated in FY76 (para 3.15) but was not discontinued until FY80. In addition to the delayed elimination of the royalty surcharge, NEC's operating results were also depressed by the reduction in electricity sales and higher fuel costs caused by the general delay in commissioning hydropower projects, which resulted in greater utilization of thermal plant, consumption of fuel, and supply interruptions. 4.22 The combination of these factors prevented NEC from achieving the financial targets set at the time of appraisal, which in any case were optimistic. The following table compares forecast with actual rates of return earned on historically valued average net fixed assets in service during the period FY77-FY83. - 26 - Forecast Actual % % FY77 3.1 1.0 FY78 4.3 0.5 FY79 4.0 (1.8) FY80 4.1 3.5 FY81 6.0 1.1 FY82 6.4 0.2 FY83 6.5 1.5 Despite these weak operating results, NEC's finances were manageable because of its unique financial position. The principal reason for this was that prior to FY81 NBC had no debt to service, since the few additions to gener- ation and transmission plant were provided through bilateral grants and transferred to NBC as Government equity, and its cash flow was just suffi- cient to finance modest distribution expansion. There was a marked improve- ment in FY81 because of a tariff increase and the elimination of the royalty payment. Tariffs 4.23 The Government carried out a tariff study at the outset of the Project. The study emphasised the need for tariff levels to to reflect the cost of electricity supply and promote an optimal allocation of resources, but not at the expense of poorer consumers. It found thats (a) the economic cost of electricity supply in Nepal was about 3-5 times the average revenue from existing tariffs; and (b) that the cost differences for supplies in wet and dry seasons, and daily peak and off-peak periods, were very pronounced. The principal recommendations of this study were not implemented, however the Government initiated another tariff study in 1983 and the results of which are in the process of being implemented. 4.24 The following table summarises the tariff increases required if NBC is to meet its covenanted 62 rate of return during FY83-88. Required Required Tariff Average Revenue 1/ Increase Fiscal Year (NR per kWh) (US cents) % 1983 0.87 6.8 67 1984 0.97 7.6 11 1985 0.97 7.5 - 1986 1.01 7.9 5 1987 1.32 10.4 31 1988 1.34 10.5 2 1/ Average Revenue per kWh in 1984 was NR 0.52 (US 4.1 cents). - 27 - System Losses 4.25 System losses were approximately 30% of gross generation before the Project. Major causes of these high losses included substantial electricity theft, late billing and bad metering, and only soft measures were taken against illegal consumption. NEC established a Loss Elimination Division in November, 1978 to deal with this problem. Nineteen areas were selected for investigation, and master meters were installed to compare electricity sup- plied with that measured by the consumer's meters. Areas of high pilferage were detected and corrective actions were taken, including upgrading of the quality of employees used for meter reading and ensuring that meters were maintained in good working order. System losses were reduced to 28% in 1981, but then increased to 35% in 1983. More recently, a specialist has given guidance to NEC in setting up a five year loss reduction program with the objective of reducing losses to 15% by 1987. Funds have.been provided in a subsequent project (Marsyangdi-Credit No. 1478-NEP) to help implement the program. Government Arrears 4.26 In mid-1979 Government arrears to NEC were NR 6.0 million, equivalent to four years billing. During negotiations for the Supplementary credit in mid-1980 the Government agreed to settle these arrears. However, this did not occur and by 1983 they were double the 1978 level. These accounts were, however, settled in 1984. Performance of the Consultants and Contractors 4.27 The performance of the consultants was uneven. Many changes were made to the plans prepared under the feasibility study following detailed engineering studies. These changes affected the cost estimates, and when the bids were received for the two main contracts they were 140% higher than estimated (para 4.02). The supervision of construction was sometimes weak, for example, the failure of the headrace tunnel when it was filled with water (para 4.12) was partly attributed to poor supervision of tunnel lining grout- ig. 4.28 The performance of the civil works contractor was also mixed. When the selection was in progress the consultants expressed reservations about the contractor's construction plans, and to some extent these reservations proved to be well founded. At times there was both a lack of sufficient equipment and of appropriate equipment at the Project site. There were also shortages of capable staff and labor, and inadequate logistical planning. Bank Group presence was particularly important in pointing out the urgent need to augment transportation facilities, use better tunnel boring equip- ment, and engage experts to solve particular problems (paras 4.12 and 4.14). - 28 - 4.29 However, the contractor made efforts to improve his performance and was susceptible to the suggestions made in this respect. As noted, his ability to reinforce and repair the headrace tunnel within six months was a sound achievement (para 4.13). Indeed the fact that completion of the civil works, and plant commissioning as prescribed under the contract, were delayed by only one year was a noteworthy achievement. It says a good deal about the ability of the contractor and consultant, with the Bank Group and Borrower in the background, to work together and muster the necessary resources to push the project to completion in the last year or so. 4.30 Some of the covenants (para 3.18) were met only with difficulty and delay; while the rate of return covenant was not met: - NEC takes about nine months to submit its annual audit to the Association instead of the covenanted six months, due to weak internal auditing methods and the need to prepare a translation in English; - tariff increases were inadequate to enable NEC to satisfy the rate of return covenant (para 4.22); and - the Government settled its arrears four years late (para 4.26). V. PROJECT JUSTIFICATION Load Growth 5.01 Power and energy requirements in the period 1964-1974 increased sevenfold, with an average annual growth rate of about 22% for both maximum demand and energy generation. At the time of appraisal in 1975, it was forecast that the average annual rate of growth would be about 14% in the period 1975-1984, but would level off to 9.3% in 1984. Maximum demand was forecast to increase from 30.4 MW in FY75 to 85.5 MW in FY83, while energy generated was forecast to increase from 117.3 GWh to 389.7 GWh in the same period. 5.02 The actual experience, however, shows that in FY83 energy generation in the area served by NEC was only 280 GWh, corresponding to a maximum demand of 71 MW at a 45% load factor. As a result of delays in commissioning the Kulekhani project and technical problems in other hydro stations, about 16 MW of load was shed continuously during peak hours during the four years FY79-FY82. If load shedding had not taken place and new connections had not been restricted, then it is estimated that demand would have reached expecta- tions. The delay in commissioning Kulekhani thus caused substantial load shedding and delay in making new consumer connections. However, load growth - 29 - (actual and suppressed) confirmed the need for the additional capacity provided by the Project, which also enabled NEC to institute a proper main- tenance program for its existing power stations. Rate of Return 5.03 At appraisal, the internal rate of return (IRR) was estimated to be 6% on the basis of existing tariffs, and to be 10.7% allowing for projected tariff increases. The cost and sales data used in these estimates was very different to the outturn data. The revised IRR, based on outturn cost and sales data, is 3.3% when estimated on the basis of existing tariffs and 6.1% using the new tariffs which the government has agreed to implement as a condition of credit effectiveness for the Marysangdi Hydro Electric Project (Annex 7). NEC was able to manage financially because of its negligible debt service and the fact that it was able to finance new generation and transmis- sion facilities from grants. VI. PROJECT IMPACT 6.01 At the time of its construction, Kulekhani was the largest project ever undertaken in Nepal, and the country has benefited in a number of impor- tant respects. First, its commissioning ended the severe power shortages that were inhibiting the operations and growth of industry and commercial undertak'.;gs and which were having a generally debilitating effect on the national economy. Second, the project created a substantial amount of employment, equivalent to some 5,000 manyears, and served to upgrade a sig- nificant number of Nepalese workers, who have attained proficiency in a range of skilled and semi-skilled occupations. Third, the commissioning of Kulek- hani has assured Nepal of electricity supply to meet demand growth through 1989, when new facilities are scheduled for completion. 6.02 In addition, the Project has been an important factor in fostering institution building in the power subsector. HMG is in the process of con- solidating a largely uncoordinated and fragmented group of small entities into one authority to operate Nepal's small power system; progress has been made in rationalizing tariffs and in strengthening NEC's financial opera- tions; and the exposure of management and technical personnel to a project of this magnitude has resulted in the development of supervisory and administrative skills. VII. PERFORMANCE OF THE BANK AND THE BORROWER 7.01 The principal weakness in the Bank Group's performance occurred at the outset. Since this was the first project of its size in Nepal, no relevant prior experience with local conditions was available and the Bank - 30 - Group did not fully anticipate the inherent risks involved. In hindsight, it would have been prudent to have had a panel of experts to review the feasibility study, and geological and hydrological data, including the record of investigations, made by the Kulekhani consultants. Under OMS 3.80, which was issued in June 1977 after the appraisal of this Project, a panel of experts is required to be constituted to look into the design and safety aspect of the dam and associated works for large hydroelectric projects. In the case of Kulekhani, only one expert was retained for this purpose. It is possible that if a full panel consisting of civil engineers, geologists and a hydrologist had been constituted from the beginning, then the prob lems resulting from the tunnel failure and landslide could have been avoided or at least minimized. Also, the Bank Group could have required the detailed engineering to have been carried out up to and including the construction phase before Credit approval, which would have resulted in better cost estimates. 7.02 Otherwise the Bank Group's role in the project was instrumental in its successful completion. Project execution proved difficult and without the Bank's close involvement, it is likely that there would have been addi- tional serious problems. On a number of occasions, the Bank Group rendered advice on the need for specialized equipment and outside expertise, and advised on changes of certain key personnel. Experienced Bank Group staff conducted inspections and participated in discussions on solutions to major problems. The Bank Group participated in the Project in greater depth than is usual, because of the Nepalese lack of experience. 7.03 The Borrower's performance was generally satisfactory, given its inexperience with major projects. The Nepalese authorities were responsive to the Association's advice and in most cases agreed to recommended actions. However, the Borrower failed to implement tariff increases according to the schedule included in the Appraisal Report (para 4.20), and to eliminate by the agreed date the royalty surcharge on electricity sales. The failure to implement these measures prevented NEC achieving it rate of return targets (para 4.22). VIII. CONCLUSIONS 8.01 Although the 60 MW Kulekhani Project was completed two years behind schedule and a cost overrun of 80% occurred, the Project is now operating successfully and has assumed a vital role in supporting Nepal's economy. Load curtailment was discontinued following its commissioning and there is now sufficient generating capacity to to meet Nepal's projected load growth until 1989, when additional capacity is scheduled for completion. 8.02 The two major, and related, problems which were encountered concerned the unstable geological conditions in the project area, and the construction - 31 - of civil works. These were largely responsible for the delay in Project completion and the consequent increase in Project costs. In addition to increased Project costs, Nepal was penalized with foregone industrial output and revenues from commercial and other activities. 8.03 A perennial problem has been low tariff levels, which have affected adversely NEC's financial performance. However, its finances have been manageable because of negligible debt service and the absence of an earnings requirement to finance generation and transmission facilities, which were being financed under grants. However, this position is changing since loans and credits are being used to finance capital expansion. Tariff increases are required if the power subsector is to be financially viable and able to finance a reasonable share of the costs of future projects from internal resources. 8.04 From an operations standpoint, the geology of the area still poses some problems. The November 1983 landslide could have had serious consequen- ces if it had occurred in a location where it would have interferred with the facilities. Adequate monitoring of ground and soil conditions should be maintained, and the Government and the Association should devise an arrange- ment to ensure that this occurs. 8.05 A number of lessons were learned from the Project. An important lesson was that major construction in the Himalaya area, and other nearby ranges, should be approached with great caution and only following extensive investigation of conditions. To do otherwise is to risk major geological and construction difficulties, significant delays in project completion and large cost overruns. 8.06 Experience with the Kulekhani Project confirms the necessity of having a panel of experts to review feasibility studies for complex civil works projects. Feasibility studies may suffer from a number of defects, including inadequate exploration of geological conditions, unrealistic implementation schedules and cost estimates for projects which are new in the sense of previously not having been executed in the country. The absence of a panel of experts for Kulekhani highlights the need to follow this prescribed Bank Group practice. In addition, the Project cost estimates would have 5een improved if bids had been called before presenting the Project to the Executive Directors. The Bank Group has now made this man- datory in prescribed circumstances. - 32 - ANNEX 1 NEPAL KULEKHANI HYDROELECTRIC PROJECT Completion Report Cost Estimate US$ Million ------ Appraisal------ ---------Actual--------- Foreign Local Total Foreign Local 1/ Total Preliminary works 0.5 0.3 0.8 - 1.709 1.709 Resettlement - 0.6 0.6 - 1.139 1.139 Civil works 39.6 7.9 47.5 2/ 75.565 13.330 88.895 Equipment (a) Hydro mechanical 3.4 0.3 3.7 2.394 0.263 2.657 (b) Elctro-mechanical 8.5 0.6 9.1 11.920 0.506 12.426 (c) Transmission and Substations 1.8 0.3 2.1 2.515 0.354 2.869 Sub-total 53.8 10.0 63.8 92.394 17.301 109.695 Engineering Services 2.7 0.3 3.0 4.706 0.565 5.271 General Expenses - 1.0 1.0 - 4.915 4.915 Duties and Taxes - 0.2 0.2 - 2.746 2.746 Total 56.5 11.5 68.0 97.100 25.527 122.627 1/ The following exchange rates were used to convert annual local expenditure in NRs to US$: US$1.0 = NRs 12.02 (FY76), NRs 12.5(FY77), NRs 12.36 (FY78), NRs 12.0(FY79, FY80, FY81), NRs 12.96(FY82), NRs 13.86 (FY83) and NRs 15.3(FY84). 2/ This includes the contingencies estimated for the civil works in the appraisal report, namely physical contingencies at 11.5% and price contingencies at 58% of base cost including physical contingencies. The difference between the foregoing and total estimated contingencies in the SAR has been allocated on a prorata basis for the items shown under equipment. &{！蠟！ 認F｝寥誰廈緝i蓄 論叮I話邑整” 發91:; 齋視！‘莖 酒釁！。 驕！：。，亡以”限 胤！I•嗆｛二 叩―”牌認縴引亂： 霹―：。：：。纖谿 斤遞！,’鳥〔論 ,’一•拷！; “此屹屹亡馴．。。 遝｛〕昤 丰寥疋吃：云。壯老―亂― :;!::：〔：;;！。 :!;!!:::::!！。 一”_，。＿::.;:;!:!!,} NEPAL KULEIMAWI MROELECTRIC PROJECT COMPLETION REPORT Summary of MaIn Contracts Date of Awarded Tender Signing Contract Actual TO Called of contract Amount Asmat Civil works Sesbu Construction Co., 7/l/76 8/31177 US$52.150,000 USS74,800.400 Korea NR 197.021,215 MR 161.079 433 Blectro-Neclutuical Okurs Co.. 6/1/77 618/78 Y 2.645 Million T 2,645 Million Equipment Japan MR 4.112.300 MR 6.209.300 Hydro-Neclievical Cisco International. 3/25/17 1/18/79 Y548,558,000 Y 548,558.000 B"ipment India MR 2,054.000 02 3,214.000 Substation Crompton Greaves, Ltd., 7/l/77 4/28/78 V 578,746,000 T 579,691,000 Equipment India MR 1.013,200 MR 4,625.000 Diesel General Trading Co.. 4/4/77 - T 161.100.000 T 157,650.000 Sets Nepal MR 524.600 MR 749,600 01~& halane Sheeta fi7-PT8 (Ra Million) 1976/77 1977/78 1978/79 19798 19SWI 1981IM2 182.83 An af Julv-15. Formeant Acual Forme at Actual orecat rat ! - Foreat ,g Fr t AcaL orat gaål mm iedAntets ried agset* la operation 448.3 396.4. 564.8 441.9 741.3 449.4 1,559.9 459.0 1.568.5 545,1 1,640.1 793.8 1648.7 913.8 Les: Ao~lated depreciation Ja u -tu -2L± -aL a dad N2.4 .i 13. aÅ 172.4 A1,I ._»219.0 f.aL Total Det 1ixed Aseta 403.6 338.2 494.9 372.2 657.0 367.2 1,457.5 363.9 1.431.4 435.3 1.467.7 662.3 1,439.7 757.9 carrant Asket# Cach 2.0 7.1 3.9 10.5 3.5 10.0 2.2 17.8 3.8 10.9 6.2 13.8 6.3 28.0 uventories 5.5 8.3 5.6 9.7 7.3 10.7 14.5 12.7 14.3 19.7 15.0 21.2 17.0 22.5 Accounts receivable 5.6 9.5 7.2 11.8 9.0 14.3 11.0 19.4 26.0 23.1 28.0 30.1 30.0 32.3 Accounto recoverable -JW jag _u,a ju. .Ag n1i JÅ .¿.j, g,A .aaI »a lu JU lIM u Total Current Aset 16.6 31.1 20.5 38.5 23.8 48.5 31.9 70.8 49.3 79.1 54.2 98.7 58.3 114.5 Investments 0.2 4.3 0.2 4.5 0.2 4.5 0.2 4.3 0.2 3.0 0.2 5.0 0.2 5.0 Mvancea for coastruction JL . .. .,-::- 29. 0 _-_ 12.0 __--ZO..aa. --- TOTAL ASS 420.4 373.6 538.6 415.2 723.0 420.2 1.489.6 439.0 1,509.9 519.4 1.534.1 766.2 1,562.2 V7.4 CAPITAL ApD LIAILITID Governcent iuveotment 366.1 360.3 465.6 398.1 633.1 398.1 633.6 398.1 634.1 421.5 634.6 655.5 635.1 755.5 Coames coutribmtions - 8.4 - 9.4 - 10.5 - 10.5 - 10.5 - 10.5 - 10.5 Retained eanings ~L1a -lWa 27.2 (17.5) .A0& L2A43 j9. 11.7a 13) 2"i AZal jui,3 1220 ..L6 Total aquity 374.9 349.2 493.3 390.0 678.1 3M.2 703.3 396.9 735.6 422.7 772.5 653.5 814.1 762.6 L~*-m= Dcht 39.5 - 38.8 - 38.1 - 779.3 - 767.1 47.2 754.1 44.2 740.3 41.0 Current Liabilities _JA 6g -i- aJA _Mal -1^1 -«I __u _tI 7,8 -TaL T0TAL CAPITAL AN LIAILITIm 420.4 373.6 538.6 415.2 723.0 420.0 1.489.6 439.0 1,509.9 519.4 1.534.1 766.2 1,562.2 87.4 Debt/squity gatto 10/90 - 7/93 - 5/95 - 53/47 - 51/49 10/90 49/51 6/94 48/52 5/95 EMi 1~on Btateme nta21-Erm 1976177 1977178 19719 1979189 1iut Ig9ulv 19Mn V1iscal wer nden .7elv 15: Forecas egggg . ÉL Foecst1Foecs kIL li asmUiFreca MZL KK MI1 S Korecaist kIL oecas AI Ib av fotele mar i llUen 1"g.1 137.8 222.3 155.4 242.1 112.0 25.0 195.0 526.1 201.2 527.0 228.5 538.0 333.9 Ub <,11( ~ilien 36.7 92.4 162.8 106.5 179.1 119.3 216.4 137.2 447.1 133.5 445.3 148.2 43D.9 226.1 syftm 1omse (9) 27.0 33.0 27.0 33.0 26.0 34.3 24.1 29.7 15.0 33.7 15.5 35.1 16.2 32.9 ~avaga reeM (patoa) 43.4 38.0 57.4 38.0 57.7 39.3 57.5 43.8 73.6 52.4 . 73.6 52.2 73.6 55.2 opera o~ auee Sat * lectritty 56.3 34.9 86.6 39.6 96.4 45.8 117.6 58.7 210.8 68.7 224.8 75.6 242.3 121.5 Oter o ~vnt1ag re~ " .1 " . u, _l .W ..1 -4a -A LI .-U .U ..6. __ Tota 6.9 36.0 8F.2 41.0 97.1 49.3 113 63.0 211.6 74.0 225.6 80.8 243.1 126.8 Op«attes a aiatenance 12.5 13.3 16.8 16.1 21.2 21.2 29.4 24.9 42.6 29.2 45.3 40.6 50.4 49.0 g hae 6.7 1.5 6.7 3.2 15.8 4.5 6.7 6.0 - 22.6 - 14.8 - 9.0 DLpstatioa 8.1 10.8 14.2 11.6 14.4 ÅL5 18.1 12.9 34.7 14.7 35.3 21.5 36.6 24.6 aoyalty rchG - (0.1- 7.8 - 15.9 - - - - - - - Fnrebae at ~a 4.4 0.6 - 0.7 - 1.7 - Li - 1.7 - 2.8 - 26.8 . -.1 .-- Å.- A&al ." .L ..Ai .-" . . . Total m.i M.1 U2a ZZA IL. Ma. a. A&1 AL. W2. 22. Må.A u l»l Opeating Xma (befor inteatst) 10.1 9.9 21.2 1.6 19.7 (6.5) 27.0 12.7 M.7 4.4 90.4 1.1 96.3 10.5 L~8er latetet -- .LA --- .i --- å" Mi L al -Li et 2cea. 10.1 9.9 18.8 1.6 17.4 <6.5) 24.7 12.7 31.8 2.4 36.3 (3.2> 41.1 6i9 Rate af. (bUraga *et timid assets in Operaton) 328.0 289.7 499.0 355.2 492.0 369.7 652.0 365.3 1,444.0 399.6 1.418.0 551.3 1,453.0 710.2 Rte af rem- (1) 3.1 3.4 J/ 4.2 0.5 4.0 (1.8) 4.1 3.5 6.0 1.1 6.4 0.2 6.5 1.5 a rate of rete Sa o~etad du. to hEC t abatag ta royalty pay~t Of o" 7 -t llloa In YT77. All~wing for thia payt. th~ rata of retur s 1.O. MEPAL: CLKMANA HYMo ELECTRIC PROJECT CmPLETION REPORT Assumptions for Economic Internal Rate of Retur Actual Disbursement of lulethai Proiect (in US4 Thousand) Energy Generated at Kalekhani 1. r Z Z2 21 11 SO 8 82 8 4 Total 8. [W Total 691 565 8940 17,966 34,583 40,429 15,015 3320 1188 122,097 FT82 29.0 (actual) Foreign 584 167 6962 13,615 28,647 32.497 11, 62 1912 844 97,090 FY84 91.0 (actual) Local 1073981902 3980 5,276 6,788 2,806 1263 341 2261nformation Taxes - - 76 371 660 1,144 347 145 3 2,746 FY85 110 0 (assumed) shows actuale: FY82 - 27; FY83 - 88; FY86 165.0 (assumed) FY84 - 83; and FY85 104. These Distribution Cost FY87 211.0 (assumed) minor differences do not influence FY88 299.0 tassumed) economic calculation, however. 2. Out of US$ 6. 5 million (foreign) spent on improvement of Kathmandu distribution sys- to tem, 15% has been assumed to be spent f or evaquating Kulekbani Power, of which annual FY2027 299.0 (assumed) disbursement from FY79 to FY82 is assumed to have been 10, 30%, 302, 30%. Annual Eneray Sold to India Annual 0 6 N Charles -9. FY82 5 GWh (actual) 3. 0 6 X charges are assumed as 1.4% of Capital Cost, except in the first year (FY82) FY83 6 GWh (actual) when only one unit was commissioned, when they were assumed to be 1.12 of capital cost. FY8 o82027 26 G (assumed) Other Costs System Losses 4. Other costs include service charges at US cents 0.211/Wh and administrative expenses 10. FY82, 322 (actual); FY83, 301 (actual); FY84, 28% (assumed); FY85, 261 at US$0.237 million per annum at 1982 level. These costs are consistent with the costS (assumed); FY86, 24 (assumed); FY87, 23! (assumed); FY88, 222 (assumed); FY89, 211 assumed in BAR at 1974 level. (sue) Y6 4 asmd.F8.21(sue) Y422(sue) T9 1 (assumed); FY90, 20% (assumed), F91-95 18% (assumed), FY96-2000, 151 (assumed); FY2001 SCF to 2032, 101 (assumed). 5. No standard conversion factor has been used in order to be consistent with BAR. T Inflation Rates in Nepal 11. US cents 3.3 per Wb upto April 83 (actual) - used for calculating benefits in FY82 and FY83 6. FY Local/ Foreign 2 5.1 per Sb upto March 85 (actual) - used for calculating benefits in FY84 and FY85 onwards 8.4 per Wh beyond June 85 (agreed to be implemented) - used for 75 5.0 (assumed) - calculating benettts from FY86 onwards 76 -0.7 7.3 0.9 per Wh for power supply to India (actual) 77 2.7 5.1PrcLel 78 11.2 13.1 7D 3.5 1.1 12. Costs and tariffs used in the calculations are based on 1982 price levels. 81 13.4 1.8 82 10.4 -3.0 83 14. -0. 13. Fuel saving is based on following assumptions; out of 25M diesels in Nepal, only low 85 8.0 (projected) plant at Retanda, installed in 1981, has been considered. Possible annual generation at 86 7.0 (projected) Retauda at 50% Plant factor - 4 GRb. 667.0 (projected) Annal Energy sold - 44 X 0.7 * 31 GWh (assuming 301 losses) ./ Source - Nepal Rastra Bank, various issues of Quarterly Economic Bulletin Anmal tuel Consumption per GWh at 401 efficiei%cy - N60.xj16 - 215 tons / Source - Vorld Bak. Economic Analysis and Projection Department, July 1984 (Manufacturing Unit Value Index) Economic Cost of Diesel -US$ 185 per ton. Toa oeta fKllh"Value of Fuel esed per year - 215 x 185 z 44 x .7 - US $1.23 million. aR Total Potential of Kieatano 7. Firm Energy - 165 GWb Secondary Energy - 14. go escalation in the price of diesel has been included. Total 299 Cn pi per oh a fiye25 15. oe life of project has been assumed to be 50 years from the date when construction started in order to be consistent with SAR. IN& VULUMhJI BTOlllQXWRXC FROJUCT COMPLITION BRORT Sources and Anolications of Funds F77-F73 1976/77 1977/78 1978/79 1979180 1980181 1981182 1982/1 Fiscal year endina July 15: Frags. olSal 1.1ESPA$ AattL Frecst ActuaL FoeSa. AStuaL Forcas.t ActSul Foreca Actual Fotftast Actid soM O JW Operating income before interst 10.0 9.9 21.3 1.6 19.7 (6.5) 27.0 12.7 96.6 4.4 90.4 1.1 94.3 10.5 Depreciation ... I 114 6.1 11. 1A,A 12.5 IL. 13 . 7 i.a -ZA .5. 36.6 24.1 Total Internal Cash Generation 18.1 20.7 35.4 13.2 34.1 6.0 45.1 25.6 121.3 19.1 125.7 22.6 130.9 35.1 cs t. equity contribution 114.5 100.9 110.0 37.8 167.0 - 6&0 - - 23.4 63.0 234.0 50.0 100.0 Long-tem tames (capital iavestment) 39.5 - - - - - 742.0 - - 47.2 - - - - Consners contributions .5.,1 . ..... ..i d .-.1. ...A. ...0.5 ..I .-.l.. - - TOTAL SOURCES o 10NDS 172.6 123.4 145.9 52.0 201.6 7.1 855.6 25.6 121.8 89.7 189.2 256.6 181.4 135.1 APPLICATIMS Of WUNDS Capital investment by NEC 5.7 6.9 6.4 8.0 9.5 7.5 8.6 9.6 8.6 12.9 8.6 14.7 8.6 20.0 Capital investment transferred SEC i2i&A l00I 1 g lid 1h,A -1 . 01&a - - 23.s 63. 234.0 Total Capital Investment 159.7 107.8 116.4 45.5 176.5 7.5 818.6 9.6 S.6 86.1 71.6 248.7 5.6 120.0 Avances for construction 12.0 - 25, - 19.0 - 26.0 - 30.0 - 47.4 - 53.0 - Interest - - 2.4 -- .3 - 54.9 2.0 54.1 4.3 53.2 3.6 Amortisation -P-. .. vA- . . UZ - 13.0 3.0 lu Total Debt Service - - 3.1 - 3.1 - 3.1 - 67.1 2.0 67.1 7.3 67.1 6.8 toeese is worJI aftal .I .LS A ..1.4 -It 19ARhlLI 1A 1..1 .5 0. ..&Z 1A WEAL AWMCATIORS OF mgu 172.6 123.4 V45.9 52.0 201.6 ,.1 855.6 25.6 121.8 89.7 189.2 256.6 181.4 35.1 IR& Klekhaani Rydro Blectric ProJect Comletion Rewort Internal Economic Rate of Return (All Costs are in s$ Million) Cost stresk Denefdit Stream FT Proiect Cost Distribution Q,&AK Other Cos ts. To"I Domestil RDor Fwl Cost Tota NmanOn. Cost Qa 1Sric Admin. Coat sales to India S82ima Seneits es8 Lal Total xhAEA Eenses 76 0.9 0.2 1.1 - - - - 1.1 - - - - 77 0.3 0.6 0.9 - - - - 0.9 - - - - 78 10.0 2.7 12.7 - - - - 12.7 - - - - 79 17.3 5.1 22.4 0.6 - - - 23.0 - - - - 80 32.0 6.6 38.6 1.6 - - - 40.2 - - - - 81 33.1 7.7 40.8 1.5 - - - 42.3 - - - - 82 11.8 2.8 14.6 1.5 1.5 0.06 + 0.237 17.9 0.50 0.05 1.23 0.55 83 2.0 1.1 3.1 - 1.9 0.19 + 0.237 5.4 1.67 0.05 1.23 2.95 N 84 PA 1a - 1.9 0.23 + 0.237 3.6 3.31 0.04 1.23 4.58 1 Total 135.4 85 1.9 0.23 + 0.237 2.4 2.89 0.04 1.23 4.16 86 1.9 0.348 + 0.237 2.5 3.96 0.15 1.23 5.34 87 1.9 0.445 + 0.237 2.6 5.40 0.15 1.23 6.78 88 1.9 0.630 + 0.237 2.8 8.15 0.15 1.23 9.53 89 1.9 0.630 + 0.237 2.8 8.26 0.15 1.23 9.64 90 1.9 0.630 + 0.237 2.8 8.38 0.15 1.23 9.76 91 1.9 0.630 + 0.237 2.8 8.59 0.15 1.23 9.97 92 1.9 0.630 + 0.237 2.8 8.59 0.15 1.23 9.97 93 1.9 0.630 + 0.237 2.8 8.59 0.15 1.23 9.97 94 1.9 0.630 + 0.237 2.8 8.59 0.15 1.23 9.97 95 1.9 0.630 + 0.237 2.8 8.59 0.15 1.23 9.97 96 1.9 0.630 + 0.237 2.8 8.94 0.15 1.23 10.32 97 1.9 0.630 + 0.237 2.8 8.94 0.15 1.23 10.32 98 1.9 0.630 + 0.237 2.8 8.94 0.15 1.23 10.32 99 1.9 0.630 + 0.237 2.8 8.94 0.15 1.23 10.32 2000 1.9 0.630 + 0.237 2..8 8.94 0.15 1.23 10.32 2001- 1.9 0.630 + 0.237 2.8 9.52 0.15 - 9.67 2027 1.9 0.630 + 0.237 2.8 9.52 0.15 -0.67 EIRR based on existing tariff - 3.33% EIRR based on proposed tariff - 6.1% 0