Sri Lanka - Second Power Distribution and Transmission Project

Document of The World Bank FOR OFFICIAL USE ONLY Report Number: 19396 IMPLEMENTATION COMPLETION REPORT SRI LANKA SECOND POWER DISTRIBUTION AND TRANSMISSION PROJECT (CREDIT 2297-CE) June 30, 1999 Energy Sector Unit South Asia Region This document has a restricted distribution and may be used by recipients only in the performance of their official duties. Its contents may not otherwise be disclosed without World Bank authorization.  CURRENCY EOUIVALENTS Currency Unit = SL Rupees Appraisal year 1991: US$1 = SLR 41.00 Intervening year 1995: US$1 = SLR 53.25 Completion year 1998: US$1 = SLR 66.03 MEASURES AND EOUIVALENTS 1 kilometer (kin) = 0.6214 miles (mi) 1 meter (m) = 39.37 inches (in) 1 kilovolt (kV) = 1,000 volts (V) 1 megawatt (MW) - 1,000 kilowatts (kW) = 1,000,000 watts 1 gigawatt hour (GWh) = 1,000,000 kilowatt hours (kWh) 1 MVA = 1,000 kilovolt amperes 1 MVAr = 1,000 kilovolt amperes reactive FISCAL YEAR July 1 - June 30 ABBREVIATIONS AND ACRONYMS CEB - Ceylon Electricity Board) DMP - Distribution Master Plan ERR - Economic Rate of Return GOSL - Government of Sri Lanka ICR - Implementation Completion Report IDA - International Development Association LECO - Lanka Electricity Company Limited NORAD - Norwegian Agency for Development Cooperation NDF - Nordic Development Fund ROR - Rate of Return SAR - Staff Appraisal Report SIDA - Swedish International Development Cooperation Agency SLRs - Sri Lanka Rupees SPDTP - Second Power Distribution and Transmission Project WTP - willingness to pay Vice President: Mieko Nishimizu Country Director: Mariana Todorova Sector Director: Alastair J. McKechnie Team Leader: Marc Heitner Task Leader: Sumith Pilapitiya  FOR OFFICIAL USE ONLY IMPLEMENATION COMPLETION REPORT SRI LANKA SECOND POWER DISTRIBUTION AND TRANSMISSION PROJECT (Credit-2297-CE) Table of Contents Page No. Preface Evaluation Summary............. . i..... Part I: Project Implementation Assessment A: Evaluation of Projects ..1 B: Achievemnent of Objectives .1 C: Major Factors Affecting the Project ........................ , . , . 5 D: Project Sustainability .6 E: IDA Performance .6 F: Borrower's Performance .................................................,. 7 G: Assessment of Outcome .7 H: Future Operations .7 I: Key Lessons Leared .8 Part II: Statistical Tables Table 1: Summary of Assessments .9 Table 2: Related Bank Loans/Credits .10 Table 3: Project Timetable .10 Table 4: Credit Disbursements: Cumulative, Estimated and Actual .10 Table 5A: Key Indicators for Project Implementation - Financial and Institutional .11 Table 5B: Key Indicators for Project Inplementation - Distribution Works .12 Table SC: Key Indicators for Project Implementation - Transmission Works .13 Table 6: Studies Included in the Project .14 Table 7A: Project Costs .14 Table 7B: Financing Plan .14 Table 8: Economic Rate of Retur .14 Table 9: Status of Legal Covenants .15 Table 10: Compliance with Operational Manual Statements .18 Table 11: Bank Resources: Staff Inputs ................................................ 18 Table 12: Bank Resources: Missions .19 ANNEXES A: Mission's Aide Memoire .20 B: Borrower's Evaluation .29 Appendix 1 .38 Appendix 2 .39 Appendix 3 .40 C: Operation Plan .41 D: CEB Financial Statements .43 E: Recalculation of Economic Rate of Return. 46 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.  IMPLEMENTATION COMPLETION REPORT SRI LANKA SECOND POWER DISTRIBUTION AND TRANSMISSION PROJECT (Credit-2297-CE) PREFACE This is the Implementation Completion Report (ICR) for the Second Power Distribution and Transmnission Project in Sri Lanka, for which Credit 2297-CE in the amount of SDR 37.5 million (US$ 50.0 million equivalent) was approved on September 10, 1991 and made effective on December 16, 1991. The Credit was closed on June 30, 1998. Final disbursement took place on December 14, 1998, leaving an undisbursed balance of SDR 5.66 million to be cancelled'. The ICR was prepared by Sumith Pilapitiya, with assistance from S. Vijay Iyer, Stefan Jansson, Janice Williams-Palenzuela, Anna Goodman (all South Asia Energy Sector staff) and Sanath Ranawana, Consultant. It was reviewed by Marc Heitner, Team Leader for Sri Lanka, Energy Sector Unit, South Asia Region. Preparation of this ICR began after IDA's final supervision mission (May 18 - 29, 1998), and subsequent to IDA's decision on June 28, 1998, not to extend the Credit beyond the original closing date of June 30, 1998. It is based on material in the project files as well as discussions with the Ceylon Electricity Board and Government officials associated with the project. The beneficiary contributed to the preparation of the ICR by providing its own evaluation report, arranging field visits, and commenting on the draft ICR. 1 The amount to be cancelled includes US$ 128,590.34, which is to be refunded by CEB from the Special Account.  IMPLEMENTATION COMPLETION REPORT SRI LANKA SECOND POWER DISTRIBUTION AND TRANSMISSION PROJECT (Credit-2297-CE) EVALUATION SUMMARY Introduction 1. The Bank Group's involvement with Sri Lanka's power sector began in 1954 with a loan' to the Government of Sri Lanka (GOSL) for the expansion of the Aberdeen-Laksapana hydroelectric scheme. Since then, the Bank Group has made eleven additional loans/credits for the development of the power sector to meet demand at least cost, to improve the quality and reliability of supply, and to promote institutional reforms. 2. GOSL has historically given high priority to developing the power sector through the development of hydro-power generation capacity. Over the past decade, the Government has initiated reforms to rationalize the organization of the sector. Fragmentation of the responsibility for distribution was identified as a major problem in this respect. Apart from Ceylon Electricity Board (CEB), the Lanka Electric Company Limited (LECO) and 212 other licensees (local authorities) were responsible for the distribution and sale of electricity. To address these organizational issues and rehabilitate the distribution system, a master plan for development of the distribution system was prepared under the Ninth Power Project (Cr. 1736)2, based on which GOSL decided on a phased takeover of all licensees by CEB and LECO. The Distribution Master Plan (DMP) also recommended that the management of power distribution be decentralized to the divisional levels within CEB. Accordingly, 133 licensees were taken over by CEB and their distribution systems were rehabilitated under an IDA Credit (Cr. 1933-CE)3 over May 1989 to June 1991. The Asian Development Bank (ADB) financed LECO's takeover of another 23 licensees. This ICR relates to the Second Power Distribution and Transrnission Project (SPDTP) project, whose overall objective was to assist GOSL/CEB in the second phase of institutional reforms (including the takeover of the remaining 56 licensees) and to implement other measures recommended in the DMP to strengthen CEB' s financial, operational and technical management capabilities. Evaluation of Objectives 3. The specific objectives of the project were to: (a) support rationalization of power distribution with a view to reduce system losses in distribution systems operated by the remaining licensees and to improve the quality of supply; (b) augment the transmission facilities to meet projected demand; (c) strengthen CEB's institutional capacity by providing training programs; and (d) assist in the preparation of a technologically, environmentally, and socio-economically sound hydropower project. The objectives were clear, realistic and consistent with IDA's and GOSL's strategy for the power sector at the time. I Loan 101-CE, Aberdeen-Laksaapana Project, 1954. 2 ICR 1736-CE., Report No. 14724, June 20, 1995, Ninth Power Project. 3 ICR 1933-CE, Report No. 15413, March 18, 1996, Power Distribution and Transmission Project.  ii Implementation Experience and Results 4. Although the project achieved its main sectoral and institutional objectives, the project has not been fully completed. It is expected that upon completion of outstanding civil works, the physical objectives would also be achieved. Rehabilitation of distribution systems taken over under the project was also not completed by the Credit closing date due to delays in procurement and project implementation. The project achieved its institutional objectives in the distribution sub-sector by CEB taking over all the distribution systems operated by licensees, except within the Northern Province due to the prevailing security situation there. Although the CEB has no detailed information on the reduction in system losses of all the systems taken over under the project, the limited information available indicates significant reductions in individual licensee areas, such as from 27.6 percent to 12.0 percent in the Muniwangoda Urban Council Area. Overall, however, CEB's system losses declined marginally from 18.8 percent in 1991 to 18.7 percent in 1998. 5. The project provided for additional transmission capacity in accordance with CEB's least-cost transmission expansion plan. In 1996, at the request of GOSL, IDA agreed that a part of the transmission component would be financed by other donors. Instead, two other sub-stations were substituted for IDA financing in 1997'. However, implementation of the IDA-funded physical works was poor--with four out of the five major contracts either incomplete at Credit close or completed with up to three-year delays. Some of these delays will make it necessary for CEB to use approximately US$ 6.6 million of its own resources to finance the completion of these components. Under the institutional development component of the project, funds were available for technical assistance to improve skills in the areas of utility management and financial management. The training objectives of the project were achieved satisfactorily. 6. The key factors that adversely affected the timely achievement of the physical objectives were: (i) GOSL's protracted procurement procedures; (ii) inadequate supervision by CEB project staff of certain components; (iii) security considerations in the Northern Province which resulted in reduction and modification of the transmission works; and (iv) undue priority attention to rural electrification schemes which diverted manpower and other resources from the project. The main constraints to timely project implementation were those common to most government utilities, namely, lack of financial and operational autonomy resulting in procurement delays, lack of commercial orientation and low tariffs resulting in poor financial results. 7. The financial performance of CEB during the project period was not fully satisfactory due to its failure to meet the Rate of Return (ROR) target (except for one year); there were improvements in some areas such as reduction of arrears. Tariffs were increased by an average of 12 percent per annum between 1992 and 1998. In nominal terms, the average tariff has increased from 2.24 SLR/kWh in 1992 to 4.15 SLR/kWh in 1997. However, in inflation adjusted terms, the tariff decreased marginally during the period. In spite of IDA's repeated reminders, GOSL/CEB did not demonstrate the necessary commitment to fully meet the revenue target. 8. IDA was diligent in project design, appraisal and supervision with regular missions identifying implementation problems and recommending remedial measures. However, such measures were not always implemented on time by CEB. In retrospect, had IDA taken a stronger stand towards CEB on implementation of physical components as well as compliance with the revenue covenant, project outcomes might have been improved. 220kV sub-stations at Biyagama and Kelanitissa instead of Anuradhpura and Kotmale.  iii Project Sustainability 9. The completed physical works will be part of CEB's integrated transmission and distribution system. Adequate resources are expected to be provided by CEB for the proper operation and maintenance of the newly created facilities. Hence, the project benefits are likely to be sustained. In order to meet the growing demand for electricity efficiently, CEB must continue investing in new assets. A recent Japanese International Cooperation Agency study concluded that the investment needs for power generation, transmission and distribution would be about US$ 300 million annually over the next 10 years. However, investments appear to be declining-CEB's investments in 1995 were US$ 70 million compared to US$ 130 million in 1991 and only averaged US$ 100 million annually in that period. It is unlikely that the funding available from internal sources and donor contributions will together exceed US$ 175 million annually. There is thus a compelling case to expand the resources available for investment by creating opportunities for private sector participation in the electricity sector. For this reason, GOSL is in fact, contemplating a series of reform measures to create an enabling environment for private participation in the sector. Summary of Findings 10. CEB's ability to perform effectively depends upon GOSL enabling the utility to exercise the autonomy provided for under the CEB Act. CEB's autonomy has eroded over the years. The restoration of CEB's autonomy and financial viability are essential preconditions for smooth execution of new public sector power projects in coming years. 11. The following lessons can be drawn from this project: * Procurement: The main obstacle to achievement of the project physical objectives on a timely basis was GOSL's protracted procurement procedures. CEB should be given adequate autonomy in this area. LECO, which operates as an autonomous company exhibits much better performance in this respect. Further, all detailed design work and procurement actions should be completed during project preparation so that implementation is expedited. * Tariffs: At the root of CEB's poor financial performance is its inability to function as a commercial entity and recover its full costs through realistic tariffs. It is essential that tariff setting be moved out of the political arena. Tariffs should be regulated independently within an agreed regulatory framework, and on the basis of agreed performance targets. * Monitoring: Stronger actions by IDA and other donors to ensure CEB's financial performance might have resulted in a more successful project. Future operations should ensure advance donor coordination on project design and cofinancing opportunities during preparation, and focus on compliance with agreed conditions during project implementation. 12. IDA's strategy for the sector will be to facilitate restructuring, privatization, and creating an enabling environment to attract private investments to the power sector.  IMPLEMENTATION COMPLETION REPORT SRI LANKA SECOND POWER DISTRIBUTION AND TRANSMISSION PROJECT (Credit-2297-CE) PART I: PROJECT IMPLEMENTATION ASSESSMENT A. Evaluation of Proiect Obiectives 1. The objectives of the project were to: (a) continue supporting rationalization of power distribution organizations, particularly to reduce system losses in distribution systems operated by the remaining licensees and to improve the quality of electricity supply; (b) augment the transmission facilities to meet projected demand; (c) strengthen CEB's institutional capacity through training; and (d) assist in the preparation of a technologically, environmentally and socio-economically sound hydropower project. 2. The objectives of the project were relevant, clear and realistic. They were consistent with IDA's strategy for assistance to the power sector at the time, and with GOSL's sector development strategy. The distribution component of the project continued to support the rationalization of distribution systems, which had commenced under IDA Credit No. 1933-CE', and facilitated the takeover of the remaining licensees from Local Authorities. The transmission component was part of CEB's least-cost investment program to provide additional capacity to meet projected growth in demand. Consultancy studies were designed to develop CEB's institutional capacity. B. Achievement of ObWectives 3. This project clearly demonstrates the weaknesses in the institutional arrangements in the power sector of Sri Lanka. Whereas the Ceylon Electricity Board Act (goveming CEB) provides for autonomy and independence, the Government has increasingly rnicro-managed the sector, combining the roles of policy-maker, regulator and operator. Thus, CEB's procedures in terms of finance, human resources management and procurement became those of the Government. As a result, project implementation lagged and has affected the provision of services to consumers adversely. 4. The principal physical components of the project were: (i) rehabilitation and expansion of 56 distribution systems operated by licensees, targeted to be taken over by CEB during FY92-95; (ii) construction of about 152 km of 220-kV double circuit line with only one circuit strung initially; (iii) construction/augmentation of related 220-kV substations; (iv) construction of about 37 km of 132-kV double circuit line with only one circuit strung initially and 8 km of double circuit line and augmentation of related 132-kV substation; and (v) installation of about 70 MVA compensation equipment at selected substations to improve voltage level. In September 1995, GOSL decided to utilize other donor funds2 for construction and augmentation of the 220-kV substations at Kotmale and Anuradhapura. At the request of GOSL therefore, IDA agreed to substitute the 220-kV substations at Biyagama and Kelanitissa to evacuate power from new power plants to be constructed at Kelanitissa. No amendment to the Credit Agreement was required as these substitutions were within the project scope. I ICR 1933-CE, report no. 15413, March 18, 1996, Ninth Power Project. 2 From three Nordic institutions (NDF, NORAD, SIDA).  2 5. The distribution component of the project largely achieved its stated objectives. Of the 56 licensees remaining under local authority control, CEB took over all 22 licensees located outside thec Northern Province. In April 1996, it was agreed to suspend further attempts to take over the 34 licensees within the Northern Province due to the prevailing security situation in that province, and procurement activities were discontinued. It was also agreed to utilize available funds for the extensive rehabilitation needed at the Kandy distribution system which had been taken over in 1995. The Staff Appraisal Report (SAR) had identified this security risk, and it was agreed that disbursement on this component would depend on IDA being satisfied that the security situation was conducive to project implementation. Subsequently, CEB took over 10 systems in six Local Authority areas in the North as the security situation improved using its own resources. CEB is now contracting with private generators to supply power to isolated parts of the distribution system in the North. These generators will be moved to other more remote areas once supply from the 33-kV grid is established. 6. The transmission expansion components are part of CEB's least cost expansion plan, based on prevailing system configuration and load flow assessments. At the time of Credit closure, several of the major investment components were still under construction. However, notwithstanding the delays in implementing the transrnission components, the new facilities when completed would significantly contribute to the objective of meeting projected electricity demand. The component-wise details are as follows: * 132-kV Lines Rantambe-Badulla and Kotmale-Kurunduwatte: works completed but can be energized only after the 132-kV substations at Rantambe, Badulla and Kotmale are completed. * 132-kV Substations at Rantambe, Badulla and Kotmale: The completion date for this contract was May 1995, but the substations were still under construction at Credit closure. Low quality and defective equipment were the main reasons for delay in completion. * 220-kV Kotmale - Anuradhapura Line: The award of the contract to supply and erect this 165- km transmission line was delayed by about two years due to the protracted procurement process and disagreements with IDA on the selection of the contractor. After the contract was awarded in October 1996, slow implementation and inadequate supervision resulted in the works being only 50 percent complete at Credit closure. Approximately US$ 3.6 million would be spent from CEB's resources to complete this component. * 220-kV substation at Biyagama, together with components substituted at the request of GOSL in January 1996 including: (i) construction of a 220-kV substation at Kelanitissa; (ii) construction of two 220-kV bays at Biyagamna; and (iii) upgrading 132-kV Biyagama-Kelanitissa line to 220 kV. Following protracted procurement decisions, the contract was finally awarded in June 1997. Civil works at the site were delayed further by an additional 82 days due to a bomb blast at the boundary of the Kelanitissa Power Station site. At Credit closure, the civil works at the Kelanitissa site were 50 percent complete with less than 15 percent of the erection works completed. At the Biyagama site, only 33 percent of the civil works had been completed with less than six percent of the erection works completed at Credit closure. Upgrading of 132-kV Kelanitissa line to 220 kV was completed on time. 7. Fragmentation of responsibility for electricity distribution and supply--between CEB, LECO and the Local Authorities (licensees)--was considered to be a major obstacle to improving the efficiency and further development of the sector. The licensees have been faced with: high systems losses (averaging 25 percent); unreliable, poor quality and deteriorating supply; high arrears to CEB; long delays in connecting new consumers; and shortages of funding for proper operation and maintenance as well as  3 lack of competent staff. Acting upon the recommendations of-a Distribution Master Plan, GOSL had taken measures to rationalize the organization of the power distribution sector. The takeover of licensees' distribution systems by CEB and their rehabilitation commenced under the previous Credit (1933-CE). The SPDTP continued this activity towards its completion. 8. Most of the licensee systems were spread over the island and, in view of the economies of scale, it made sense at the time that they be consolidated into CEB, which operates the island-wide distribution system. The takeover at the time was to be supported by decentralization of distribution management to the divisional level within CEB. While the objective of the project was to reduce CEB's distribution system losses from 18.8 percent in 1991 to 12 percent by 1998, CEB achieved only a marginal reduction to 18.7 percent. One reason was CEB's centralized management structure and lack of autonomy, which was in sharp contrast to Lanka Electricity Company (LECO), established in 1983 under the Companies Act. LECO made considerable progress in reducing distribution losses and improving the quality of supply and service, as well as its revenue collection. 9. Upgrading its technical and management skills was a primary objective for CEB as a means to improve its performance and efficiency. The project addressed CEB's institutional weaknesses and provided various, largely successful, forms of technical assistance and training. Technical assistance was also provided to install a computerized project implementation, monitoring and reporting system. Overall, the training objectives of the project were satisfactorily achieved. A total of 80 members of CEB's staff received international training while about 9,400 were trained locally. The training followed an agreed plan which covered the following areas: utility management; financial forecasting and corporate planning; budgeting and budgetary control; cash and credit management; project accounting; management information systems; performance audits; and other topics. The training was useful and a majority of trained staff remained within CEB. However, it is debatable whether the efficiency gains from the training can be fully realized under CEB' s present institutional framework. 10. The Credit also financed a study to upgrade the Management Information System (MIS) at CEB. Although this study was completed, no significant improvement has been observed. This is mainly due to problems encountered in staffing, training and user commitment in implementing the recommendations of that study. 11. The project was to provide consulting services to update the feasibility study and prepare detailed engineering designs and bid documents for the Upper Kotmale Hydropower Project. This sub- component dropped at the request of CEB after Credit approval, as another donor offered to finance the technical assistance, as well as the investment required for that project. 12. The environmental impact of constructing transmission and distribution lines was negligible, and was adequately monitored. Most distribution lines were constructed alongside existing roadways, so they are visually similar to existing lines. New transmission lines were also constructed along existing public roadways and transmission corridors and had no significant environmental impact. Environmental clearance was required for the Kotmale-Anuradhapura transmnission line, since it was a new line exceeding 10 km, and at a voltage level exceeding 50 kV [the National Environmental Act's (NEA) criteria for requiring an environmental assessment for transmission lines]. Clearance was obtained by CEB after an environmental assessment, as required by the NEA. 13. In general, the efficiency of CEB's electricity supply improved under the project. Delays in connecting new consumers were reduced, while the number of customers per employee increased: 75 in 1992; 90 in 1993; 99 in 1994; 108 in 1995; 115 in 1996; 126 in 1997; and 130 in 1998. CEB has thus recorded impressive productivity gains during the project period. In support of the project's institutional objectives and to ensure CEB's financial viability, various financial covenants were agreed to between  4 GOSL and IDA. The revenue covenant specified that CEB maintain a rate of return (ROR) on net revalued fixed assets in operation of at least 7 percent in 1992-1993 and 8 percent thereafter. The rate was relaxed for the years 1992-1993 in view of a large increase in CEB's asset base' and CEB's commitment to meet the other financial covenants and commercial objectives, e.g. 30 percent self- financing of investments, debt service coverage ratio of at least 1.5, accounts receivable below three months of billing and current ratio of at least 1.2. 14. The ROR target was fully achieved only in 1995. One reason for CEB's inability to meet the revenue target was that tariff increases were not implemented as scheduled during the course of the project, and actual tariff increases were well below the required levels and not timely. In addition to insufficient tariffs, CEB's financial situation suffered in 1996 and 1997 due to a prolonged drought which affected the hydro-power generation capacity. CEB was compelled to rely heavily on its thermal capacity, thus increasing expenditure on fuel and causing it to purchase electricity at high prices from private generators. 15. CEB was advised both by IDA and the Asian Development Bank that a tariff increase of 12.5 percent in 1998 would be essential to recover from the financial setback suffered during 1996 and 1997. This would have enabled CEB to achieve a ROR of 7.3 percent in 1998, and, with additional increases in tariffs of 10 percent in each of the following two years, to restore its financial viability. However, tariff increases are largely decided upon by the Government and the political agenda often takes precedence over the commercial interests of CEB. The recommended tariff increases for 1998 were not implemented. 16. CEB' s self-financing ratio, accounts receivable levels and debt service coverage were satisfactory. Accounts receivables (in terms of months of sales equivalent) also improved towards the latter half of the project: 2.8 in 1991; 3.5 in 1992; 3.3 in 1993; 2.7 in 1994; 2.5 in 1995 and 1996; and 2.4 in 1997 and 2.7 in 1998. Thus, for the latter years, the rate was well within the covenant level of 3.0. CEB's actual performance, as compared to project covenants/appraisal projections is summarized in the table below: Table 1: Financial Performance Highlights COVENANT 1992 1993 1994 1995 19 1997 1998 Rate of Return Covenant 7.0 7.0 8.0 8.0 8.0 8.0 8.0 Actual 3.5 4.6 7.8 8.0 2.5 0.6 4.6 Tariff Increases (%) Projected 25 15 12 0.0 0.0 0.0 0.0 Actual 1.8 17.7 27.8 8.1 8.0 3.7 7.5 Debt Service Coverage Ratio Covenant 1.5 1.5 1.5 1.5 1.5 1.5 1.5 Actual 1.3 1.7 2.3 2.8 1.6 1.2 2.1 Accounts Receivable (mos.) Covenant 3 3 3 3 3 3 3 Actual 3.5 3.3 2.7 2.4 2.5 2.6 2.7 Self Financing Ratio (%) Projected 33 40 41 49 44 40 39 Actual 47 36 14 41 37 20 47 Current Ratio Covenant 1.2 1.2 1.2 12 1.2 1.2 1.2 ._________________ .Actual 1.0 1.0 1.9 2.3 1.9 1.7 1.6 17. The major components of the project were an integral part of CEB's long-term plan: the distribution component was identified as indispensable to address inefficiencies affecting licensees; the transmission component was part of the least-cost plan for transmission investments to link existing and future generating stations with load centers; and consulting services and training components addressed general deficiencies identified by CEB. Since the project contributed towards the overall improvement I Resulting from the commissioning of the Samanalawewa hydropower project.  5 of the electricity sub-sector, the benefits of the project to consumers could not be separated from benefits arising from other investments towards achieving CEB's long-term development objectives. 18. In view of the project being thoroughly integrated with CEB's least-cost development program, it was justified at appraisal through an economic analysis of CEB's entire program for the 10 years from 1991 to 2000. CEB's total investments for generation, transmission and distribution were included, as well as incremental fuel costs, and operating and maintenance costs associated with this investment program. CEB's incremental sales revenues were used as a measure of benefits. Based on the above, the economic rate of return (ERR) was estimated to 10.7 percent at the time of appraisal. 19. The economic analysis in the SAR was adjusted by replacing incremental sales revenue with estimates of consumer's willingness to pay (WTP) for the incremental electricity sales. This was considered a better estimate of economic benefits, as it would capture part of the consumer surplus. On this basis, the ERR at appraisal was estimated at 15.7 percent. 20. The ERR has now been re-calculated, using actual data for the period 1991-1998, and similar methods and assumptions as in the SAR (see Annex E). The resulting ERR is 12.2 percent, which is above the SAR estimate of 10.7 percent. Adjusted for (proven) WTP, the ERR increases to 14.8 percent which is slightly below the SAR estimate. As such, the investment program has been justified ex-post on economic grounds since it yields an ERR which is above the standard opportunity cost of capital of 12 percent. Further, the indicated ERRs most likely under-estimate the real benefits of CEB's 1991-2000 investment program, as the calculations largely reflect low tariff levels, and do not fully capture the consumer surplus. In its Operations Plan, CEB indicates that it intends to comply with the covenanted rate of return of 8 percent. This would require a tariff increase of about 30 percent over current levels. If such an increase is assumed to be in effect as from 2000, and maintained in real terms thereafter, the resulting ERR would be 16.8 percent. C. Maior Factors Affecting the Prject 21. The prevailing security conditions in the country did not pose a risk to overall project implementation (as anticipated in the SAR). IDA exercised its discretion on approving the component of the project relating to rehabilitation/expansion of the 34 licensees operating in the Northern Province. In April 1996, it was decided not to pursue this component of the project. CEB subsequently managed to take over 10 licensees in six local authority areas, when the security situation improved in 1997-1998. The security situation also caused delays in the licensee's implementation of another component: a bomb explosion on the boundary of the Kelanitissa sub-station delayed civil works by 82 days. This contributed to this component being incomplete at Credit closure. 22. A major factor that had a negative impact on CEB's financial performance was the extensive drought which prevailed in 1996 and 1997, which made it necessary for CEB to purchase high cost emergency power. 23. The most significant cause of delays in project implementation was GOSL's cumbersome procurement procedures. CEB has inadequate autonomy for procurement of materials and supplies to efficiently carry out its mandate. Although GOSL enhanced CEB's authority in procurement by raising the threshold from SLRs 20 million to SLRs 100 million (equivalent to US$ 1.5 million) at IDA's insistence, this threshold proved still inadequate for proper functioning of a utility of CEB's size. For amounts exceeding this threshold, various Cabinet-appointed tender committees are involved in bid evaluation and the final award recommendation requires approval by the Cabinet of Ministers. This evaluation and approval process was the major cause of delays in completion of virtually all physical  6 components of this project. Excessive Government control over procurement decisions was identified in the SAR as a risk which could delay implementation of the project. 24. Throughout most of the implementation period, CEB was not in compliance with the ROR covenant. Tariff increases, which are subject to approval from the Cabinet of Ministers were neither timely nor adequate. D. Project Sustainability 25. Upon completion, the project will be part of CEB's integrated transmission and distribution system. Total generation has grown at an average of 8.5 percent over the last five years to reach 5,100 GWh in 1997, and peak demand has grown at the rate of 6.9 percent over the same period to reach 1,037 MW that year. Electricity sales in 1997 reached 4,200 GWh and per capita consumption, 230 kWh. About 50 percent of the population has access to electricity, a ratio that has increased significantly from only 29 percent in 1990. However, over 1991-1995 CEB's investments dropped steadily from SLRs 6.7 billion to SLRs 3.8 billion, an annual average of less than SLRs 5 billion or less than US$ 100 million. Considerable amount of work has been carried out to assess the investment needs of Sri Lanka's power sector over the next 10 years. A Japan International Cooperation Agency study indicates that the investment needs for generation, transmission and distribution is about US$ 300 million per year for the next 10 years. Under a "business as usual" scenario, the funding available from CEB internal resources and from the donors would be in the range of US$ 120 to US$ 175 million. The annual financing gap could thus be of the order of US$ 150 million. In view of the country's fiscal position, it is unlikely that GOSL could meet this funding gap. Private investment in the sector will be necessary to mobilize the additional financing required. GOSL is considering a series of reform measures which would create an enabling environment for private participation in the sector. This project has enhanced GOSL's ability to reform and rationalize the power sector by bringing distribution systems that were operated by different licensees into the CEB fold. This will facilitate GOSL's objectives of creating a limited number of viable independent distribution companies by restructuring CEB' s existing distribution activities. E. IDA Performance 26. This project was intended to complement the activities started under the IDA financed Power Distribution and Transmission Project (Credit 1933-CE), which had objectives very similar to this project: to streamline the organization of the power distribution system; rehabilitate and expand distribution systems managed by licensees; and implement CEB's least-cost transmission program. The project was consistent with IDA's lending strategy for combining institution building with partial financing of CEB's investment program to ensure a balanced and cost-effective development of the electricity supply infrastructure in the country. IDA assisted CEB in preparation of the project and identified distinct components consistent with GOSL's sectoral policies, CEB's least-cost expansion plan and IDA's strategy for sector development. All technical, financial, economic, institutional and environmental aspects were reviewed carefully and incorporated into the scope of the project wherever necessary. During appraisal, it was determined that CEB would require technical assistance for preparation of design and bidding documents and for training its staff in critical areas. Required provisions were made in the project for fmancing such measures. The project was regularly supervised by IDA staff with missions every six months during project implementation. The skills mix of mission staff and duration of the missions were adequate, and recomnendations of the missions were reflected in the country implementation reviews. The missions identified-implementation problems and made timely recommendations for remedial measures. However, such were not always implemented on time resulting in the Credit closing while several components were incomplete. Had IDA taken a stronger position on CEB's unsatisfactory performance on the physical components and continued default on the ROR  7 covenant, the outcome of the project might have been better. On the whole, IDA's performance is considered satisfactory. F. Borrower's Performance 27. The project was prepared in accordance with accepted standards for power sector development and CEB's long-term expansion program CEB clearly recognized the importance of rationalizing the power distribution system and the need to upgrade and expand the transmission network. However, the project was plagued with procurement delays due to GOSL's protracted procurement process. These problems combined with poor quality equipment and supplies in some of the physical components of the project, resulted in inordinate delays that prevented the construction works from being completed prior to Credit closure. As a result, CEB wil have to finance approximately US$ 6.6 million of investments out of its own resources to meet contractual obligations for work completed after Credit closure. While CEB had dedicated project staff for the transmission component, the distribution component was part of the daily activities of provincial staff involved in CEB's electricity distribution work. Had there been a dedicated project management unit for the distribution component with adequate staff and labor, the rehabilitation work could have been accomplished more effectively. Progress reports were prepared for the project in a timely manner and were adequate for IDA to monitor the performance of the project. CEB cooperated fully with IDA supervision missions. The provision of counterpart funds from the CEB was timely and adequate. The training component was fully utilized. On the whole, CEB's performance was satisfactory. The performance of GOSL in the areas of procurement and power tariff regulation, however, was not fully satisfactory. For implementation aspects, the project was rated as a problem project from late 1993 to April 1996 because of the delays in procurement and non-compliance with covenants. G. Assessment of Outcome 28. The project has achieved its sectoral and institutional objectives in a satisfactory manner. The physical objectives will also be substantially achieved, albeit with a delay. CEB's financial performance was, however not fully satisfactory with CEB failing to meet the ROR target throughout the project period, except for one year. The project costs were within the estimates of the SAR. The disbursement ratio was reasonably good, with approximately 85 percent of the Credit being utilized. The re-calculated ERR, using actual figures from CEB for the period 1991-1998 is still over 12 percent and is considered satisfactory. 29. The outcome of the project has highlighted some of the limitations of the CEB model. CEB's lack of autonomy is demonstrated in the long procurement processes that led to serious project implementation delays. CEB's inability to function as a commercial entity and recover its full costs by realistic tariffs resulted in inadequate financial performance. Due to the above considerations, the overall assessment of the project has been rated as marginally satisfactory. H. Future Operations 30. An operational plan was agreed with CEB during the final supervision mission. The plan provides for technical inputs from CEB at regular intervals. It also addresses issues required for satisfactory future financial management of the project, including a commitment from CEB to allocate adequate funds for completion of the physical works components. Implementation of the plan will be monitored by IDA during preparation of the proposed Power Sector Restructuring Project.  8 31. In view of inadequate financial resources for the required level of investment in the sector,.. GOSL has resolved to reform the power sector to attract private investment. GOSL has made a commitment that all future thermal power generation projects will be executed through the private sector. As such, some Independent Power Producers have already been contracted, and GOSL is currently evaluating proposals from private investors for a new 150-MW combined cycle power plant. IDA's sector assistance strategy will be targeted towards sector restructuring in order to increase efficiency and create an enabling environment for private investments. I. Key Lessons Learned 32. The following key lessons are identified: (i) advance procurement actions (hiring of consultants, appointment of contractors, etc.) should be part of various stages of project preparation and processing; (ii) CEB's authority to handle procurement, independently of GOSL, should be enhanced; (iii) CEB's institutional structure should enable effective project implementation with adequate autonomy--this is likely to require incorporation under the Companies Act; (iv) project implementation should be entrusted to staff dedicated to that task; (v) the security situation should be properly evaluated, and works in areas prone to civil unrest should not be included in future projects; (vi) an independent regulatory regime to determine tariffs is necessary for the financial viability of the sector; and (vii) private investments and operations should be promoted to complement public resources; (viii) at appraisal, attention should have been given to financial management in general, and the submission of audited accounts on a timely basis in particular.  9 IMPLEMENTATION COMPLETION REPORT SRI LANKA SECOND POWER DISTRIBUTION AND TRANSMISSION PROJECT (Credit-2297-CE) PART II: STATISTICAL TABLES Table 1: Summary of Assessments A. Achievement of Objectives Substantial Partial Negligible Not Applicable Macroeconomic Policies (/) Sector Policies (/) Financial Objectives (/) Institutional Development (/) Physical Objectives (/) Poverty Reduction (/) Gender Concems (/) Other Social Objectives (/) Environmental Objectives (/) Public Sector Objectives (/) Private Sector Objectives (/) Other (specify) (/) B. Project Sustainability Likely Unlikely Uncertain (/) '. Iigly Satisfactorv Deficient C. Bank Performance Satisfactory Identification (/) Preparation Assistance (/) Appraisal (/) Supervision (/) Hihly Satisfactory Deficient D. Borrower Performance Satisfactory Preparation (/) Implementation (/) Covenant Compliance (/) Operation (/) Highlv Satisfactory Unsatisfactory Highly E. Assessment of Outcome Satisfactory Unsatisfactory (/) See para 29. Outcome is rated as marginally satisfactory.  10 Table 2: Related Bank Loans/Credits (from June 1982) Loan/Credit Title Purpose Year of Status AIproval Preceding Operations Seventh Power Project, Credit To strengthen the 220-kV and 132-kV power 1982 Closed, 3/88 1210-CE transmission system Eighth Power Project, Loan To construct an 80 MW diesel power station 1982 Closed, 3/86 2187-CE Ninth Power Project, Credit To improve the reliability and quality of power 1986 Closed, 6/94 1736-CE supply _ Power Distribution and Rehabilitate, develop, and expand distribution 1988 Closed, 6/94 Transmission Project systems to be taken over from selected Credit 1933-CE licensees. Construction of 230 kmn of 132-kV transmission lines, and construction and l___________________________ augmentation of related substations Following Operations: Private Sector Infrastructure Promote private sector participation through 1996 Ongoing Development Project both direct investment and increased efficiency Credit 2880-CE in infrastructure operations. Table 3: Project Timetable Steps in Project Cycle Date Planned Date Actual/Latest Estimate Identification (Executive Project Sunmmary) February 1989 Pre-appraisal March 1990 Appraisal February 1991 Negotiations May 1991 Board Presentation September 10, 1991 Signing September 20, 1991 Effectiveness December 16, 1991 Project Completion September 1997 December 31, 1999 Credit Closing June 30, 1998 June 30, 1998 Table 4: Credit Disbursements: Cumulative, Estimated and Actual (US$ Million) FY92 FY93 FY94 FY95 FY96 FY97 FY98 FY99 Appraisal Estimate 4.0 13.0 25.2 37.4 42.6 47.8 50.0 Actual 2.3 2.3 5.3 7.9 10.9 15.0 29.8 43.7 Actual as percent of Estimate 57.5 17.7 21.0 21.1 25.6 31.4 59.6 87.4 Date of Final Disbursement December 14, 1998 Cancellation: SDR 5.66 million (US$ 7.61 million equivalent) includes amount to be refunded by CEB/GOSL (US$ 0.128 million). Note: Fiscal years to the period July 1 - June 30 (IDA FY).  Table 5A: Key Indicators for Project Implementation Financial and Institutional 1991 1992 1993 1994 1995 1996 1997 1998 I.___Key__Implementation______ Est. I Act. Est. I Act. Est. I Act. Est. I Act. Est. I Act. Act. Act. Act. 1. KeylImplementationl indicators in SAR 1. Customers per Employee 55 65 75 70 90 75 99 80 108 115 126 130 2. Number of New Connections 70,000 - 80,000 107,579 80,000 126,662 80,000 147,231 80,000 113,369 154,035 170,000 163,800 3. System Losses(%) 16 18.8 15 19.0 14 22.0 13 18.0 12 18.2 18.0 17.7 17.0 4. Rate of Return on Assets (%) 7.4 6.4 7.0 4.1 7.0 4.6 8.0 7.9 8.0 8.0 2.4 1.5 2.9 5. Accounts Receivable (Mos.) 3.0 2.8 3.0 3.5 3.0 3.3 3.0 2.7 3.0 2.5 2.5 2.4 2.7 6. Long Term Debt Service 1.7 1.7 1.5 1.3 1.8 1.7 2.1 2.3 2.5 2.5 1.5 2.2 2.0 Coverage 7. Total No. of Staff Trained 800 1,117 100 1,837 100 2,068 100 1,808 100 2,568 1 38 7 Under the Project External 0 6 39 11 23 1 38 7 Internal 1,117 1,831 _ 2,029 1 ,797 2,545 0 0 0  12 Table 5B: Key Indicators for Project Implementation Distribution Works ITEM OF WORK PROGRAM FOR 22 LA PROGRESS AT CREDIT SCHEMES CLOSURE New MV Lines 195 km 57 Ian New Sub-stations 33kV/LV 233 Nos 124 Nos New LV Lines 300 km 183 km LV Line Rehabilitation & 300 km 519 km Inprovement Substation Augmentation 10 Nos 10 Nos Service Connection Rehab 25,000 Nos 46,000 Nos Meter Replacement 33kVlLV 25,000 Nos 20,000 Nos Primary Sub-stations and Kandy 6 Nos 2 Nos Municipal Council System ._ All distribution works were essentially completed by December 1998 (six months after Credit closure), with the exception of remaining works at Ratnapura and Kandy Municipal Council Schemes (to be completed by December 1999).  13 Table SC: Key Indicators for Project Implementation Transmission Works INDICATORS APPRAISAL STATUS AT CREDIT CLOSURE COMPLETION DATE 132 kV Rantambe-Badulla & December 1994 Contract award was delayed and the Kotmale Lines new completion date was May 1996; actual completion however, was in March 1998. The lines could not be energized at Credit closure since the substations were only completed in December 1998. 132 kV Substations at December 1994 Contract award was delayed and the Rantambe, Badulla & Kotmale new completion date was May 1995. However, the substations were only completed in December 1998, six months after Credit closure . 220 kV Kotmnale- September 1997 Contract award was delayed by over 2 Anuradhapura Line years and work is still in progress. Just above 50 percent of the work had been completed at credit closure. Anticipated completion date is November 1999. 220 kV Substations at Kotmale June 1996 220kV substation at Kotmale completed and Anuradhpura in November 1998, 220 kV substation at Anuradphapura completed in l ______________________ _ _ November 1998. 220 kV Substations at Not in the original project Originally scheduled to be completed in Kelanitissa and Biyagama June 1998. But contract award was delayed, and it is now anticipated that construction will be completed in November 1999, 17 months after Credit l ___________________________ ________________________ clo su re Upgrading of 132 kV May 1997 Completed on schedule Kelanitissa Line to 220 kV  14 Table 6: Studies Included in the Project Study Purpose as defined at appraisal Status Impact of study Management To assist CEB to upgrade its The report was submitted in There was no significant Information Management Information System December 1995 improvement in CEB's Systems Study performance due to problems encountered in staffing, training, and user commitment in implementing the recommendations of the __________________ study Preparation of the To assist CEB to update the The study was not financed at N/A Upper Kotmale Feasibility study, and prepare the request of GOSL in 1992 Hydropower Project detailed engineering designs and since another donor was bid documents for the project proposing to finance the TA ._________ _I and investment Table 7A: Project Costs Item Appraisal Est. (US$) Actual Costs (US$) Distribution 22.6 Transmission 38.2 49.9 Consultants/Training 5.0 4.0 Base Cost 65.8 77.9 Contingencies 13.2 0 TOTAL 79.0 77.9 Table 7B: Financing Plan Source Apprisal Estimate (US$M) Latest Estimate Local Foreign Total Local Foreign Total Costs Costs Costs Costs IDA 7.5 42.5 50.0 2.0 41.7 43.7 CEB 29.0 - 29.0 30.8 3.4 34.2 Total 36.5 42.5 79.0 32.8 45.1 77.9 Table 8: Economic Rate of Return (ERR) Appraisal Estimate (%) Re-estimate () Base Case 10.7 12.2 WTP as Benefits Case 15.7 14.8l For detailed calculation, see Annex E. I Excludes approximately US$ 39 million for 220 kV substations at Kotmale and Anuradhapura and related reactive compensation equipment (these components have been financed by NDF, NORAD, SIDA); includes cost for 220 kV substations at Biyagama and Kelanitissa.  Table 9: Status of Legal Covenants Agreement Section Covenant Present Original Revised Description of covenant Comments Type Status Fulfillment fulfillment Date date Credit 3.04 02 C 12/31/91 The borrower shall take or cause In compliance since 1991 to be taken all measures necessary to ensure that on or after December 31, 1991 total dues for electricity supplied by the Board shall not exceed 3 ______ ____ __ _months billing _ Credit 3.05 02 NC The borrower shall take all The borrower failed to meet necessary actions to enable the the rate of return target all Board to effect adjustments to its years except for one year tariffs to enable it to comply with the rate of return covenant of the l _________ ________ Project Agreement Credit 3.06 12 C The borrower shall carry out a In compliance satisfactory program to redeploy or retire the staff of local authority distribution systems transferred to the Board l Credit 3.07 12 CD The borrower shall take measures The distribution systems of for the transfer of distribution all 22 Local Authorities systems from Local Authorities to outside the North have been the Board taken over. As agreed in 1996, the 34 LA's in the Northern Province have been excluded from the project due to security l_________ ________ reasons Credit Schedule 10 C No withdrawals shall be made for As agreed in 1996, there 1.3 (b) expenditures for the Northern have been no withdrawals L Province unless and until IDA is under this sub-component ~ 3 satisfied that the project can be 8 implemented 0 ______. _ ,J%D  Agreement Section Covenant Present Original Revised Description of covenant Comments Type Status Fulfillment fulfillment Date date Credit 4.01 (b) 01 C The borrower shall furnish to In compliance (ii) IDA not later than six months after the end of each fiscal year (1) an audit report on the special account and (2) a separate opinion by auditors as to whether the statements of expenditure submitted during each fiscal year can be relied upon to support the related withdrawals __l Project 4.01 (b) 01 CD 04/30/96 The Board shall submit to IDA The FY 97 unaudited (ii) not later than (1) four months statements were submitted to after the end of each year, the IDA in May, a delay of less unaudited financial statements for than a month. The audited such year; and (2) ten months statements were received after the end of each year, with a two to three months certified copies of its financial delay each year statements Project 4.02 0.2 C The Board shall maintain a debt In compliance service coverage of not less than 1.5 Project 4.03 02 NC 01/01/96 The Board, shall, before the end Except for one year, rate of of each fiscal year, adjust the return target was not tariffs to provide sufficient achieved revenue to cover operating expenses including taxes, if any, and straight line depreciation, and provide annual return on current value of its net fixed assets of not less than 7 percent for FY 92 and FY 93 and 8 percent thereafter Project 4.02 02 C The Board shall maintain a ratio In compliance of current assets to current l A liabilities of not less than 1.2 o _ L0 ~  Agreement Section Covenant Present Original Revised Description of covenant Comments Type Status Fulfillment fulfillment Date date Project Schedule 02 C 12/31/91 The Board shall take all measures In compliance 2 necessary to ensure that on and after December 31, 1991, total bills due from consumers for electricity supplied by the Board shall not exceed 3 months billing Project Schedule 05 C For the purpose of self insurance In compliance 2 of its assets, the Board shall, within 11 months of the end of the fiscal year, deposit its annual provision to the insurance reserve in an insurance escrow account with an independent financial _ _ _ ___ __ _ __institution ___ Project Schedule 05 C 11/30/91 The Board shall: (1) by In compliance 2 November 30, 1991 furnish a training program, and (2) implement the program, satisfactorily thereafter Key Covenant Types: 1. Accounts/audit 8. Indigenous People 2. Financial performance/generate revenue from beneficiaries 9. Monitoring, review, and reporting 3. Flow and utilization of project funds 10. Project implementation not covered by categories 1-9 4. Counterpart funding 11. Sectoral or cross-sectoral budgetary or other resource allocation 5. Management aspects of the project executing agency 12. Sectoral or cross-sectoral policy/regulatory/institutional action 6. Environmental covenant 13. Other 7. Involuntary resettlement Status: C = covenant complied with CD = complied with after delay NC = not complied with CP = complied with partially  18 Table 10: Compliance with Operational Manual Statements Statement number and title I Description on lack of compliance No significant deviations from IDA relevant Operational Manual statements |O.P. 10.02 |Delay of two to three months in submiission of l | ~~~~~~~~~~audited accounts Table 11: Bank Resources: Staff Inputs Stage of project cycle Planned Revised Actual Weeks US$ Weeks US$ Weeks US$ '000 Preparation to Appraisal na na na na 15.2 41.9 Appraisal na na na na 7.7 21.5 Negotiations through Board Approval na na na na 14.3 39.4 Supervision na na na na 128.4 364.7 Completion na na na na 7.5 13.3 TOTAL na na na na 480.8  19 Table 12: Bank Resources: Missions Specialized Stage of No. of Days in staff skills Types of Project cycle Year Persons field represented Performance rating Problems Implemnt. Dev. status impact Through Appraisal 1991 3 12 EGR/FNA/ENIE N/A N/A N/A Appraisal through 1992 3 15 EGR/FNA N/A N/A N/A Board ApprovalI Supervision 1 5/92 2 14 EGRIFNA 1 1 Supervision 2 7/92 1 11 EGR Not rated Not rated Supervision 3 12/92 1 7 EGR 2 2 PR Supervision 4 10/93 2 17 EGRIFMA 3 2 PR Supervision 5 7/94 2 13 EGR/PR U S PR Supervision 6 4/95 2 13 EGRIFNA U S PR Supervision 7 9/95 2 18 EGRIFNA U S PR Supervision 8 3/96 3 22 EGR/FNA/OPN S S PR Supervision 9 12/96 2 12 EGR/FNA S S PR Supervision 10 3/97 1 7 EGR Not rated Not rated PR Supervision 11 6/97 4 13 EGR/FNA/OPN/ENIE S S PR Completion 5/98 5 11 EGR/FNA/ENIE/DA U U PR Key: EGR : Power Engineer FNA : Financial Analyst ECN : Economist OPN Operations Analyst ENIE : Environmental & Infrastructure Engineer PR : Procurement Specialist DA : Disbursement Assistant LC : Compliance with Legal Covenants FP : Financial Performance PR : Procurement Progress PM : Project Management Performance 1 : Problem Free 2 Moderate 3 : Major Problems S : Satisfactory U : Unsatisfactory  20 Annex A Page 1 of 9 SRI LANKA SECOND POWER DISTRIBUTION AND TRANSMISSION PROJECT CREDIT 2297-CE FINAL SUPERVISION MISSION May 18-June 4, 1998 AIDE MEMOIRE' 1. An IDA mission comprising Sumith Pilapitiya, Vijay Iyer, Lennart Carlsson, Joan Pullenayegem and Julitta Rasiah undertook final supervision of the Second Power Distribution and Transmission Project during the period May 18-June 4, 1998. The project is scheduled to close on June 30, 1998. 2. The mission would like to thank the officials and staff of the Ministry of Irrigation, Power and Energy (MIPE), the Ministry of Finance and Planning (MOFP) and the Ceylon Electricity Board (CEB) for all the courtesies and assistance extended to the mission members. This Aide Memoire summarizes the mission's findings and the agreements reached with the Government of Sri Lanka (GOSL) and CEB at the wrap-up meeting held on May 29, 1998 and is subject to conformation by ]DA management. SUMMARY OF CONCLUSIONS AND RECOMMENDATIONS 3. An overall assessment of progress of activities under the project clearly demonstrates that performance is unsatisfactory. The project was declared effective in 1991. The project implementation has been consistently plagued with procurement problems, resulting in unacceptable delays. With all major procurement under the credit completed by June 1997, the mission noted that the disbursement over the last year was about 100 percent more than the cumulative disbursements over the last six years. However, with just one month remaining before credit closure, the overall disbursement ratio for the project has been only 56 percent. The pace of implementation of the larger investment components are well behind schedule. The CEB defaulted on the 8 percent Rate of Return (ROR) covenant in 1996 and 1997; the information provided to the mission indicates that the CEB will be in default on this covenant in 1998. Under these circumstances, whereas CEB management has made a request for a nine-month extension of the credit closing date, the mission does not recommend an extension. PROJECT IMPLEMENTATION Transmission Component 4. Lot A: 132 kV Rantambe - Badulla and Kotmale Lines. A supply and erect contract (US$ 3.2 million) was awarded in November 1993 with contract completion by May 31, 1996. Although there were substantial delays due to design and manufacturing difficulties, the 37 km Rantambe - Badulla line has been completed, and the Take-Over-Certificate (TOC) will be issued shortly. The eight km Kotmale - Kurunduwatta spur line has also been finished and the works are now being checked out by CEB. The lines can, however, not be energized until Lot B has been completed. I The text of the Aide Memoire has been altered to remove the names of consultants and contractors.  21 Annex A Page 2 of 9 5. Lot B: 132 kV Substations at Rantambe. Badulla and Kotmale. The contract (US$ 1.6 million) for the turn-key supply of these three substations was in February 1993, with contract completion by February 1995. Most of the equipment has been sourced in India. There were quality problems with some relay panels and steel structures that have been resolved. The main problem, however, has been and still is with 11 disconnect switches. 6. The original disconnectors were supplied to the sites, but rejected before erection due to corrosion of the galvanized steel parts as well as other deficiencies. They were replaced by the supplier, but the same quality problems re-occurred. In September 1997, the supplier was given a second chance to correct the problems and agreed to supply a new and improved design. The first disconnector of the new design was supplied and installed in February 1998. Even though the new design is a clear improvement, it does not fully meet CEB's requirements in all aspects. The remaining 10 disconnectors have just been delivered and their installation will commence in early June. 7. It is the mission's opinion, that CEB should have acted more forcefully, and exercised its contractual right to procure the disconnectors from other sources and deduct the cost from the contract price, as was agreed with IDA in December 1996. At present, this does not appear to be an option, but CEB should use its right to claim maximum liquidated damages for delay. Neither the 5 percent payment at PAC nor the 5 percent at FAC would be due before the closing of the credit. 8. The mission takes serious note of the fact that even after three years from the date that this contract was scheduled to be completed, the substations are not ready and the transmission lines (Lot A) cannot be energized. 9. Lot C: 220 kV Kotmale - Anuradhapura Line. The procurement of this 165 km line was delayed by about two years. However, a supply and erect contract was subsequently signed on October 2, 1996. The contract calls for completion in January 1999, which is after the credit closing date of June 30, 1998. This is a result of the late award of the contract. The contract amount is US$ 8.5 million plus SLRs 132 million. 10. The contractor is well behind schedule and as of April 30, 1998 the situation is as follows: _________ __ |Planned (%) Actual (%) Supply of material 90.0 65.5 Foundations 410 (87) 99 (21) Tower erection 350 (74.3 - Overall work progress 85.8 45.9 11. As is evident from this table, the main problem is in the area of foundation construction, where the contractor in using two local subcontractors in addition to his own crews. The rate of foundation construction is at best 35 foundation groups/month. Tower erection has started during May 1998.  22 Annex A Page 3 of 9 12. The consultant estimates that about US$ 2.2 million plus SLRs 88 million will remain unpaid at the loan closing date. This amount includes the 5 + 5 percent retention money to be paid at PAC and FAC respectively and about US$ 0.5 million of tower material that will not be delivered before June 30, 1998. The presently expected completion date is May - June 1999, i.e. 5 - 6 months behind schedule. This, however, assumes that there is no disruption of the payments to the contractor as a result of the credit closing. A total of approximately US$ 3.6 million of GOSL resources is required to complete this component of the project. The mission was assured by the Chairman that CEB's own funds will be made available for completion of this component upon credit closure. 13. Lot D: 220 kV substations at Kotmale and Anuradhapura. and Reactive Compensation Equipment. The financing of this lot was taken over from IDA by NORAD, SIDA and NDF. The lot includes the two substations at the endpoints of the Lot C line and a 6*5 MVAr switched shunt capacitor bank at the Kotugoda substation near Colombo. 14. The shunt capacitor installation was commissioned in late April 1998, three months ahead of schedule. It has substantially improved the voltage in the Colombo area. 15. Pre-commissioning tests of the Kotmale 220 kV substation extension are presently being performed and it is estimated that it will be commissioned on June 28, one month ahead of schedule. 16. Equipment erection is nearing completion in the New Anuradhapura 220/132/33 kV substation. It is expected that the station will be completed in January 1999, five months ahead of schedule. 17. All equipment for these substations have been sourced in Sweden, Norway and Germany. There have been no problems with any of the Lot D contracts. 18. Lot E: 220 kV Substations at Kelantissa and Biyagama. Although IDA approved the bidding documents for the above contract in October 1996, the bidding process was protracted and final contract award was in June 1997. This delay occurred in spite of an agreement with CEB that the contract award should be made by March 31, 1997, so that this component could be completed prior to credit closing. Civil works at the site was delayed further by an additional 82 days due to the bomb blast at the boundary of the Kelanitissa Power Station. At present, the site investigations have been completed and the civil works design is approximately 85 percent complete. CEB anticipates that 30 percent of the erection will be completed by credit closure while it is expected that construction will be completed by February 1999. The mission was informed that the equipment manufacture is on schedule with all equipment except for the transformers having been manufactured and tested successfully. The mission was informed that transformer testing has just commenced. If the testing of transformers are successful as well, the contractor proposes to ship the equipment to Sri Lanka in mid-June. The equipment is scheduled to arrive in Sri Lanka several months prior to the site being ready. The mission urges CEB management to ensure that the equipment is properly stored until the site is ready so that the US$ 21.4 million investment is not jeopardized.  23 Annex A Page 4 of r 19. The CEB expects to disburse approximately 90 percent of the CIF component which is financed under the credit, prior to closure. This, however, means that CEB will have to pay about US$ 3 million from its own or GOSL resources for the 5 percent + 5 percent retention money, under this contract. The mission informed CEB management that CEB will be liable to pay for the completion of this component. The Chairman has assured the mission that CEB funds will be allocated for this component as well. 20. Lot F: Upgrading of 132 kV Kelantissa Line to 220 kV. CEB awarded a contract for US$ 114,199 plus 32,850.49 for upgrading of the above mentioned line, in May 1997. The mission was pleased to note that all work under this component has been completed. Distribution Component 21. All of the 22 municipal distribution systems have now been taken over by CEB. The last one, Ratnapura Municipal Council system was taken over during the latter part of 1997. The mission was informed, that even a few of the 34 distribution systems in the Northern Province, which were agreed to be excluded in April 1996 due to security reasons, have now been taken over. CEB is now contracting with private generators to supply power to isolated parts of the distribution system in the north. These generators are being moved to other, more remote areas when supply from the 33 kV grid is established. 22. The upgrading of the distribution systems that have been taken over has suffered from the protracted procurement process. Procurement Problems 23. Although there are a number of cases where contractors have shown poor performance, the main cause of the delays in implementing the investments financed under this credit has been the exceptionally slow procurement process for all CEB contracts. This risk was identified in IDA's Staff Appraisal Report for the project dated June 28, 1991, as it had been a major problem in previous IDA financed projects. 24. Under the World Bank's recently adopted procurement rules it is very unlikely that any CEB procurement could have taken place under the procurement procedure that is currently being followed by CEB. The Bank can now refuse an application for extension of the bid validity time in excess of eight weeks and require that award of contract be made within the prescribed bid validity time period. If the implementing agency fails to award a contract on time, the Bank may declare misprocurement and will normally not accept a rebidding. 25. It is evident, that the Government of Sri Lanka needs to empower CEB with the right to make its own procurement decisions, and that CEB must develop the necessary procurement procedure to be able to function in an efficient manner. The current slow and complicated procurement process is not only causing major delays in new investments but is also causing delays in the procurement of vital spare parts for power plants, substations, etc. resulting in a large waste of existing resources. The present situation is crippling the CEB in a way that is detrimental to the development of the country.  24 Annex A Page 5 of 9 Technical Assistance Training of CEB Staff 26. The credit provided approximately US$ 800,000 under this component (US$ 745,000 for general training of CEB staff and US$ 55,000 for exposing CEB and MIPE staff to power sector reforms). There is an accumulated balance of about US$ 44,600 available to date. Of this CEB has committed US$ 40,575 for additional training of CEB staff which will be utilized prior to credit closure. The unutilized balance from the training allocation will be approximately US$ 4,000 at the end of the credit. The DGM - Training informed the mission that a proposal to utilize the balance for a Distance Education Course will be sent to IDA by June 15, 1998. Status of Studies financed under the Credit 27. Management Information System Study CEB signed an agreement in July 1994, to carry out an MIS upgrading study. The study was estimated to cost Can$1,048,536 and 4,499,371. In July 1996, the CATB had approved a further contract increase of Can$ 217,533 and 1,116,000 on account of additional eight staff months consultancy (the consultant left Sri Lanka in September 1996 after completing his assignment). Although an IDA supervision mission had reviewed the justification and agreed to it during September 1995, CEB has been unable to get the amendment to the contract which reflects these changes. CEB had paid for this extension with its own resources without an amended contract. Subsequently, the firm ceased to be in existence and CEB is unable to get the amendment to the contract signed. The mission has informed the CEB that the credit is unable to pay for this extension without an amended contract, therefore. CEB may have to absorb this cost. Financial Issues' 28. During 1996 and 1997 CEB's financial performance deteriorated substantially. Poor hydrological conditions in those two years led to costly temporary measures such as purchase of power from private generators and provision of incentives for import of generator sets. An ADB mission in February 1998 has pointed out that CEB is in violation of the crucial minimum rate of return on net fixed assets covenant in 1996 and 1997. This observation has been confirmed by this mission and it also notes that without tariff adjustments in the current fiscal year. CEB would continue to be in violation of this covenant. Besides ensuring compliance, tariff increases are also necessary to restore CEB's financial health in the wake of the problems of 1996-97. 29. CEB has submitted the audited accounts for the year ended December 1996 to the Bank. This is presently under review. The CEB is yet to forward the audited accounts for 1997. The mission was also provided with the draft financial statements for 1997 (under audit) and projections for 1998-2000 by CEB. Based on these statements, the key indicators for gauging CEB's financial performance are summarized in the following table. l Figures in this section have been revised subsequently.  25 Annex A Page 6 of 9 Financial Covenant Actuals | Forecasts Indicators Requirement 1996 1997 1998 1999 2000 ROR on fixed assets - base 8% 2.4% 1.5% 6.3% 5.7% 4.1% case with no tariff increases ROR on fixed assets with tariff 8% 2.4% 1.5% 7.3% 9.5% 9.6% increases of 12.5 percent in July 1998, and 10 percent each in 1999 and 2000 Debt Service Coverage ratios - 1.5 1.6 1.4 3.7 2.3 1.7 base case Current ratio - base case 1.2 2.0 1.4 1.9 2.2 2.1 30. CEBs Rate of Return: The ADB Mission of February 1998 estimated a negative rate of return for fiscal 1997 based on provisional data made available at the time. The financial data for 1997 made available to the Bank mnission indicates that the ROR would be closer to 1.5 percent of the average value of net fixed assets. This computation does not follow some of the more rigorous assumptions used by ADB - such as not allowing interest earned as part of income. However, it is clear that even with generous treatment of income indicators, CEB does not achieve the covenanted 8 percent rate of return in 1997. For 1998, based on the latest provisional numbers provided by CEB to the mission, the ROR is expected to be in the range of 6 percent. The detailed computations are shown in Annex 1. Based on the projections for 1999 and 2000 made available to the mission and in a scenario of no tariff increases, the situation with regard to the rate of return covenant is not likely to improve and in fact appears to deteriorate. 31. The following issues are relevant to CEB 's financial performance. (a) The KHD thermal power IPP is expected to be commissioned by July 1, 1998. An output of 27 Gwh per month will be purchased at a rate of between US cents 7-8 per Kwh (Rs. 4.40 per Kwh at current exchange rate of 1US$ = SLRs 63) depending on the price at which fuel will be supplied. Power purchase payments of nearly SLRs 650 million in 1998 and around SLRs 1650 million per annum in 1999, rising to SLRs 1800 in year 2000 would need to be made to KHD. At about 350 Gwh per annum the KHD plant represents an addition of about 8 percent to the net power availability in Sri Lanka. The pre-KHD tariff of SLRs 4.50 per unit needs to increase to SLRs 4.85, in order for CEB to pay for the power without incurring any additional financial burden (assuming that system losses remain at or below 17 percent). (b) The Government has with effect from April 1, 1998 eliminated the 7 percent business turnover tax (BTT) payable by CEB. This has been replaced by a general sales tax of 12.5 percent, but this is levied in addition to the tariff and is appropriated by government.  26 Annex A Page 7 of 9 The GST applies only to consumers with more than 90 Kwh of consumption in the month. This ceiling eliminates nearly 75 percent of the domestic consumers from paying this tax. To CEB the benefit of eliminating BTT translates into an effective tariff increase of nearly 6 percent. The computations shown in the table above reflect this change from April 1 onwards. (c) CEB is anticipating government approval for importing fuel directly at Singapore spot mnarket rates. Together with the anticipated reduction of fuel taxes, CEB is assuming substantial savings in its fuel costs and is making a case for tariff decreases! The mission would like to caution against any such steps based on anticipated cost reductions which may not materialize. Buying fuel at spot market rates may make sense at today's depressed oil prices. However, without an assurance of steady supply and hedging and indexation provisions to insure against market changes and upward movements in oil prices, this could be a potentially risky strategy. (d) The mission recommends that average tariffs be increased with effect from July 1, 1998 to SLRs 5.07 representing a 12.5 percent increase. This is recommended to be followed up by similar increases in 1999 and 2000 to restore CEB's financial health and facilitate its recovery from the crises in 1996 and 1997. This recommendation is also consistent with the ADB mission recommendations. Increases across consumer categories should be made to reduce cross subsidies on domestic consumers, since 75 percent of such consumers are already benefiting from being under the consumption ceiling that triggers payment of GST. The scenarios for 1998-2000 with and without these tariff increases are shown in Annex 1. The mission was told that a 12.5 percent tariff increase is in fact being contemplated and that the CEB intends to apply this and future increases across the various consumer categories so as to eliminate the subsidies on the domestic sector, particularly on the 0-90 Kwh per month consumption category. (e) The present credit is closing on June 30, 1998. In view of the fact that the project has performed poorly and the state of CEB's financial performance, it is unlikely that an extension would be considered. The ongoing and outstanding works will require an investment of nearly SLRs 430 million spread over the period from July 1998 to June 1999. This funding would have to be from CEB resources. This additional resource generation would also be facilitated by the suggested tariff increases mentioned in (d). Other Proiect Aspects 32. Financial Accounts and Disbursements. Unaudited financial accounts of the CEB were given to the mission. CEB has informed the mission the audited accounts will be available by June 30, 1998. Actual disbursement as of June 4, 1998 is approximately US$ 29 million. Although, disbursements under the project have improved, it is still only 55 percent of the credit proceeds. With approximately a month left prior to credit closing, the mission is very concerned that almost 45 percent of the credit remains undisbursed.' l Just prior to Credit closure, CEB submitted large claims so that eventually, more than 87 percent of the Credit was withdrawn.  27 Annex A Page 8 of 9 Lonig Term Generation and Transmission Expansion Studies 33. The Mission has reviewed CEB's Long Term Generation Expansion Planning Study for the period 1998 - 2012 issued by CEB in December 1997 and the Master Plan Study for Development of the Transmission System of Ceylon Electricity Board performed by JICA and issued in January 1997. 34. The generation expansion study's main load growth scenario assumes an average 8.1 percent p.a. load growth during the studied period. There are also a low growth scenario of 7.1 percent and a high growth scenario of 9.1 percent. During the five year period 1992 - 96 the average load growth was 8.8 percent p.a. and the corresponding average demand growth 6.9 percent p.a. 35. The present generation system is dominated by hydro with 1115 MW installed capacity. The CEB thermal capacity is 391 MW (derated capacity). During recent years hydro has supplied on the average 90 percent of the energy, exceptions being the drought years of 1992 and 1996 where thermal generation was 18 percent and 28 percent respectively. 36. The remaining exploitable hydro capacity is limited and also relatively expensive. Sri Lanka therefore stands on the threshold to a new era where thermal power is going to play an increasingly important role. As there are no domestic thermal fuel resources, future generation expansion will have to be based on imported oil and coal. 37. Thermal generation projects are well suited for development by the private sector, and GOSL is encouraged to invite Independent Private Power developers to build the necessary thermal generation plants. This is already happening to some extent, but this policy should be pursued in a consistent way. Public financing resources could then be concentrated on the investment needs in the transmission, distribution and rural electrification areas. 38. The generation expansion plan seems to have been done in a competent manner using the WASP3 software and assuming five different hydrological conditions. The least cost generation expansion program for the base case envisages the following generation additions during the next few years: Year Plant Power Comment 1999 Sapugaskanda Diesel Extension 40 MW (committed) KHD plant (BOO) 51 MW (committed) l_______ GT part of Kelantissa CC plant 100 MW (committed) 2000 Completion of Kelantissa CC plant 50 MW (committed) Gas turbine 105 MW 2001 Combined Cycle 150 MW Combined Cycle 150 MW 2002 Kukule hydro 70 MW (committed) 2003 - 2004 Coal plant on west coast 300 MW 2005 Gas turbine 105 MVV _ 2006 Coal plant on west coast 300 MW  28 Annex A Page 9 of 9 39. The coal fired plants would most probably have been scheduled earlier if it had not been considered unrealistic to commission such a plant before 2004. In the low growth scenario, which appears more realistic, there are no gas turbine plants until 2010. The mission was informed that no preparations are underway for the 105 MW gas turbine plant scheduled for year 2000. Bids will be received shortly for one of the 150 MW Combined Cycle plants as an lPP. Considering the large proportion of hydro power in the country, it is evident, that there is a need for base load plants. CEB is proposing the construction of coal fired plants, which appears to be a sound approach as the analysis clearly shows that coal fired plants provide the lowest cost when operated at a plant factor of 60 percent or above. These stations are in fact expected to operate at about 80 percent plant factor. 40. The use of coal negatively affects the global environment, local eco-systems and public health due to air pollution. In addition to these emissions, the ash residue and wastewater from coal combustion raise further environmental issues. A very important task for Sri Lanka is to balance the conflicting demands of economic growth and increased demand for power with environmental impacts that can be considered reasonable for sustainable development. However, countries like Sri Lanka which are grappling with impending power and capital shortages should avail itself of recent advances in the field and be able to select cost effective, environmentally friendly technologies for coal based power generation. 41. The introduction of thermal power with imported fuel on a large scale will make it very important to use electricity in a rational way. This can only be achieved by setting tariffs that reflect the true cost of providing power to the various customer categories. This will without doubt necessitate substantial tariff increases. Cross subsidies should also be eliminated. If there are social reasons to subsidize the very smallest domestic consumers, this should be preferably be done in a transparent manner through the government's budget so as not to burden CEB's finances with this obligation. If necessary tariff adjustments are not done, CEB's finances will rapidly deteriorate and CEB will become a burden on the country's finances. Implementation Completion Report 42. The mission left CEB with guidelines for the preparation of the Borrowers Evaluation Report of the project that will be annexed to IDA's Implementation Completion Report (ICR). The mission requested CEB to identify a coordinator for the preparation of the CEB's Evaluation Report. The mission was informed by the Chairman that Mr. D. C. Wijeratne, Additional General Manager (Transmrission) will coordinate the preparation of the Borrowers Evaluation Report and the information for the ICR. An IDA ICR mission will be fielded during the month of August. Agreements with CEB 43. It was agreed with Chairman, CEB that CEB's own resources will be made available to make payments under the on-going contracts once the credit closes. This amounts to a total of approximately US$ 6.6 million. It was agreed that a letter confirming this agreement will be sent to IDA prior to June 30, 1998.  29 Annex B Page 1 of 9 BORROWER'S EVALUATION 1. BORROWER'S ASSESSMENT A. Introduction 1. In December 15t, 1991 an IDA Credit of SDR 37.5 Million (equivalent to US $ 50.0 M) was approved by IDA Board for GOSL/CEB to plan, design and implement a Second Power Distribution and Transmission Project and the details as follows: a. Distribution Rehabilitation Component (Part A of schedule II of DCA) Rehabilitation of Distribution system take over by CEB of 56 licensees b. Transmission Expansion (Part B of schedule II of DCA) 1. 132kV substations at Rantambe, Badulla and Kotmale with about 45km of Tr.lines. 2. 220kV line from Anuradhapura to Kotmale 3. 220kV substations at Anuradhapura and Kotmale 4. Reactive compensation equipment at related stations. c. Technical assistance (Part C of schedule II of DCA) 1. Training of CEB officials 2. Consultancy services for various technical studies, Preparation of bid documents and - specifications for 220kV Transmission works, Power system protection study and MIS upgrading study. B. Project Objectives 2. The principal objectives were: * to support further rationalization of Power distribution to reduce system losses in the distribution systems operated by 56 licensees which could not be taken over under the Power Distribution and Transmission Project IDA Cr. 1933-CE and improve quality of electricity supply. * to provide additional transmission and grid substation systems facilities to help/mneet the projected demand of supply North Central, Northern Eastern, Uva and Part of the Central Provinces. * to assist in the preparation of Upper Kotmale Hydro Power project to ensure its development in a technologically, environmentally and socio-economically sound manner and * to further strengthen CEB' s institutional capacity.  30 Annex B Page 2 of 9 C. Desi2n 3. To achieve the above objectives, the following project components of the project were designed. (I) DISTRIBUTION OF LOCAL AUTHORITIES SYSTEMS Studies were conducted on the electricity distribution systems of Sri Lanka by the CEB under "Distribution Master Plan" and it was revealed that LA distribution systems suffered from Heavy Voltage drop and Power losses in LV lines. This resulted in a poor service to the consumers and a national loss of valuable electrical energy. This situation was expected to grow worse year after year with more consumers adding to the system and with the growth of electricity demand. No scientific programme to study, design or implement the improvements needed to arrest the above situation was underway in any of the local authorities. Therefore CEB launched an intensive design program using computer techniques AIvMI at rectifying this. (It) TRANSMISSION WORKS LOT A - Construction of 37km 132kV Transmission line between Rantambe Power station to Badulla Grid Substation of single circuit Lynx conductor with provision for stringing the second circuit with similar conductor under hot line conditions. * Construction of 8km 132kV Transmission Line between Kotmale Power station to Kurunduwatta Spur line of double circuit Lynx conductor for looping 132kV Polpitiya Anuradhapura Transmission Line into Kotmale Power station. LOT B * At Kotmale 132kV SS Construction of a 132kV busbar with three new circuit breakers, two for additional Polpitiya & Kiribathkumbura feeders and for the bus coupler which connects the new and existing bays. * At Badulla 132kV SS Construction of a new 132kV feeder bay and connected to existing 132kV single busbar using two disconnecting switches and one circuit breakers. * At Rantambe 132kV SS Construction of a 132 feeder bay for Badulla feeder 2 using three disconnecting switches and one circuit breaker.  31 Annex B Page 3 of 9 LOT -C Construction of 165km, 220kV double circuit steel tower transmission line single circuit strung with single ACSR Zebra between Kotmale PS to new Anuradhapura GSS LOT -D * Construction of 2 nos. 220kV transformer bays along the 100 MVA 220/132/33kV transformers at Anuradhapura Grid Substation. * Construction of 220kV line bay at new 220kV Anuradhapura Grid Substation with provision for an additional bay. * Construction of 220kV line bay at existing 220kV Kotmale Grid Substation with provision for additional bay. * Construction of 2 Nos. 132kV transformer bays at Anuradhapura to interlink with existing 132kV Substation. * Static Reactive compensation with switchgear and other allied equipment to be connected to existing bus bars such as at Pannipitiya GSS, Anuradhapura GSS and Matugama GSS. 4. Subsequently in 1996, GOSUCEB decided that Lot D to be executed under financial assistance from Norad funds. IDA at the request of GOSLUCEB agreed to permit CEB to use the saving to construct 220kV Kelanitissa Biyagama Tr. work and to carry out a thorough rehabilitation of the Kandy distribution system subject to CEB adherence to and agreed a procurement schedule. (M) Technical Training 5. Credit under training is utilized in the training of senior managers, engineers and accounts by way of visits to power sector utilities in different countries attending seminar of BOO/BOT and restructuring studies financial management, business strength, forecasting programmes, operational maintenance of low and high voltage distribution, protection study, procurement study. (IV) Management Information System Upgrade Project * Design The MIS of CEB was a paper based system and all the functional systems except billing was paper based. The CEB Management did not receive timely and accurate management information, for decision making. It was very difficult to trace back any previous transactions occurred which are recorded in various paper documents. 6. The objective of the project is to computerize five functional areas of CEB namely. 1. Material Management 2. Finance and Accounting 3. Project Management 4. Human Resource and Payroll 5. Billing and Consumer Services - only the MIS  32 Annex B Page 4 of 9 7. The consultancy services for the project is funded by 2297CE. Detailed Project Implementation: The consultants, Ontario Hydro International, Canada, submitted a findings report with recommendations to tender for off-the-shelf packages for computerizing the above. CEB accepted the proposal and OHII prepared the specifications for tendering. It was decided to implement the systems at two pilot sites; Head Office and WPN Province with the intention to deploy at other CEB sites if successful. 8. CEB funded the software / hardware and implementation costs. * Implementation Six offers were received and an integrated package with Material management and Accounting called MITF in was selected. There were no acceptable solutions for other functions. The LAN-WAN infrastructure is installed by CEB funds and the microwave project. The supplier MIT Ltd., has developed a job costing system to suit CEB's specific needs. Also Tender monitoring, Purchase / Sub contracting modules are developed to suit the needs to Procurement Branch- By now (end of 1998) WPN Provincial Office implementation is completed. Central Stores is computerized and linked to Head Office. The Head Office sites are in varying degrees of implementation mainly depending on the support from users. * Operation Experience The major factors affected in implementation are: 1. The degree of user support 2. The adherence to accepted procedure, prompt resolution of issues consistency (or the lack of the above) 3. Delays in procurement and installing the infrastructure and the breakdowns of infrastructure. 4. The complexity of CEB' s operational procedure * Plans: Implementation commenced at WPS Office, it is planned to deploy at other province/complex offices in phases. A system study is commenced to: 1. Extend the computerization to Areas & Deports. 2. To cover the missing components of a provincial setup.  33 Annex B Page 5 of 9 D. Imlnementation Distribution Rehabilitation Component 9. The work implemented and the progress as a percentage of scope as at end of June 1998, is given below. New MV Lines - 57 km New Substations - 124 km New LV Lines - 183 km LV Line Rehab. & Impor. - 519 km Substation Augmentation - 10 nos Service connection Rehab. - 46,000 nos Meter Replacement - 20,000 nos Primary Substations & KMC sys. - 2 nos 10. The overall progress based on the value of work completed upto end of June 1998 is 60 percent. 11. The main reasons for the delays are as follows: i. Design changes necessary to incorporate the needs of the fast developing Loads. ii. CEB's resources had to be shared by several simultaneous projects while the provincial construction units at the same time had to cope with shifting priorities thus disrupting plans and programmes. iii. Lengthy procurement procedures. iv. The private sector construction units in the country were small in number at the start of the project and time was needed for theses units to be established and trained for them to be utilized by the CEB in the Project work. 12. The work has been handled by the provincial units of the CEB utilizing the CEB's own work force as well as contractor gangs on short time contract basis. CEB's own vehicles and construction equipment procured under other projects as well as under this project have been utilized for the work. The contractor gangs have been using their own vehicles, tools and construction equipment. 13. The major and essential work is expected to be completed by the 315' of December 1998, while the balance work consisting mainly of the improvement and expansion work of the Ratnapura Municipal council scheme taken over recently and rehabilitation of 11kV underground system in the enhanced Kandy Municipal Council scheme would continue up to December 1999, as organization of work and supply interruptions are complex and need co-ordination with other utilities.  34 Annex B Page 6 of 9 Transmission Lot A The turnkey project for the construction of 37km of 132kV double cct. tower line single circuit strung (Lynx conductor) between Rantambe and Badulla and 8km of 132 kV double cct tower line with lynx conductor looping 132kV Polpitiya/Anuradhapura Tr. Line to Kotmale PS was awarded to a foreign contractor at a total estimated cost of USD 2,930,965.00 + SLRs 32,963,208.50 on 1st Nov. 1993 with a target completion of 31-05-96. However the project commenced only on 19th May 1994, and were completed and put into commercial operation on 28" March 1998 and the reason for the delay being. * The design fabrication and testing of transmission towers (manufactured by SAE, India) had given problems. * Kotmale Kurunduwatta 1.2km line section was deviated to avoid heavy Pile foundations. * Special type towers of l9nos were proposed along the line route to cater uplift load and it involved special design and testing of uplift. Later T3 and T6 towers were modified to cater for uplift loads. * Delay in supplying of foundation stubs and other materials. Lot B Construction of 4 nos. 132kV line bays and one 132kV bus coupler bay at Rantambe, Badulla and Kotmale substations at total estimate cost of Deutsche Mark 421,118.00 plus US$ 1,008,911.00 plus SFR. 295,141.00 plus SEK 397,534.00 plus SLR 11,498,131.90 was awarded to joint venture of ABB Schaltanlagen GmbH (Germany) and Samuel Sons & Co. Ltd., Sri Lanka on February 2, 1993. Target date of completion was February 8, 1995. The contractor was not completed even at time of closing of the IDA loan and the reasons for delays being: * All control and relay panels, most of the steel structures were rejected due to excessive corrosion and poor quality and replaced by new items. * Supplying of inferior quality material specially 145kV disconnector units were rejected twice and the matter was then referred to a special committee appointed by the GM(CEB) and they rejected total 1 Inos. 145kV disconnectors on 26t, August 1996. * On CEB's consent contractor erected one DS unit with modification at Kotmale SS on 19 February 1998 and took nearly five months to install balance 10 nos. DS units. * The substation extension works at Rantambe has not been completed yet due to non availability of Busbar protection scheme modules.  35 Annex B Page 7 of 9 Lot C Turnkey construction of 165km of 220kV double circuit Zebra conductors tower line with single circuit strung between Kotmale power station and Anuradhapura GSS was awarded to joint venture KEC International Ltd., and Best and Crompton Engineering Ltd., India on 20.05.96 at a total estimate cost US $ 8,479,618.00 plus SLRs 132,192,703.00 with target completion date of 02.01.1999. The work has really conmmenced on 2nd October 1996 and is presently expected to be completed only by June 1999. The reasons for the delay being: * Contractor delayed with the commencement of the site work by four months due to the difficulties in obtaining registration of the joint venture in Sri Lanka and India. * Difficulty in access to the sites, 50 percent of the line route is passing through hilly terrain and contractor has not equipped with mechanization and tools for work in such conditions. E. Operation Experience 14. The works that are commissioned under the Project will integrate with the works in the normal CEB Electricity Distribution System and the same organizational set up will be responsible for carrying out the maintenance and operation of the works. * Organization Chart The organization Chart of the CEB set up for the above is given below. The work is carried out by the Depot Maintenance Staff under the direct supervision of the Depot Superintendents and the Area Engineers are responsible to the Provincial Deputy General Manager of the smooth functioning of the planned maintenance work. * Plant & Equipment Register A plant & Equipment Register is maintained in each Depot giving the details of all lines, substations and underground systems and this Register is updated regularly when newly constructed works are added to the system.  36 Annex B Page 8 of 9 ADDITIONAL GENERAL MANAGER (DISTRIBUTION OPERATION) DEPUTY GENERAL MANAGER (PROVINCE) AREA ENGINEER ELECTRICAL SUPERINTENDENT | ~~(DEPOT) MAINTENANCE & MINOR CONST$UCTION STAFF (DEPOT) Depot System Maintenance Register & Maintenance Planning The details of Plant & Equipment of which regular maintenance has to be carried out are extracted from the Plant & Equipment Register and entered on the Depot System Maintenance Register. This register serves as a check list to ensure that maintenance of all plant and equipment has be planned for each quarter. When the maintenance work carried out during the quarter is entered in this register, any outstanding work would be reflected in this register at the end of each quarter. When planning the work using the schedules of tasks, frequencies, standard gang compositions and work standards, any deficiencies in staff categories needed to plan all the periodic maintenance work would be immediately evident in this system of planning and corrective action could be taken such as recruitment of staff, engagement of contractor gangs or payment of incentives for work by staff over and above the work standards fixed for a gang. * Maintenance Progress Electrical Superintendents of the Depots forward the Monthly Progress to the Area Engineers who forward the details extracted from these reports to the Deputy General Managers of the Provinces, at the same time deciding action to improve substandard performance as well as to deal with an overload of work.  37 Annex B Page 9 of 9 * Substation Maintenance Periodic checks and maintenance work of Distributions are carried out by Depot staff. In the case of Primary substations the periodic checks are carried out by the substation staff while the maintenance work is carried out by the Distribution Maintenance Engineer and his staff. * System Operations System Operations are carried out by the standby gangs in the depots with the help of Primary Substation and Grid Substation staff. The operations are supervised by the Electrical Superintendents of the Depots. The Central System Control Centre is regularly informed of the systems operations carried out at 33kV. F. Evaluation of Borrower's Own Performance Distribution. Rehabilitation component 15. The work required Modern technology and computer systems for interactive on-going system designs and for identification of system changes and their incorporation in the Project during implementation. The delays in purchase of such equipment and the non-availability of trained personnel and expertise as a result of the exodus of technical staff was mainly responsible for the slow design work. 16. Due to periods of Civil unrest affecting work and the fast changes in the country having to meet the demands of growing industries as well as domestic loads, the implementation work was delayed. Slow administrative systems inherent in the country and the lack of a proper incentive scheme to promote work also contributed to these delays and as a result the Borrower Performance fell short of the requirements needed for timely performance. 17. Some of the Key lessons learned that may be useful in the future are as follows. (i) Large Projects to be carried out expediently require change of frame work of organizations. To undertake such work as a separate project by identified staff. (ii) Planning work should be facilitated with modern equipment such as computer systems to be provided to the project planners at the pre-commencement stage. (iii) Training of personnel on modern techniques. (iv) Retention of trained personnel by offering incentives. G. Evaluation of Bank Performance Distribution. Rehabilitation component 18. One of the key lessons learned in negotiating with the Bank is that the conmmunication between the Bank and the Borrower should be fast and all responses quick for speedy decisions and implementation. The Bank should seriously consider incorporation special conditions in agreements with Government of recipient countries for healthy changes to be introduced in purchase and adrninistrative procedures prevailing in the countries.  38 Annex B Appendix I LOCAL AUTHORITY ELECTRICITY SCHEMES TAKEN Local Authority Scheme Takeover Date Total LT Line Number of Maximum L ____________________ ___________ Length (km) Consumers Demand (KVA) 1. MataraUC 91.12.30 129.3 9880 3900- 2. Minuwangoda UC 92.04.23 47.7 2414 863. 3. Nawalapitiya UC 92.04.28 25.9 3307 1177 4. Hambantota UC 92.04.28 19.0 1875 542 5. Monaragala PS 92.04.28 27.1 980 542 6. Weligama UC 92.05.28 53.8 3380 857 7. Gampola UC 92.06.24 50.6 5658 1549 8. Talawakele Lindula UC 92.06.25 7.1 980 283 9. Batticoloa MC 92.07.20 125.2 7000 2037 10. Wattegama UC 92.08.18 9.2 1023 294 11. Hatton - Dikoya UC 92.08.24 23.0 2780 1018 12. Mutur PS 92.08.27 16.4 554 190 13. Manmunai S & EP PS 92.09.24 24.6 1200 257 14. Balangoda UC 92.10.05 75.4 2002 829 15. Matale MC 92.10.29 75.6 6329 1895 16. Manmunai PS 92.10.29 18.1 1107 238 17. Kurunegala MC 92.10.29 81.6 5980 2968 18. Kegalle PS 92.10.29 17.5 386 130 19. Gampaha UC 92.11.26 41.1 3656 1276 20. Rambukkana PS 92.12.07 28.5 1000 310 21. Kandy MC 95.12.29 207.0 20000 10561 22. Ratnapura MC 97.10.02 84.1 9000 2655 Total 34371  Key Indicators for Project Implementation Distribution and Rehabilitation Works Indicators Quantity Acc. to Staff Quantity actually Quantity Acc. to reduced Status as at Appraisal Report planned after survey scope corresponding to the 30e June 1998 curtailed programme 1. New MV overhead lines (km) 400 390 195 57 2. New LV overheads lines (km) 600 600 300 183 3. New 11 kV underground Cables (km) 35 27 _ . 4. New LV UG Cables (km) 50 35 _ _ 5. New 33kV/LV Substations (nos) 50 MVA 375 233 124 6. New 1 lkV/LV Substations (nos) 90 7. New Indoor type 1 lkVILV Substations (nos) 12 MVA 50 ___ 8. New 33kV/1 1kV Primary Substations (nos) 06 06 02 9. Rehabilitation of 11 kV Underground Kandy MC system- systems (nos) 10. Service connection Rehabilitation 50,000 50,000 25,000 46,000 Meter Replacement (nos) 25,000 20,000 11. Substation Augmentation (nos.) - 10 12. LT line Rehabilitation of & Impr. (km) 300 519  Table 4: Project Costs Appraisal Estimate (US$M) Estimate (US$M) as of 30.06.98 Item Local Foreign Total Local Foreign Total Costs Costs Costs Costs Distribution l Distribution Lines / Cables 2.4 4.5 6.9 l Distribution Substations 1.6 2.9 4.5 Consumer Services, Meters 0.9 1.3 2.2 l Vehicles 0.5 0.5 1.0 11.14 12.82 23.96 Compensation Equipment - l Civil Works and Erection 6.6 6.6 l Way leave and Land Development 0.2 0.2 l CEB's administrative Cost 1.2 1.2 l Transmission Transmission Lines 11.6 15.3 26.9 o Grid substations 3.2 5.0 8.2 Compensation Equipment 0.2 1.3 1.5 21.10 28.84 49.94 Way leave and Land Development 1.1 - 1.1 I CEB's administrative Cost 0.5 - 0.5 Technical Assistance Capacity Building Consultancy 0.1 1. I 1.2 0.28 0.91 1.19 Training 0.1 0.6 0.7 0.00 0.67 0.67 Project Support Consultancy 0.1 1.2 1.3 0.30 1.86 2.16 Hydroproject Consultancy 0.2 1.6 1.8 1 - - Total Base Cost 30.5 35.3 65.8 Physical Contingencies 3.0 3.5 6.5 Price Contingencies 3.0 3.7 6.7 Total Project Cost 36.5 42.5 79.0 32.82 45.10 77.92 W  41 Annex C Page 1 of T Sri Lanka Second Power Distribution and Transmission Project Operation Plan OPERATIONAL ISSUES STRATEGY PERFORMANCE TIMING INDICATORS Project Completion The physical works for the CEB to complete this 220 kV Kotmale - November 1999 transmission component is component with its own Anuradhapura line incomplete at credit closing resources 220 kV substations at November 1999 ______________________ _Kelanitissa and Biyagama Distribution and CEB will use its own Ratnapura Municipal Council December 1999 rehabilitation works resources to complete this scheme and rehabilitation of component is incomplete at component the 1 kV underground system credit closing in the enhanced Kandy Municipal Council Scheme Project Operations Facilities constructed under The works commissioned Regular updating of the plant Regularly the project should be under the project are being and equipment register of the operated and maintained integrated within CEB's distribution systems taken over efficiently overall system. A from licensees comparison will be made with the past performance of The depot system maintenance Quarterly the licensees' to determine register updated each quarter the quality of service Maintenance work of Regularly substations including scheduled replacement of transformer oil is carried out regularly LH and HV breakdowns of Monthly systems taken over monitored regularly Training of technical staff According to according to an approved plan training plan.  42 Annex C Page 2 of 2 OPERATIONAL ISSUES STRATEGY PERFORMANCE TIMING INDICATORS Project Operations (Cont'd) Efficient operation of the CEB will monitor system Monitoring of voltage levels at Monitoring started system should lead to losses and variation in pre selected feeders with the reduced system losses, and voltages in the licensees' Minuwangoda UC restriction of voltage systems taken over scheme and is variations continuing in the other systems Reduce system losses by 1 Annually percent annually Reduce operation and By increasing the maintenance costs number of customers per employee, as has been occurring each year, and by amalgamating the routine distribution maintenance and rehabilitation of works Compliance with covenants CEB should adjust tariffs at Agreed tariff adjustments Compliance with revenue Each year the beginning of each fiscal based on CEB's ability to covenants year so that their revenue meet its revenue covenant projections are sufficient to and rebalancing of tariffs to earn a rate of return of 8 eliminate cross-subsidies percent on current value of its net fixed assets  Table 1: CEll Historical and Forecast Income Statements (SLRs million)' 1991 1992 1993 1994 1995 1996 1997 1998 Proj. Act. Proj. Act. Proj. Act. Proj. Act. Proj. Act. Proj. Act. Proj. Act. Proj. Act. Energy Generation (GWh) 3284 3376 3172 3539 3700 3978 3942 4362 4209 4800 4546 4527 4910 4899 5303 5558 SystemLoss(%) 16.0 18.8 15.0 19.0 14.0 22.0 13.0 18.0 12.0 18.2 12.0 18.0 12.0 16.0 12.0 18.7 Energy Sales (GWh) 2758 2742 2952 2916 3182 3126 3430 3565 3704 3915 4007 3737 4321 4116 4666 4521 Sales Growth(%) 7.0 5.1 7.0 6.3 7.8 7.2 7.8 14.0 8.0 9.8 8.0 -4.5 8.0 10.0 8.0 10 Tariff Increase (%) 4.1 1.8 17.7 27.8 8.1 8.0 3.7 7.5 AverageTariff (RstkWh) 2.40 2.24 3.00 2.82 3.45 2.69 3.86 3.44 4.00 3.72 4.00 4.02 4.00 4.15 4.00 4.46 Operating Revenue Electricity Sales 6620 6144 8855 6653 10977 8396 13253 12256 14815 14566 16000 15030 17280 17165 18662 20176 Fuel Surcharge 345 502 1727 366 958 0 0 0 0 OtherOperating Revenues 219 1008 230 594 241 1202 254 859 266 704 280 1311 293 2634 308 1939 Interest Eamings 148 64 86 96 61 15 179 549 324 1164 497 1523 674 452 721 310 Total Operating Revenme 7332 7718 9171 9070 11279 9979 13686 14622 15405 16434 16777 17864 18247 20251 19691 22425 Operating Expenses Fuel Cost 335 479 103 1645 238 349 510 912 988 987 1487 3950 1830 5534 2476 2553 Purchased Power 610 2475 Operation & Maintenance 1041 1698 1364 1831 1664 1882 1980 1989 2187 2248 2362 2937 2523 3655 2748 4504 Turnover Tax 209 199 269 368 336 438 413 661 474 858 525 930 573 1233 634 390 Administration 508 421 559 611 615 741 676 842 744 958 818 1517 900 1845 990 1713 Depreciation 1908 2064 2501 2134 3051 2875 3403 3362 3759 3694 4060 4223 4336 4815 4724 5078 Other2 1768 1927 104 Total Operating Expenses 4001 4861 4796 6589 5904 6285 6982 7766 8152 8745 9252 15325 10162 19619 11572 16817 Operating Income 3331 2857 4375 2481 5375 3694 6704 6856 7253 7689 7525 2539 8085 632 8119 5608 Less: Interest Charged Operations 2018 2457 2644 2111 2699 2345 2680 2741 2676 2324 2802 2360 3136 2464 3702 2806 Expenditure of Feas. Studies 40 7 40 95 40 85 40 305 40 144 40 83 40 158 40 86 NetIncome BeforeTax 1273 393 1691 275 2636 1264 3984 3810 4537 5221 4683 96 4909 -1990 4377 2716 Income Tax Net Income 1273 393 1691 275 2636 1264 3984 3810 4537 5221 4683 96 4909 -1990 4377 2716 Retum On Net Fixed Assets (%) 7.36 6.45 7.05 3.45 6.99 4.61 7.99 7.84 8.01 8.00 7.92 2.54 8.23 0.57 7.11 4.56 1. All values for 1991-1998 are from CEB's records 2. Other' includes cost of hiring generators and power purchases O I LI)  Table 2: CEB Historical and Forecast Balance Sheet (SLRs million) 1991 1992 1993 1994 1995 1996 1997 1998 Proj. Act. Proj. Act. Proj. Act. Proj. Act. Proj. Act. Proj. Act. Proj. Act. Proj. Act. Assets Fixed Assets Fixed Assets 76674 72670 105253 106556 116666 122449 130809 133637 142571 147734 152719 180245 162618 207455 180913 226838 Less Cum. Dep. 22292 26510 26645 31152 31622 36424 36950 42004 43229 47492 70139 53443 80160 59984 87618 Net Fixed Assets 54382 72670 78743 79911 85514 90827 94385 96687 100567 104505 105227 110106 109175 127295 120930 139220 Construction In Progress 23472 27773 7396 6120 7504 3832 4823 4918 6094 4923 9746 9512 17980 14819 21755 15085 Investment in Subsidiaries 345 340 355 340 365 485 375 635 385 635 395 723 405 723 415 722 Insurance Escrow Account 327 271 432 332 549 435 679 552 822 658 975 799 1137 973 1318 1162 Current Assets Cash 1443 692 273 -2039 958 1107 2620 5688 3860 7757 6083 4177 7392 1409 7024 637 Inventories 1917 2414 2631 2698 2917 2512 3270 3048 3564 2875 3818 3730 4065 4542 4523 5701 Accounts Receivable 1741 1416 2214 1919 2744 2300 3313 2766 3704 2919 4000 3099 4320 3763 4666 4568 Other Receivables 1921 2201 2113 3065 2324 1288 2556 2234 2812 4360 3093 5310 3402 4633 3743 4652 Deferred Revenue Expenditure 410 355 257 Total Current Assets 7022 6723 7231 5643 8943 7207 11759 13736 13940 17911 16994 16726 19179 14702 19956 15815 Total Assets 85548 107777 94157 92346 102875 102786 112021 116528 121808 128632 133337 137866 147876 158512 164374 172004 Equity Government Equity 8543 8468 9393 9155 9673 9907 9851 10620 9851 10773 9851 11763 9851 12106 9851 12943 ConsumerContribution 4139 4102 4835 4561 5611 5850 6473 6824 7425 7825 8457 7105 9579 10278 10796 10437 Revaluation Surplus 31458 33074 35645 37647 40370 44829 45500 51170 50220 58890 53639 65858 57217 83762 60929 88794 Retained Eamnings 11361 10532 13051 10807 15687 11598 19672 15381 24209 20371 28891 20351 33801 17983 38178 20706 Total Equity 55501 56176 62924 62170 71341 72184 81496 83995 91705 97859 100838 105077 110448 124129 119754 132880 LongTerin Debt 23128 24049 24055 24753 24132 23513 23913 25311 24375 22959 26295 23833 30907 23258 37422 26264 Other Uabilities./Deferred 2245 2150 2106 1226 0 0 0 2429 0 2786 Income CurrentMaturitiesofLTD 1840 1967 1992 1816 1873 2038 2026 2181 2340 1773 Other Current iabilities 2834 4814 3061 5423 3305 7089 3570 7222 3856 7815 4164 8955 4497 6515 4857 8299 Total Current Liabilities 6919 4814 7178 5423 7403 7089 6612 7222 5729 7815 6202 8955 6523 8696 7197 10072 Total Equity And Liabilities 85548 85039 94157 92346 102876 102786 112021 116528 121809 128633 133335 137865 147878 158512 164373 172002 Current Ratio 1.0 1.4 1.0 1.0 1.2 1.0 1.8 1.9 2.4 2.3 2.7 1.9 2.9 1.7 2.8 1.6 LongTermDebt 31 30 29 28 27 26 24 21 22 19 22 18 23 16 25 17 /Equity 69 70 71 72 73 74 76 77 78 81 78 82 77 84 75 83 (D tv) ti tt  Table 3: CEB Historical and Forecast Fund Flow Statement (SLRs million) 1991 1992 1993 1994 1995 1996 1997 1998 Proj. Act. Proj. Act. Proj. Act. Proj. Act. Proj. Act. Proj. Act. Proj. Act. Proj. Act. Source Net IncomelNet income Before Interest 3,292 2,857 4,334 2,481 5,335 3,694 6,665 6,856 7,213 7,465 7,484 2,539 8,045 474 8079 5522 Depreciation 1,908 2,064 2,501 2,134 3,051 2.875 3,403 3,362 3,759 3,694 4,060 4,223 4,336 4,815 4,724 5,078 Exp. In Feasibility Studies 7 95 85 305 144 83 158 86 Intemal Cash Generation 5,200 4,914 6,835 4,520 8,386 6,484 10,068 9,913 10,972 11,015 11,544 6,679 12,381 5,289 12,803 10,600 Less: Prior year Adjustment 360 Equity Contribution 432 420 850 687 280 752 178 713 0 153 0 990 0 343 0 837 Other Contribution 580 690 696 459 775 1,289 863 973 951 1,001 1,033 914 1,121 3,523 1217 525 Loan 4,270 3,620 2,894 1,999 2,069 712 1,597 1,720 2,335 1,087 3,958 2,781 6,638 3,676 8855 4779 Deferred Liabilities 333 357 Total Sources 10,482 9,644 11,275 7,665 11,510 9,237 12,706 13,319 14,258 13,256 16,535 11,364 20,140 12,804 22,875 17,098 Applications Construction Program 8,014 6,760 6,600 5,891 5,206 4,326 4,461 3,967 6,493 3,797 8,952 7,445 12,941 9,407 16541 12231 Other Investments 10 10 7 10 138 10 150 10 0 10 337 10 0 10 0 Consumer Cont. to Profits 350 365 Debt Service: Interest 1,179 2,457 2,739 2,111 2,743 2,345 3,559 2,741 3,902 2,324 2,802 2,360 3,136 2,464 3702 2806 Debt RepaymentVAmortization 941 407 1,840 1,439 1,967 1,474 1,992 1,642 1,816 1,551 1,873 1,801 2,038 1,937 2026 2181 tn Charges to Insurance Reserve 18 DepositTo Escrow Account 77 67 105 63 117 107 131 144 143 113 153 140 163 174 181 189 Special Levy to Govemment 1,500 0 Increase In Worldng Capital Cash Increase -78 264 -1,170 -2.731 686 3,146 1,662 4,581 1,240 2,113 2,223 -3,580 1,309 -2,768 -369 -772 OtherThan Cash Increase 338 -311 1,152 885 782 -2,299 891 95 654 3,359 523 1,361 544 1,221 783 101 Total Applications 10,481 9,644 11,276 7,665 11,511 9,237 12,706 13,320 14,258 13,257 16,536 11.364 20,141 12,803 22,874 17,101 LTDServiceCoverage 1.76 1.72 1.52 1.27 1.8 1.70 2.16 2.26 2.44 2.84 2A7 1.61 2.39 1.20 2.24 2.13 Self-financing Ratio (%) 34 30 33 47 40 36 41 14 49 41 44 37 40 20 39 47 Ft)  46 Annex E Page 1 of 2 IMPLEMENTATION COMPLETION REPORT SRI LANKA SECOND POWER DISTRIBUTION AND TRANSMISSION PROJECT (Credit-2297-CE) Recalculation of Economic Rate of Return 1. The ERR calculations for this ICR follow as far as practicable the methodology used in the SAR. As the project forms an integral part of CEB's 1991-2000 investment program, the ERR calculations are, as they were in the SAR, based on this program and not on the project. Actual data have been used up to 1998, and revised projections for 1999-2001 based on most recent available information. After year 2001, costs and benefits have been assumed to remain constant in real terms. The main features of the ERR calculations are summarized below: (a) Capital costs for 1991 to 1998 have been taken out of CEB's books and taxes, duties and revaluation adjustments have been removed; the estimates for 1999 and 2000 are based on past investment trends and CEB's indication that all project works will be completed by the end of 1999; (b) CEB's purchase of power and lease of generating capacity in recent years have been excluded as not being related to the 1991-2000 investment program; (c) Incremental operating costs exclude depreciation and taxes; CEB's operating costs defined in this manner have over the period 1992-1998 fluctuated between 2.1 percent and 2.5 percent of gross fixed assets in operation; for the purpose of ERR calculations, incremental operating costs have been assumed to equal 2.3 percent of accumulated capital costs for CEB's 1991-2000 investment program; (d) Fuel costs for incremental power generated in 1991-1998 are based on CEB's actual fuel costs and for 1999-2001 on CEB's Long Term Generation Expansion Planning Studies (1998); (e) CEB's actual incremental revenues for 1992 to 1998 have been used, interest and other non-operating income have been excluded and no deductions for turnover tax have been made; for 1999, no tariff increase is expected, and for 2000 and 2001, annual increases of 10 percent have been assumed; for the "willingness to pay" case, higher tariffs in real terms - as demonstrated by consumers' willingness to pay in the past - have been used; (f) All nominal cash flows have been expressed in 1998 real terms using the IMF published GDP deflator for 1991 to 1997 and the CPI for 1998 to 2001, i.e. 9 percent for 1998, 8 percent for 1999, 7 percent for 2000 and 6 percent for 2001; after 2001, all incremental costs and benefits have been assumed to remain constant in real terms; (g) The useful life of the assets created under CEB's 1991 to 2000 investment program is expected to end in 2025; no residual values have been considered.  47 Annex E Page 2 of Z Constant 1998 Sri Lanka Rupees (SLR million) Incremental Incremental Incremental Year Capital Cost Oper. & Fuel Cost Benefits Net Maint. Benefits 1 1991 10,846 249 0 0 -11,095 2 1992 8,610 447 132 -159 -9,348 3 1993 5,778 580 84 1,615 -4,828 4 1994 4,832 692 299 6,036 214 5 1995 4,210 788 387 7,492 2,107 6 1996 7,442 960 1,195 6,151 -3,446 7 1997 8,613 1,158 1,875 6,975 4,671 8 1998 6,720 1,312 1,002 8,441 -593 9 1999 3,864 1,401 1,863 8,927 1,799 10 2000 1,428 1,434 2,080 11,060 6,118 11 2001 1,434 2,355 13,619 9,829 12 2002 1,434 2,355 13,619 9,829 13 2003 1,434 2,355 13,619 9,829 14 2004 1,434 2,355 13,619 9,829 15 2005 1,434 2,355 13,619 9,829 16 2006 1,434 2,355 13,619 9,829 17 2007 1,434 2,355 13,619 9,829 18 2008 1,434 2,355 13,619 9,829 19 2009 1,434 2,355 13,619 9,829 20 2010 1,434 2,355 13,619 9,829 21 2011 1,434 2,355 13,619 9,829 22 2012 1,434 2,355 13,619 9,829 23 2013 1,434 2,355 13,619 9,829 24 2014 1,434 2,355 13,619 9,829 25 2015 1,434 2,355 13,619 9,829 ERR using average tariff as benefit proxy: 12.2% 2. The cost and benefit streams presented above produce an ERR of 12.2 percent. If consumers' proven willingness to pay is used, the ERR would be 14.8 percent. The indicated ERRs most likely underestimate the real benefits of CEB's 1991-2000 investment program, as the calculations largely reflect existing tariff levels and do not fully capture the consumer surplus. 3. In its Operations Plan, CEB indicates that it intends to comply with the covenanted rate of return of 8 percent. This would require a tariff increase of about 30 percent over current levels. If such an increase is assumed to be in effect as from 2000, and maintained in real terms thereafter, the resulting ERR would be 16.8 percent.