Colombia - Second San Carlos Hydro Power Project

Document of The World Bank FOR OFFICIAL USE ONLY Report No. 2464a-CO STAFF APPRAISAL REPORT COLOMBIA SAN CARLOS II HYDRO POWER PROJECT May 30, 1979 Projects Department Latin America and the Caribbean Regional Office 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 EQUIVALENTS Currency Unit = Colombian Peso (Col$) Col$1 = 100 Centavos (ctv) Col$39.10 (1978 appraisal assumption of average) = US$1 Col$1,000 = US$25.58 (1978 average) Col$1,000,000 (MCol$) = US$25,575 (1978 average) MUS$ = US$1,000,000 WEIGHTS AND MEASURES 1 meter 2 3.281 feet (ft) 2 1 square kilometSr (kmi) = 0.386 square mile (mi3) 1 cubic meter (m ) = 35.315 cubic feet (ft ) = 264.2 gallon (gal) = 6.290 barrels (bbl) 1 kilogram (kg) - 2.206 pounds (lb) 1 ton (t;metric;1,000 kg) = 1.100 short tons (sh. tons) 1 kilowatt (kW) = 1,000 Watts i10 W) 6 1 Megawatt = 1,000 kW (106kW = 109 W) 1 Gigawatt (GW) = 1,000 MW (10 kW = 19 W) 1 kilowatt-hour (kWh) = 1,000 Watt-hours (10 Wh) - 830.3 kilocalorieg (kcal) 1 Gigawatt-hour (GWh) = 1,000,000 kWh9(10 kWh) 1 Terawatt-hour (TWh) = 1,000 GWh (10 kWh) 1 kilovolt (kV) - 1,000 Volts (V) 3 1 kilovolt ampere (kVA) = 1,000 Volt amperes (10 VA) 1 Megavolt ampere (MVA) - 1,000 kVA (10 VA) 1 Megavolt ampere re- 1 Megavolt ampere reactive active (MVAr) power (cos 0 = 00) 1 kilocalorie (kcal) - 3.968 British thermal units (Btu) 1 Hertz (Hz) = 1 cycle/second ...per ... - ...per second; ...per hour =/s;.../h ...per day;...per year = .../d;.../a GLOSSARY OF ABBREVIATIONS ISA = Interconexion Electrica S.A. EEEB = Empresa de Energia Electrica de Bogota EMCALI = Empresas Municipales de Cali EPM = Empresas Publicas de Medellin CHEC = Central Hidroelectrica de Caldas CHIDRAL = Central Hidroelectrica del Rio Anchicaya S.A. CORELCA = Corporacion Electrica de la Costa Atlantica CVC = Corporacion Autonoma Regional de el Valle del Rio Cauca ICEL = Instituto Colombiano de Energia Electrica NPD = National Planning Department JNT = Junta Nacional de Tarifas IDB = Inter-American Development Bank KfW = Kreditanstalt fur Wiederaufbau Fiscal Year = Calendar Year  FOR OFFICIAL USE ONLY COLOMBIA SAN CARLOS II HYDRO POWER PROJECT TABLE OF CONTENTS Page No. 1. THE SECTOR ............................................. 1 Energy Resources .................................. 1 Sector Organization ..................... . 3 Regulation, Planning and Coordination ............ . 5 World Bank Participation in the Sector ............ 6 Power Market and Supply ...... ............. 8 Rural Electrification ...... ............. . 9 Sector Investment Program and Studies ............. 9 Finances and Tariffs .... ............................. 11 Constraints on Sector Development ........... . 12 2. ISA AND ITS SHAREHOLDERS .............................. 12 ISA ............................................... 12 Bylaws ....... .............. ................... 13 Organization and Administration ....... ........ 13 Employment and Training ........... .. .......... 14 Accounting and Auditing ........... .. .......... 14 Insurance ...... .............. ................. 14 Prior Bank Lending ............. .. ............. 14 ISA's Shareholders ............... .. ............... 15 EEEB and EPM .................................. 16 CVC ....................... .................... 16 ICEL ....... ............... .................... 16 CORELCA ..................... .................. 17 3. THE POWER MARKET ....................................... 17 Historic ................. ......................... 17 Forecasts ....... ............... ................... 19 Balances of Capacities and Energies ....... ........ 19 4. THE NATIONAL DEVELOPMENT PROGRAM AND THE SAN CARLOS II PROJECT .............................................. 22 The Program ....................................... 22 National Development ............. .. ............. 22 ISA Development ................ .. ............... 23 The Project ....................................... 24 The San Carlos I Project (1582-CO) ...... .. ...... 24 Objectives ....... ............. .................. 25 "This report is based on the findings of an appraisal mission which visited Colombia during October/November 1978 and January 1979. The mission comprising Messrs. W.F. Kupper and J. Gorrio' was assisted by Mr. Claude Besse' (consultant) during the October/November 1978 visit. 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.  TABLE OF CONTENTS (Continued) Page No. Description .................... .................. 26 Estimated Cost .................. ................. 27 Financing ..................... ................... 27 Engineering; Studies; Training ........ .. ......... 28 San Carlos II ....i ............................. 28 Calderas .................... ................... 29 Transmission .. ......... 29 Dispatch Study ............... .. ................ 29 Training of ISA's Staff ........... .. ........... 29 Rectroactive Financing ............ .. ............. 31 Implementation Schedule ............ .. ............ 31 Procurement ...... ............ .. .................. 31 Disbursements ................. .. ................. 31 Environmental Aspects .............. .. .......... 31 Project Risks ...... ............ .. .............. 32 Project File ...... ............ .. ................... 32 5. FINANCES ......................... ....................... 33 Introduction ...... ............ .. ................... 33 ISA's Performance and Financial Position ....... 33 Financing Plan ................. ................ 36 Future Finances ................. .. .............. 38 Financial Outlook of ISA's Shareholders ......... 40 EEEB ............................................... 41 EPM ......................... ....................... 41 CVC ......................... ....................... 42 CORELCA ....................... ..................... 42 ICEL ........................ ....................... 43 Performance Indicators and Reporting ...... .. ....... 43 Uniform System of Power Sector Accounts ............ 44 6. ECONOMIC ANALYSIS ................................... .... 44 Comparison of Alternatives ........... .. ............ 44 Return on Investment .............. .. ............... 47 7. AGREEMENTS REACHED AND RECOMMENDATION ................... 48 ANNEXES 1.1 IBRD Power Loans ........................................ 50 1.2 1977 Sector Installed Capacities and Power Generation ... 51 2.1 ISA: Organization Chart (IBRD 20297) ................... 52 2.2 Description of ISA's Shareholders ....................... 53  TABLE OF CONTENTS (Continued) Page No. 3.1 Main Power Systems, Electricity Supply Data .... ......... 57 3.2 Forecast Energy Requirements Interconnected System, 1978-85 ................................................ 58 3.3 Balances of Energies and Capacities Interconnected System, 1978-85 ........................................ 59 4.1 ISA's Development Program Cost Estimate, 1970-85 60 4.2 Hydro Developments on the Nare, Guatape and Samana Rivers (IBRD 20098) .................................... 61 4.3 San Carlos I Revised Cost Estimates (Loan 1582-CO) ...... 62 4.4 San Carlos II Cost Estimate ............................. 63 4.5 Implementation Schedule, Key Dates ...................... 64 4.6 Loan Disbursement Schedule .............................. 65 4.7 Contents of Project File ................................ 66 5.1 Actual and Estimated Income Statements, 1976-85 .67 5.2 Actual and Estimated Balance Sheets, 1976-85 .... ........ 68 5.3 Actual and Estimated Sources and Applications of Funds, 1976-85 ......................................... 69 5.4 Financial Performance Indicators ........................ 70 5.5 Schedule of Existing and Proposed Long Term Debt as of September 30, 1978 .................................... 72 5.6 Estimated Capital and Security contributions, 1978-85 ... 73 6.1 Rate of Return on Project ............................... 74 MAPS IBRD 3948R2 - ISA's Electric Power Systems IBRD 13005R2 - San Carlos Hydro Power Projects   COLOMBIA SAN CARLOS II HYDRO POWER PROJECT 1. THE SECTOR Energy Resources 1.01 Colombia's main indigenous commercial energy resources are hydropower, coal, gas and oil. Potential hydropower appears to be the most promising at some 100 GW of capacity and 250-300 TWh of annual energy capability, as shown by the preliminary investigations made by the Govern- ment with technical assistance from the Federal Republic of Germany. 1.02 Colombia is also endowed with very large coal and gas deposits. Over 1970-77 crude oil output declined at an average rate of 6.5%/a. Over the same period, consumption of petroleum products increased by 5.5%/a. As a result, Colombia is now a net importer of crude oil (it was a net exporter until 1976) and prospects are for these imports to rise sharply to onerous levels by the early 1980s unless additional reserves are discovered and developed quickly. Measures are being taken (1.05) to deal with this problem and to develop alternative energy sources. In the case of coal, there have been various obstacles to more adequate utiliza- tion of the existing potential: prices as low as one-fifth of those prevailing on international markets, the competition of low-priced petro- leum, fragmentation of production among a large number of very small mines with low output and productivity levels, and lack of efficient marketing and transport infrastructure. However, the Government is currently taking action to address these problems, and large-scale development of coal reserves is planned (1.04). With respect to natural gas, a previous decline in known reserves and output has been dramatically reversed with the dis- covery of large deposits in the Atlantic Coast region. These reserves (estimated at over 5 x 1012 ft3) will provide energy and petrochemical feedstock to this rapidly industrializing region. 1.03 Output of primary energy during 1965-75 has not kept pace with overall economic expansion. It increased only 3.6%/a during 1965-70 when it reached its peak at 690 x 1012 Btu, and declined since then to 637 x 1012 Btu in 1977, mainly due to falling crude oil output:  - 2 - ------------------- Primary Energy Output 1/ ---------------- 1965 1970 1977 Heat Heat Heat Equiva- Equiva- Equiva- lent 2/ lent 2/ lent 2/ Unit Quantity 1012 Btu Quantity 1012 Btu Quantity 1012 Btu Hydro power GWh 3,649 38.3 6,212 65.2 10,500 120.8 Crude Oil 106bbl 73.2 410.0 80.1 448.3 50.2 281.1 Natural gas 109ft3 65.7 65.7 105.0 105.0 122.0 122.3 Coal 106t 2,230 64.0 2,500 71.7 3,947 113.2 Total 578.0 690.2 637.4 ------------------- Final Energy Consumption 1/ --------------- 1965 1970 1977 Heat Heat Heat Equiva- Equiva- Equiva- lent 2/ lent 2/ lent 2/ Unit Quantity 1012 Btu Quantity 1012 Btu Quantity 1012 Btu Electricity GWh 4,790 50.3 7,538 79.1 14,900 156.5 Petroleum Products lO6bbl 23.5 131.6 33.8 189.3 48.5 271.6 Natural Gas 109ft3 12.1 12.1 84.8 84.8 96.1 96.1 Coal 106t 2,700 76.9 2,100 61.6 3,647 104.6 Total 270.9 415.0 628.8 In contrast to the declining energy output, final energy consumption has grown by 8.9%/a during 1965-70, and 8.5%/a during 1971-73, when economic growth was high and energy prices declined sharply in real terms. During 1974-77, the economic down-turn and increase in real energy prices had a dampening effect on consumption, which now has settled at a growth of about 4.5%/a compared with a GDP growth of some 6% in recent years. 1/ The difference between primary energy output and final energy consump- tion, expressed in heat equivalent, constitutes the approximate sum of total losses and exports. 2/ Calculated at: 11,500 Btu/kWh for power, 5.6 MBtu/bbl for oil and its products, 1 MBtu/103 ft3 for gas and its products and 28.69 MBtu/t for coal and coke.  1.04 The Government's development strategy is aimed at achieving a more favorable balance between domestic energy supply and use, thus utilizing more fully those energy sources which are in abundant supply, i.e., hydropower, natural gas and coal. The Government is planning a large-scale development of coal deposits by state entities in association with foreign investors. For that purpose, a new enterprise, CARBOCOL, has recently been created and is likely to emerge as the Government's chief agency in coal-related matters. The Government attaches high priority to developing the thermal coal deposits at El Cerrejon (reserves 600 Mt and production target 10 Mt/a) near Riohacha in the department of La Guajira on the Atlantic coast under CARBOCOL's responsibility in cooperation with foreign investment. The Government also intends to step up surveys of identified coal fields in the provinces of Santander and Antioquia with the intention to study the feasibility of using low grade coal for firing large thermal plants required in the early nineties when potential hydro sites are expected to be increasingly more costly to develop (1.24). Small private firms which own coal mines are pursuing plans to expand output in order to supply fuel for heat intensive industrial processes and in-plant power generation. In order to expand potentially viable mines, a well-coordinated Government program is needed to provide a more rational price structure, improvements in mine safety, credit facilities and support for marketing and infrastructure. Such a program would need substantial technical and capital assistance from abroad and the Bank is providing guidance to the Government in the preparation of a proposed coal engineering project. 1.05 In the hydrocarbon sector, the Government has taken action to stimulate investment in exploration and field development, which had declined after 1971 because of unrealistically low prices applied to domestic sales. The Government is encouraging foreign participation in exploration and development on the basis of association contracts with ECOPETROL (the Government oil agency). The prices paid for oil produced by increasing yields from existing fields and from new fields have been raised, the latter now being close to world market levels, and the dis- criminatory exchange rate for petroleum has been eliminated. As a result, interest among foreign petroleum companies to expand or start operations in Colombia has been intensified and a significant up-turn in exploration is expected. 1.06 Plans are underway to explore the country's uranium potential and the Government has concluded an exploration contract with the French IMinatome group. The development of any uranium potential that might exist would provide the country with another long-term energy option. Sector Organization 1.07 Electricity is the fastest growing form of energy use in Colombia; its share in overall energy consumption has grown from 14% in 1960 to 25% in 1977. This process has been assisted by the gradual consolidation of isolated facilities into regional systems and the interconnection of these  systems to facilitate development of Colombia's low-cost hydro resources. The main systems are (see Map 3948) the Central System, covering the interior and the Pacific coast, and the Atlantic (or Northern) system covering the northern part of the country. The site of the San Carlos hydro station, for the first stage of which a loan of MUS$126 (1582-CO) was approved in 1978, and of which the present project constitutes the second phase, is located in the Central System. By 1982 a full national grid will have been established with the completion of a 500-kV line inter- connecting the Atlantic and the Central systems, for which a Bank loan of MUS$50 (1583-CO) was approved at the same time as the loan for San Carlos I. 1.08 Public electricity services are presently provided by: (a) municipally-owned companies, independent of the Central Government, of which the largest are Empresa de Energia Electrica de Bogota (EEEB), Empresas Publicas de Medellin (EPM), and Empresas Municipales de Cali (EMCALI); (b) national enterprises such as Instituto Colombiano de Energia Electrica (ICEL), the Corporacion Autonoma Regional del Cauca (CVC), and the Corporacion Electrica de la Costa Atlantica (CORELCA); (c) a large number of local subsidiaries of ICEL, CORELCA and CVC 1/; and (d) a generating and transmission company, Interconnexion Electrica S.A. (ISA), the shareholders of which are EEEB, EPM, CVC, ICEL and CORELCA. ISA is the beneficiary of the San Carlos I loan mentioned above and will own and operate the 500-kV line interconnecting the Atlantic and the Central system, to be financed by the Government which is the borrower for Loan 1583-CO. 1.09 ISA was established in 1967 to provide a rational framework for sector development by interconnecting the systems of its shareholders, thus creating a national grid capable of sustaining large hydroelectric developments. By pooling their financial resources through ISA, its shareholders have been able to undertake much larger and more economical projects than would have been feasible under the previous arrangements for independent growth. Colombia also has a number of public entities known as Regional Autonomous Corporations with a range of functions related to development of the regions under their jurisdiction, including legal capacity to generate, transmit and distribute electricity. CVC is the largest of these entities. The Ministry of Mines and Energy owns part of the sector directly through ICEL and CORELCA. EEEB and EPM, presently the largest utilities, are controlled by autonomous municipal governments. CVC reports to the National Planning Department (NPD) as 1/ In most cases, the ownership of these subsidiaries is shared with local governments.  -5- do some other regional development corporations, IBRD Map 3948 shows the service areas of the major retailers; further details on the major utilities are given in Chapter 2. Regulation, Planning and Coordination 1.10 The Ministry of Mines and Energy is charged with formulating a national policy for the generation, transmission and distribution of electricity although it shares responsibility with NPD in defining investment priorities. The Ministry discharges its functions through its Electric Energy Division and was also given the responsibility for coordinating and supervising power sector planning. This division is still small and is in the process of being organized. It does not have the powers assigned to similar agencies in other countries (issuance of licenses, regulation of tariffs, approval of expansion programs) to enforce its policies and programs. Public utility retail tariffs (including those for electricity) are regulated by the Junta Nacional de Tarifas de Servicios Publicos (JNT) in the NPD, which has customarily approved requests for rate increases. However, utilities are free to set tariffs at levels lower than those approved by the Junta and have done so in the past. Although the Government cannot enforce its policies directly on the municipally con- trolled power companies, a mechanism for reaching agreement on major issues affecting the sector is provided by ISA, in which the Government has a major although not controlling interest. 1.11 Sector planning and coordination have improved markedly, as illustrated by the following: (a) In line with its recently revised bylaws, ISA defines the generation and transmission expansion program for the inter- connected system. On the basis of studies carried out by it and its shareholders, ISA executes simulation studies and ranks plant in order of economic merit. After approval by its Board, this becomes the national expansion program. As specified in these bylaws, all plants requiring a joint effort of all its shareholders are constructed, owned and operated by ISA. Plants of regional interest may be built by one or several shareholders, subject to ISA approval of such regional plants. Under these arrangements, ISA is, in effect, responsible for an important part of sector regulation and planning; only utilities which do not participate directly in ISA and the regional development corporations, other than CVC, would not be covered by its decisions. Voting arrangements in ISA have been restructured to require the concurrence of four of its five major share- holders in all important decisions, thus protecting the interests of the municipal utilities and encouraging a more positive participation in its deliberations; (b) As part of the San Carlos I loan, ISA and its shareholders agreed to prepare and present to the Government and the Bank for comments by December 31, 1979, a Power Sector Development Master  - 6 - Plan. This plan is to cover the period 1980-90 in detail and 1991-2000 in general terms and consolidate the programs for generation and transmission expansion. Similarly, ISA's shareholders undertook, under the coordination of the Ministry of Mines and Energy, to prepare and present, as part of ISA's Master Plan, to the Government and the Bank for comments by December 31, 1979, a 1980-2000 Sector Development Master Plan for Distribution consolidating all existing and future programs for distribution and covering the period 1980-85 in detail. Overall, the Master Plan is expected to provide a valuable framework for long-range decisions on sector financing, pricing and rural electrification which have in the past been based on partial and uncoordinated information. With respect to generation, the laster Plan will be based partly on an ongoing sector study which is expected to be completed by about mid-1979, and for which assistance was obtained from the Federal Republic of Germany. The first part of this study, which has been completed, concentrated on sector institutions and financing. The second part, which is being carried out with assistance from ISA, will comprise a compre- hensive survey of the country's hydro resources; (c) As agreed under the San Carlos I loan, a tariff study based on marginal costing is underway covering the most important supply areas in the country. With Bank guidance, this study is being carried out through a committee in which experts from the Government, ISA and its shareholders participate; and (d) Also under the aegis of San Carlos I, a study is being executed by consultants to assess the extent and causes of losses in the main power systems down to the level of distribution with the objective of identifying and carrying out actions which would minimize such losses. World Bank Participation in the Sector 1.12 Since 1950, the Bank has made 21 loans to Colombia's power sector, totalling US$610 million (Annex 1.1). Seventeen loans have assisted the expansion of capacity in the systems of Bogota, Medellin, Cali, Cartagena, Bucaramanga, and Manizales. In addition, the Bank is currently supporting rural electrification under the Integrated Rural Development Project (1352-CO, 1977). A report of the Bank's Operations Evaluation Department (OED) on the "Third Power Expansion Program Loan 537-CO" (Report No. 536, June 29, 1977) concluded that the objectives of the 1968 US$18 million loan to EEEB for expansion of its generating capacity (by 200 MW) and transmission, subtransmission and distribution systems had been met, despite some delays and a 12% cost overrun. A previous OED report, "Third Medellin Power Project - Loan 369-CO" (Report No. 450, May 24, 1974) concluded that the project had been very well executed despite considerable geological difficulties; although EPM's tariff levels were adequate to generate suffi- cient funds, anticipated revenues did not fully materialize because of power losses in the distribution system, a problem which has since been rectified. Overall bank operations in the sector have also been reviewed in two OED  -7- reports 1/ which concluded that the Bank's financing had been successful in assisting the power companies to develop hydroelectric plants at lower unit cost than they otherwise would have been able to do. This permitted greater urban coverage as well as cheaper and more reliable electricity supply to industry. OED also commended Bank efforts in the establishment of the central interconnected system which facilitated further power sector development. In addition, OED identified as important considerations for possible future loans in the Colombian power sector: the need to give greater attention to power distribution; the need for improvement of financial recording and financial planning capabilities; and the need to give more attention to public utility tariff structures. 1.13 The first OED recommendation (distribution) was addressed in Loan 874-CO (1973) which included expansion of electricity distribution in low income areas. However, between 1973 and 1978 Bank objectives could not be pursued through lending because of institutional difficulties. The municipal utilities were reluctant to relinquish their independent role in generation and also experienced severe financial constraints which reduced the availability of funds to ISA. Decisions on system expansion required protracted negotiations among the shareholders and the Government; those negotiations were further complicated by the original shareholders' reluctance to allow the incorporation of CORELCA into ISA. Throughout these negotiations, the Bank continued to support the concept of centralized planning, construction and operation of the national grid and resisted proposals that would weaken ISA. Because of the time required by the shareholders to arrive at decisions on these fundamental issues, Bank consideration of San Carlos I, the 500-kV Interconnection and EEEB's Mesitas hydroelectric project, all of them urgently needed to avoid power rationing in Colombia, suffered consider- able delays. A solution finally evolved after extensive discussions between the Bank, the Government and the shareholders, and the three loans made in 1978 served as a vehicle for addressing again the various OED's recommendations. Currently, a distribution project for the Bogota area is being considered for Bank financing, Bank involvement in a similar project in the CORELCA system appears possible, and a tariff study is being executed (1.11). Under the proposed loan a study will be made of the design of a common system of accounts for public power utilities. 1.14 The recent developments in the sector (1.11) have increased the confidence in the possibility that through further lending, the Bank's objectives in the sector can be more fully realized in the medium term. They are in general: coordinated sector planning, efficient organization and operation, and sound financial management; within the general scope of these objectives specific attention in the short term should be given to: least-cost operations, rational distribution developments, improvement in financial recording and financial planning capabilities and development of adequate tariff structures and levels on a common basis throughout the country. 1/ "Operations Evaluation Report: Electric Power" (Report No. Z-17, dated March 10, 1972) and '"ank Operations in Colombia - An Evaluation" (Report No. Z-18, dated May 25, 1972).  -8- Power Market and Supply 1.15 Electricity generation in Colombia increased by an average of 9.7%/a over the period 1960-70 and then slowed to about 9% on average until the end of 1977 1/ due to the slackening in industrial growth after 1974 (industrial consumption decreased to 7.2%/a compared with 9.5%/a during the sixties). Present annual per capita electricity generation is estimated at about 610 kWh, which is below the average for Latin America. Installed capacity at the end of 1977 was 3,765 MW, including self-production. Hydro stations accounted for 68% of total energy generation. 1.16 Colombia has about 2.2 million electricity subscribers in an estimated total population of 25.2 million; 88% of these subscribers are residential, and electricity service reaches 62% of the population. Studies by the Bank's Development Policy Staff indicate that Colombia has been able to provide electricity service to a very high proportion of its urban population (86%, with the connection rate exceeding 98% in the larger cities). However, only 36% of the families in small towns (500-2,500 inhabitants) and 16% of other rural families had service in 1976. Of the electrified municipalities, 88% have continuous service, while the other 12% have service only during certain hours of the day. In many towns the quality of the service is unsatisfactory because of lack of maintenance. 1.17 Residential consumers were responsible for the largest share of electricity sales by the major utilities in 1977, followed by industry: Sales 7]-/ Clients 3/ Category GWh % No. % Residential 4,803 42.3 1,912,556 87.6 Industrial 3,706 32.7 27,687 1.3 Commercial 1,545 13.6 218,954 10.0 Others 1,289 11.4 24,002 1.1 Total 11,343 100.0 2,183,209 100.0 1.18 Public utilities accounted for 93% of total electricity supply; the rest was provided by self-production. Of the public supply, EEEB generated 24%, EPM 22%, CORELCA 14%, CVC and ICEL 13% each, and ISA 7%. Self-suppliers (mainly oil refineries, petro-chemical plants, steel mills and cement works) owned 5.7% of the country's installed capacity; these plants are also connected to the public electricity service. The public-service labor force totalled 13,445 at the end of 1977, 1/ On the basis of unadjusted figures for 1977, which was a dry year causing considerable power curtailments (3.03). 2/ Source: ISA 3/ Source: ICEL  - 9 - including 6,690 manual workers; this gives ratios of 264 kW/employee and 162 subscribers/employee, which compare favorably with the average for Latin America. The following table summarizes (Annex 1.2) installed capacity and energy generated in Colombia in 1977: Public Service Self-Producers Total MW % GWh % MW % GWh % MW % GWh % Hydro, Subtotal 2,715 72 10,317 68 20 1 88 - 2,735 73 10,405 68 Steam 528 14 2,684 17 132 3 698 5 660 17 3,382 22 Gas turbine 266 7 1,041 7 39 1 188 1 305 8 1,229 8 Diesel 43 1 167 1 22 1 96 1 65 2 263 2 Thermal, Subtotal 837 22 13,892 25 193 5 982 1 1,030 27 4,874 32 Total 3,552 94 14,209 93 213 6 1,070 7 3,765 100 15,279 100 Rural Electrification 1.19 About 36% of the population lives in areas classified as rural. Although most of the rural villages with electricity service are close to the urban centers, connection density is modest (1.16). It is estimated that the cost of a rural electrification network, for the country as a whole, would be about US$600 per household; assuming that, over a period of six years, electricity could be brought to about 20% of the rural popula- tion presently without service (about 40,000 dwellings a year), the cost would be some MUS$150. The lack of comprehensive data with respect to ongoing and expected rural electrification efforts is expected to be remedied through preparation of the Masterplan (1.11). 1.20 Rural electrification programs are currently underway in a number of regions in the country. Among the most important are: (a) the electrification subproject of the 1977-79 Integrated Rural Development Program supported by IDB, Canadian International Development Agency and Bank financing (Loan 1352-CO); (b) the electrification program in the department of Choco financed by the Netherlands Government; and (c) the electrification program in the coffee-growing areas, financed by coffee sector resources. Sector Investment Program and Studies 1.21 The total 1978-85 investment program of ISA and its shareholders (except for ICEL for which reliable information is not available), excluding interest during construction, amounts to about Col$290 billion in current prices (about US$3.6 billion in end-1977 prices), with a foreign component of about 60%. Of the total, 65% pertains to ISA, 16% to EEEB, 9% to CORELCA, 7% to EPM and 3% to CVC. Taking into account that the shareholders' portion of the program also includes considerable investments in generation  - 10 - and transmission, some 70-75% of total investments would pertain to genera- tion, which is extremely high (a range of some 40-60% would be the norm). Because the new generating capacity would be of little use without a network path to the consumers, upward adjustments in investments for subtransmission and distribution can be expected and it is therefore probable that the esti- mated cost of Col$290 billion is understated. The master plan for power development to be prepared by ISA and its shareholders (1.11) is expected to provide a basis for firmer total investment estimates. 1.22 The investment program also includes, in addition to the projects already decided upon by the Government and ISA's shareholders (4.01), the start of generation and transmission projects which will be commissioned after 1985. ISA is now regularly updating 1/ its study of economic ranking of projects which indicates that the 1984-88 portion of this program, on which decisions still have to be taken (the program up to 1984 is being executed), would be the least-cost alternative for system expansion. 1.23 The study shows that, beyond plant already decided upon, only limited thermal capacity would be required up to about 1988; Cerrejon II (150 MW) in the CORELCA region as well as Tasajero I (132 MW) in the Central System (ICEL, North Santander) should be advanced as much as possible for completion not later than by the end of 1984, but hydro plant as scheduled would otherwise meet incremental demand for capacity and energy until the end of the period. 1.24 The introduction of large thermal plant later in the century is expected to play an important role in ISA's planning in the next few years (lead time for mine development and power station construction may aggregate some 10 years). Even the large hydro potential of some 100 GW (1.01) would be completely utilized by about 2020 and the use of the country's large coal reserves for firing of thermal plant may become more economic than hydro well before that time. The Government is aware of this problem 2/ and the Bank (through preparation of a proposed coal engineering project) together with the Government agencies involved, is addressing the problem. It is expected that the Government, without abandoning the objective of appraising all of the country's potential coal fields will focus on surveying and studying two areas: Tasajero in North Santander and Bolombolo in Antioquia. The use of coal for thermal plant firing and the substitution of coal for oil would be the primary objectives. It is anticipated that preliminary surveys and project preparation for a full study will warrant financial assistance in about a year. The inclusion of relatively large thermal plant also appears justified in terms of reliability of supply: to arrange the necessary financing for the large hydro plants being considered is time consuming and, by itself, may be a cause for delays while delays due to physical problems during construction are not unusual. 1/ Verificacion y actualizacion del programa de expansion del sistema interconnectado, Diciembre 1978. 2/ Disponibilidad de capacidad hidroelectrica y su influencia en la generacion termica en el futuro (Departamento Nacional de Planeacion Noviembre 1978).  - 11 - 1.25 The generation investment program will impose a heavy financial burden on ISA and its shareholders. To ensure that only sound projects are undertaken, assurances have been obtained under the San Carlos I loan that ISA and its shareholders would not undertake construction of any generating plant or combination of plants of more than 200 MW (ISA) and 100 MW (shareholders) capacity prior to completion of San Carlos I unless satisfactory evidence has been presented to the Bank that it is economically justified and that adequate financing is available to carry it out without jeopardizing the project. This covenant has been repeated in the agreements for the proposed loan. Finances and Tariffs 1.26 Except for EEEB and EPM, which have histories of adequate cash generation, the power sector has relied heavily on borrowings and budgetary contributions to finance its investments. EEEB and EPM operate low-cost systems and cover the most affluent markets in the country; they have, therefore, been able to finance their investments with an appropriate balance of borrowings and cash generation while charging relatively low rates. Because there has been no mechanism to obtain financial transfers within the sector from the more affluent areas to the less affluent, CVC, ICEL and CORELCA, which operate high-cost systems in lower income areas than EEEB and EPM, have had to rely on budgetary contributions from the Government and subsidies, despite their higher rates. 1.27 Rate adjustments lagged considerably behind yearly inflation over most of the period 1971-76, during which average rates increased by about 13%/a while inflation averaged 19%. The 1977 average revenue - at prices of 1970 - was equivalent to Col$0.179/kWh (89% of the 1970 average revenue of Col$0.202/kWh and up from Col$0.147 in 1976). The average 1978 rate is expected to be in the order of Col$0.780-0.800 or about USV2 equivalent. Furthermore, the positive trend in rate setting is expected to continue as a result of the agreements reached under the San Carlos I loan. In view of the importance to economic growth of adequate electricity service, the Govern- ment has adopted a policy calling for adequate rates in order to ensure that the sector generates internally a reasonable portion of the funds required. It should be noted that Colombia is still fortuitous in having access to relatively low cost hydro energy: ISA's development program is estimated to cost, in current prices, only about US$530/kW (4.03). As a result, the current rates are among the lowest in the world while meeting the requirements of sound financing of the power sector in the main centers. 1.28 In view of the considerable imbalances that currently exist in the structure of tariffs and the rates (residential consumers pay about half of the average charged to industry in the Medellin area), the power sector and the Government are studying the tariff structure and the rates with a view toward power pricing that reflects approximately the cost of supply to each consumer category (1.11). An important step in this direction has been taken by EEEB under the Bank loan for the Mesitas project. EEEB has agreed to introduce  - 12 - gradually revised tariff structures and rates in accordance with the above principle between April 1980 and June 1982. The implementation of the agreed recommendations of the tariff study under San Carlos I would be a major objective of further Bank lending in the sector. Constraints on Sector Development 1.29 In the past, the large number of entities associated with the power sector, the lack of adequate regulation, coordination and planning at the national level and low electricity rates constrained the sector's ability to make rational use of Colombia's abundant hydroelectric resources. The regionalized nature of the sector, reflecting the political and economic decentralization of Colombia, precluded technical cooperation and engendered difficulties in coordinating investment allocation; decisions were made on a local basis without due regard to overall country planning for power develop- ment. This, together with the lack of funds, resulted in recurring power shortages, a problem that will not be solved before well into the early eighties, and then only if the agreed development program is implemented expeditiously (the latter in turn, being largely dependent on adequate rate setting). To date, the sector's organization has precluded the usual practice of diverting resources from well-developed urban markets to support service in rural areas (1.26). 1.30 The Government has recently taken a number of positive measures to address the sector's institutional constraints. In 1975, it eliminated the jurisdictional overlap between ICEL and CORELCA on the Atlantic Coast by transferring control over the electricity distribution companies in that region to CORELCA. Another positive measure was the reorientation of ICEL, which in future will be responsible basically for electricity development in rural and semi-rural areas, where the Government will continue to subsidize the service since ICEL cannot be financially self- supporting in those areas. In order to remedy the problems that exist between the generating and distributing companies in the Cauca Valley, as a consequence of the complex organization of electricity service in that region, the Government has supported the establishment of a regional power company whose basic function will be to consolidate that region's electricity sector in a single enterprise (2.15). With the incorporation of CORELCA into ISA, most of the sector is represented directly or in- directly in ISA's Board and a better coordination of power sector planning in Colombia is now possible. ISA's effectiveness in achieving this coordination, however, will depend on its ability to sustain the consensus developed over the past 2 years among its shareholders. 2. ISA AND ITS SHAREHOLDERS ISA 2.01 Interconexion Electrica S.A. (ISA) would be the Borrower for the proposed San Carlos II Hydro Power Loan. ISA is a public corporation estab- lished in 1967 and is responsible for the expansion and operation of the inter- connected transmission system and generating plant of national significance.  - 13 - 2.02 Bylaws. ISA's shareholders, and their holdings as of December 31, 1978 are: Utility Shares % EEEB 4,876 25.0 EPM 4,875 25.0 CVC 3,826 19.6 CHIDRAL 1/ 74 0.4 ICEL 2,852 14.6 CHEC 2/ 75 0.4 CORELCA 2,922 15.0 19,500 100.0 1/ A CVC subsidiary - see 2.15. 2/ Central Hidroelectrica de Caldas, an ICEL subsidiary. ISA's bylaws, which are consistent with the decentralized structure of the power sector, give it many regulatory and planning functions. They also contain important provisions with regard to the financing of the major generation projects entrusted to ISA (Chapter 4). Under the previous loans, ISA has agreed to secure the concurrence of the Bank before amend- ments are introduced in the bylaws; this covenant has been repeated in the agreements for the proposed loan. 2.03 Organization and Administration. ISA is administered by its Shareholder Assembly, a 5-member Board of Directors and a General Manager. The Assembly must act on all major issues, and decision-making may be slow as the interests of the various shareholders sometimes differ. To ensure that decisions are based on a consensus, ISA's bylaws specify that the decisions of the Shareholders Assembly require the concurrence of 75% of the shares. 2.04 The General Manager, who is appointed by the Board of Directors for a 2-year term, renewable indefinitely, is in charge of the day-to-day management of the company. He is assisted by the chiefs of four depart- ments (Technical, Operations, Finance and Administration). ISA's present organization is adequate (Annex 2.1) but future recruitment of experts may be increasingly difficult (2.05; 4.17). With the help of consultants, it has handled well the technical and administrative aspects of the 230-kV Interconnection and Chivor I, and the 500-kV Interconnection and San Carlos I. It is not expected to encounter major problems in implementing the proposed project. ISA's transmission facilities and Chivor I are being operated satisfactorily. Financial planning has improved following the recent creation of the Finance Department. In 1977/78 ISA's main office was transferred from Bogota to Medellin, a consequence of the Government's decentralization policy. The transfer should prove generally advantageous, as ISA's major projects for the foreseeable future will be closer to Medellin than to Bogota.  - 14 - 2.05 Employment and Training. ISA's professional staff is suffi- ciently large (about 500 out of a total of 800 people) and experienced to handle its present responsibilities and its pay levels are satisfactory. ISA has a satisfactory general training program at various national institutions. However, in view of the rapid growth of the sector, the need for staff trained in special areas (e.g. hydrology, soil and rock mechanics, ecology, etc.), which are not taught at graduate level at the universities, is expected to outstrip available supply of qualified manpower. Thus, the proposed loan would finance a necessary study to determine training requirements as well as the carrying out of a sub- sequent training program (4.17). 2.06 Accounting and Auditing. ISA's accounting and data processing systems are good. Its monthly financial statements are produced promptly and contain the required data. ISA is reorganizing its internal auditing office to ensure that its auditing procedures keep pace with the company's growth. 2.07 Until 1975, ISA's annual financial statements were audited by independent external auditors acceptable to the Bank. In compliance with Government regulations, ISA's financial statements for 1976 and subsequent years are audited by the Office of the Comptroller of the Republic. How- ever, because this audit does not satisfy the Bank's requirements, the financial statements since 1976 have also been audited by an independent auditor, Cuellar, Feged and Ci., which is satisfactory. Under San Carlos I, ISA agreed that independent auditors, acceptable to the Bank, will continue to be used and that audited financial statements, together with a detailed auditor's report, will be submitted to the Bank within 4 months of the end of each financial year. This undertaking has been repeated in the proposed agreements for San Carlos II. 2.08 Insurance. ISA's transmission facilities are insured in accordance with sound utility practice and appropriate insurance was taken out for the Chivor I project before June 30, 1978 as required under the agreements for the San Carlos I project. 2.09 Prior Bank Lending. ISA has received three Bank loans totalling MUS$196.3. The first (Loan 575-CO for MUS$18) was made in 1968 to finance part of the foreign cost of the 230-kV Interconnection Project, which linked ISA's original shareholders, and a series of hydroelectric studies. The interconnection was completed in 1972 at a cost below the appraisal estimate and the Bank agreed that the savings could be used to finance the 230-kV Guatape-Barrancabermeja transmission line. Studies of the Cauca and Saldana rivers were respectively completed by Integral (Colombia) and Compania de Estudios e Interventorias (CEI, Colombia), and a feasibility study of the Betania hydroelectric project by the consortium Sedic (Colombia) - Harza (US); a feasibility study of the Sogamoso hydroelectric project was carried out by a consortium comprising Hidroestudios (Colombia) and Harza (US) and a feasibility study of projects on the Guavio river was carried out by Ingetec (Colombia); similarly a study of projects on the Rio Sinu basin in the Atlantic region was completed by the Consorcio Alto Sinu  - 15 - (Colombia)- Chas. T. Main (US). As a result of these studies, a project on the Guavio river (1,600 MW), two on the Rio Sinu (Urra I, 340 MW; Urra II, 710 MW) and one on the Rio Magdalena (Betania, 618 MW) have been identified and included in ISA's long-term development program. 2.10 The second loan (681-CO for MUS$52.3) was made in 1970 to finance part of the foreign cost of the 500-MW Chivor I Hydroelectric Project, ISA's first power station. The Inter-American Development Bank (IDB) made a MUS$35 loan for the project, and is providing MUS$48.5 in financing for Chivor II, which would add a further 500 MW capacity for operation in 1980/81. Chivor I was completed in mid-1977 (Project Completion Report dated February 1979), two years behind schedule, with a cost overrun of approximately MUS$86 (75%). The delay was due mainly to a contractor defaulting on construction targets (and being replaced) and to geological problems encountered during construction of the project's dam and tunnel. The cost overruns resulted from these problems, from higher-than-expected bid prices and particularly from Colombian and foreign inflation. 2.11 The Completion Reports on the 230-kV interconnection project and the Chivor I project have been prepared as a single report (February 1979). It concludes that the projects underwent engineering, physical, financial and institutional difficulties. The estimation of operational and invest- ment requirements for an institution so financially dependent as ISA, without provisions for price contingencies in an inflationary environment led to severe financial difficulties. The shareholders had to redefine their role in the sector and, in the process, execution of the projects was delayed. The experience gained under these projects has had a considerable impact on the shaping of Bank policy for further lending for San Carlos I. Adequate provisions for price contingencies have been introduced; local financing is being secured through long-term financial commitments-of the shareholders to ISA; improved financial planning was instituted by ISA and its shareholders as well as continuous monitoring of their financial performance. 2.12 The third loan (1582-CO for MUS$126) was made in 1978 for the San Carlos I project. IDB made a MUS$60 loan for the project, mainly to finance the dam. Main works were bid in intensive international competi- tion and total costs are expected to remain well below the original estimate (4.06). Main civil works, which started in May 1977 are on schedule. ISA's Shareholders 2.13 ISA's shareholders (Annex 2.2), which are satisfactorily perform- ing the obligations agreed to under the San Carlos I project, fall into two categories: (a) The two major municipal utilities, EEEB and EPM, which own 50% of ISA shares; and (b) The three National Government utilities, CVC, ICEL and CORELCA, which together with their subsidiaries, own the balance.  - 16 - 2.14 EEEB and EPM, the municipal utilities, have been generally success- full and relatively well-managed. Both serve concentrated urban markets in Colombia's two largest urban areas and have access to low-cost sources of power. In 1974-75, EPM encountered some difficulties as a result of political interference in management and both utilities' finances were adversely affected by low power rates. These problems have now been corrected, and EEEB and EPM's performance is expected to continue to improve. The other three major shareholders of ISA have in the past been less successful than EEEB and EPM as a result of the less affluent markets they serve and the complexity of their organizations. 2.15 CVC is an autonomous corporation which, together with other regional development corporations, reports to NPD. It is responsible for multipurpose development of the Cauca Valley. It is active in the fields of power, coal mining, irrigation, rural development and hotel operation. The largest city in the Cauca Valley, Cali, is served by a municipally-owned utility, EMCALI. Most of the other important communities in the area are served by CVC directly or through 26 subsidiaries. CVC owns 65% of the shares of CHIDRAL, the principal bulk power supplier in the area; the balance of the shares are owned by EMCALI and the Municipality of Cali. CVC and EMCALI have agreed to set up a new regional power company to take charge of power generation and transmission in the Cauca Valley. They have expressed their intention of consulting their creditors (among which the Bank is included as a result of its early power loans to CVC and CHIDRAL - see Annex 1.1 - and its more recent loans to.EMCALI for water supply: 682-CO and 1523-CO in 1970 and 1978, respectively). 2.16 ICEL is a government institute reporting to the Ministry of Mines and Energy. Through 11 subsidiaries, ICEL is responsible for power development in most of the country, with the exception of the areas covered by CVC, CORELCA and the various municipal utilities. ICEL's subsidiaries are expected to become the major users of the output of the San Carlos I and II projects. To enhance their efficiency, ICEL under the San Carlos I project agreed to take all necessary action to strengthen the management, planning, operations and finances of its subsidiaries and to formulate an improvement program. ICEL's central staff is conducting a study of at least five of its subsidiaries which will be presented to the Bank, together with its proposals for implementa- tion, by March 31, 1980. Implementation of the proposals, with any modifications resulting from the comments of the Bank is expected to be completed by December 31, 1981. 2.17 The Bank has recognized that, although little is known about the technical and financial situation of ICEL and its subsidiaries, the manpower required to obtain the relevant data would be prohibitive at this stage. Furthermore, as ICEL's incremental market would be largely among the lower-income rural population, the conclusions of such investiga- tion have been judged unlikely to uncover significant possibilities for increasing the sector's overall financial viability. Thus, the Government undertook to cover ICEL's contributions to ISA for the San Carlos I project in the event the company would be unable to make timely payments.  - 17 - In the interim, ICEL has agreed to provide available financial informa- tion to the Bank 1/, which is expected to provide a somewhat fuller picture of the power sector but would not be sufficient basis for determining ICEL's capacity to meet its financial commitments to ISA, including power purchases (estimated at 45% of the San Carlos I and II output). Thus, assurances have been obtained from the Government that such commitments would be met timely, and the relevant undertaking under San Carlos I has been amended to include ICEL's commitment to ISA for purchase of power. 2.18 CORELCA is a government-owned corporation reporting to the Ministry of Mines and Energy. It is responsible for generation, bulk supply and the coordination of power development in Colombia's Atlantic Coast region. The newest of ISA's shareholders, it has been functioning since 1972 and in 1975 took over ICEL's controlling interest in the 7 local utilities serving the area. In order to increase its effectiveness in handling its rapidly growing operations, under the San Carlos I project, CORELCA has agreed to strengthen its management and finances. To this end, it would carry out a study with the assistance of consultants acting under terms of reference acceptable to the Bank. The terms of reference for this study, for which proposals were received in early October 1979, discussed with CORELCA. As a result, under the proposed loan, the study has been extended to also include CORELCA's 3 largest subsidiaries. CORELCA would furnish for comments, by December 31, 1979, to the Government and the Bank, the conclusions of the study related to CORELCA itself and by June 30, 1980 the conclusions related to the subsidiaries, together with its proposals for implementation. By March 31, 1981, CORELCA would carry out a program with respect to its own improvements, and by September 30, 1981, with respect to improvements of the subsidiaries, all based on its proposals and the Government's and the Bank's comments thereon. 3. THE POWER MARKET Historic 3.01 In 1977, total electricity requirements in the country were about 15.3 TWh 2/. Of this, the Central Market system (serving the Pacific Coast and the interior), through the main utilities ISA, EEEB, EPM, EMCALI and various subsidiaries of CVC and ICEL, accounted for about 79% (12.0 TWh); the Atlantic Coast system (CORELCA and subsidiaries) about 14% (about 2.2 TWh); and the self producers about 7% (1.1 TWh). 1/ ISA, on behalf of the Bank, is presently executing a preliminary review of ICEL's investment program, operations, and finances. 2/ Estimated by ISA. Although ICEL annually prepares a statistical year book for the sector, not all production is included due to lack of data and the information given is sometimes at variance with data obtained by ISA directly and reflected in the San Carlos I appraisal report; for this report, ISA amended the San Carlos I data accordingly.  - 18- 3.02 The overall 1972-77 power data for ISA's shareholders (Annex 3.1) is summarized as follows: Unadjusted Average 1972 1974 1977 Growth Generation (Gross) (GWh) 9,380 10,938 14,208 8.7 Maximum demand (MW) 1,810 2,165 2,737 8.6 Sales (total) (GWh) 7,600 (100%) 9,179 11,343 (100%) 8.3 Residential 2,981 (39%) 3,777 4,803 (42%) 10.0 Commercial 942 (12%) 1,214 1,545 (14%) 10.4 Industrial 2,628 (35%) 3,139 3,708 (33%) 7.1 Others 1,049 (14%) 1,049 1,289 (11%) 4.2 Losses (%) 1/ 19.0 16.1 20.1 Over 1971-1977 the public sector's growth rate of electricity production (adjusted to reflect curtailments in 1977, see para. 3.03), was about 9.8% compared with a GNP growth rate of 6%/a. Growth of sales, which averaged 9.5%/a, varied from 7.2%/a for the EPM system to 11% for EEEB's system. The pattern of supply and demand has not changed materially: the share of each system in the market has hardly varied. Commerce and industry together had the same share in 1977 as in 1972; residential consumption increased by 3 percentage points while "Others" declined by 3 percentage points. The rather large difference in the 5-year growth pattern of generation compared with sales appears to be due to the increase in losses in 1977. In view of the importance of reducing losses to a minimum, ISA has undertaken, under the San Carlos I loan, a study of the nature, size and occurrence of losses in its own system and those of its shareholders (1.11). The study is expected to make recommendations for reduction of losses and (if required) improved metering systems. 3.03 During late 1976 and early 1977 supply was seriously rationed (up to 10% of requirements could not be met during the 5-month dry season depending on the supply area) in the Central Interconnected System, parti- cularly in the areas served by CVC and CHEC. The 1976/77 rainy season was unusually dry, and commissioning of Chivor I hydro and the thermal plant at Barranca were delayed. Supply was also rationed in the Atlantic system due to the gas shortage resulting from delayed completion of a gas pipeline to Barranquilla. 1/ Including unaccounted energy.  - 19 - Forecasts 3.04 Projected demand and energy requirements are based on ISA's detailed analysis of past consumption trends in the market served by each of its shareholders and on a study of the correlation between power sector growth and growth of GNP at rates of 6%, 6.5% and 7%, adjusted for large expected consumers in the various regions. From 1981 onward the Central and Atlantic systems are considered as integrated in view of the planned completion of the 500-kV Interconnection Project. ISA is presently studying, with the assistance of consultants, the application of a multiple regression model reflecting social and economic factors closely correlated with growth of electricity. 3.05 The 1977-85 electricity requirements in the interconnected system are expected to grow at an average of 10.6%/a (over the adjusted 1977 figures) in accordance with historic trends. As a result (Annex 3.2), gross energy requirements of the systems would be the following: Year EEEB EPM CVC ICEL CORELCA TOTAL 1/ Coincident --------- - ----------------( GWh) --- - -- ------------ - Maximum Demand (MW) 1977 2/ 3,965 3,196 2,030 2,627 2,190 14,008 2,737 1978 4,388 3,819 2,367 3,665 2,431 16,660 3,182 1980 5,320 4,467 2,812 4,805 3,262 20,666 3,925 1983 7,073 5,733 3,600 6,167 5,010 27,583 5,182 1985 8,559 6,684 4,246 7,337 6,222 33,048 6,246 This forecast, which is about equal to the forecast made in 1977 for San Carlos I, appears reasonable, except that ICEL and CORELCA's average growth rates appear high at almost 13%/a. As a result of the ongoing studies for these systems (2.16; 2.18) those rates may be adjusted downward in the future. Balances of Capacities and Energies 3.06 In order to meet the forecast power requirements in the national interconnected system by 1985, about 4,500 MW in effective generating capacity would have to be added to the 3,440 MW available at the end of 1977. The 1977-85 balances for energies and capacities are shown in Annex 3.3 for average water availability. Summarized, they show the follow- ing: 1/ The differences between these totals and the total generation shown in Annex 3.1 represent the losses in ISA's system. 2/ Actual.  - 20 - 1977 1980 1983 1985 Requirements Maximum demand (MW) 2,737 3,925 5,182 6,246 Gross generation (TWh) 14.2 20.8 28.2 33.8 % Hydro 73 70 72 73 Z Thermal 27 30 28 27 Effective Capacities (MW) 3,440 3,803 6,873 7,994 % Hydro 75 71 77 77 % Thermal 25 29 23 23 Capacity Margin (MW/%) Central System 631/21 -243/-8 CORELCA System 37/9 101/14 Interconnected System 1,691/24 1,748/22 3.07 In the Central System, due to delays in plant construction, the capacity margin is expected to deteriorate until interconnection. The meeting of peak demand will be difficult (even if ICEL's requirements would remain below expectations - see para. 3.05) if any of the years through 1981 would be exceptionally dry and, in this event, depending on actual load growth, further emergency measures may be necessary (4.02). Until intercon- nection, CORELCA's situation will also be difficult if its forecast of peak demand materializes (3.05). However, its energy requirements (except during the time of the forecast peak) can probably be met. After interconnection the emergency works begun in 1978 (additional thermal plant and river diver- sions) would start to alleviate the situation by 1982, even if hydrological conditions are below average. With the advancement of the thermal plants Cerrajon II and Tasajero (4.02), the overall capacity margin would improve by 1983/84 to an adequate level of some 24%. ISA's simulation studies indicate that during 1982-85, the energy shortfalls would be small (1 in 20 years probability): Dry Year Shortage (GWh/%) 1982 67/0.2 1983 61/0.2 1984 7/- 1985 14/0.4 Some small unexpected delays in plant completion would not substantially affect supply conditions from 1982 onward. 3.08 With the commissioning of Chivor I (Loan 681-CO) in September 1977, ISA for the first time generated energy in the interconnected system. Its generation is expected to rise rapidly, from 1.0 TWh in 1977 to some 11 TWh in 1985, when it would meet about 33% of total requirements:  - 21 - 1978 1980 1981 1983 1985 TWh % TWh % TWh % TWh % TWh / ------Isolated ------ ---------Interconnected--------- Generation (TWh) ISA 3.0 18 3.2 15 4.0 17 9.4 33 11.2 33 EEEB 3.0 18 3.5 17 4.3 18 4.7 17 4.0 12 EPM 3.4 21 5.2 25 5.6 25 4.2 15 6.6 20 CVC-CHIDRAL 2.1 13 2.3 11 2.5 11 2.3 8 3.1 9 ICEL-CHEC 2.8 16 3.3 16 2.9 12 3.1 11 3.1 9 CORELCA 2.5 15 3.3 16 4.0 17 4.5 16 5.8 17 16.8 100 20.8 100 23.3 100 28.2 100 33.8 100 ISA's sales to its shareholders for 1977-85 are shown in Annex 3.2. 3.09 Under average hydrological conditions the energy to be transferred from the Central to the Atlantic system (i.e. the net energy to be sold by ISA to CORELCA) would be relatively small. However, actual transfers are expected to aggregate some 1.1-1.3 TWh by 1984/85, representing an average capacity of 125-150 MW, taking into account actual hydro conditions, least cost dispatch, and mutual assistance requirements.  - 22 - 4. THE NATIONAL DEVELOPMENT PROGRAM AND THE SAN CARLOS II POWER PROJECT The Program 4.01 National Development. The 620-MW second stage of San Carlos hydro plant and the 15 MW Calderas Hydro station form part of the 1978-85 national generation expansion program: Year of Commissioning Entity Location Type/l Capacity (MW) 1. Under Construction/2 1978 ICEL Barranca III S 66 CORELCA Ballenas GT 32 EPM Guatape II H 284 1979 ICEL Insula (extension) H 12 1980 CORELCA Barranquilla III/IV S 132 ISA Chivor II H 500 1981 CORELCA Cartagena III S 66 ISA Zipaquira (Termozipa) IV S 66 ICEL Paipa III S 66 1982 EEEB Mesitas (Loan 1628-CO) H 600 EPM Ayura H 19 ISA San Carlos I (Loan 1582-CO) H 620 1983 ISA Jaguas H 170 2,633 2. New Projects/3 1982 EPM Troneras (expansion) H 26 1983 EPM Guadelupe I (renewal) H 100 CORELCA Cerrejon I S 150 ISA San Carlos II H 620 ISA Calderas H 15 1984 CVC Salvajina H 180 EPM Guadalupe IV H 260 1985 ICEL Tasajero S 132 CORELCA Cerrejon II S 150 ISA Betania H 500 2,133 /1 Plant types: H-Hydro; GT-Gas Turbine; S-Steam. /2 Excludes several diversion works for increasing generation. /3 Feasibility study completed.  - 23 - 4.02 All of the above plants have been approved by ISA's board, except Betania. Not shown are river diversion works to increase generation, such as Chingaza (EAAB/EEEB), Pajarito, Nechi and Dolores (EPM) and Tunjita (ISA), and the 500-kV project (Loan 1583-CO) to interconnect the Central System (ISA) with the Atlantic System (CORELCA). Of the total, installed capacity of 4,766 MW (effective capacity about 4,500 MW, see para. 3.06) to be commis- sioned by 1985, ISA would construct 2,491 MW, or 52% in accordance with this plan. In view of a possible critical situation in 1980/81, earliest acquisi- tion of at least 150 MW in gas turbine capacity for the central system is under discussion in ISA's board and a decision is expected soon. Similarly, in order to avoid possible shortages in 1983/84, a decision is expected to advance construction of thermal plant at Tasajero (ICEL) and Cerrejon (CORELCA) up to 2 years. 4.03 ISA Development. ISA's part of the 1978-85 development program, i.e., including future plant on which construction has to start before 1985, is expected to cost about US$3.6 billion in current prices (US$2.2 billion in end-1977 prices), excluding interest during construction. The program which is shown in Annex 4.1 is summarized, in current prices, in the table below, which also provides information on the incremental capacity and approximate incremental energy capability resulting from the program by the end of 1983. Construction Cost 1/ Incremental Local Foreign Total Capacity GWh --------MUS$-------- MW Chivor II 32 86 118 500 145 Tunjita river diversion (Chivor) 24 55 79 - 800 San Carlos I (revised) 172 183 355 620 3,582 San Carlos II 34 94 128 620 648 Calderas 9 13 22 15 430 2/ Jaguas 68 82 150 170 2,340 2/ Termozipa IV 17 24 41 66 345 500-kV Interconnection 44 71 115 - - Sub-total 400 608 1,008 1,991 8,290 General Plant 10 - 10 Engineering 96 23 119 Future plant 1,127 1,348 2,475 1,633 1,979 3,612 The total cost of plant to be completed by 1983, including an allocation of MUS$50, assumed for engineering and studies related to the program, averages about US$530/kW, which is low (in end 1977 prices it would be about US$410/kW). 1/ Generation plant include related transmission facilities. 2/ Includes the additional generation at San Carlos (6.01).  - 24 - The Project 4.04 The San Carlos hydro plant is located in northwest Colombia at the confluence of the San Carlos and Guatape rivers, downstream of the outlet of EPM's existing Guatape Hydro plant (Annex 4.2) at a distance of 150 km east from the city of Medellin by a road of which 60 km are paved; the remaining 90 km correspond to a serviceable all weather road suitable for weights up to 60 tons. The first phase of the San Carlos plant is being constructed in accor- dance with the implementation schedule agreed to under the San Carlos I loan. The work comprises the Punchina dam on the Guatape river, inlet and discharge tunnels and an underground power station suitable for ten 155 MW generating units in one cavern and their transformers in a second cavern. Four units will be installed during the first phase. All main civil work will be completed during the first phase (subject to the provisions of financing described in paragraph 4.06). The second phase, which is included in the proposed Project, would add 4 additional generating units (620 MW) and related facilities. The two remaining units would be installed when required for peaking purposes, which is not expected before 1985. The output of both Guatape and San Carlos would be regulated by the large Santa Rita reservoir (which was expanded under Loan 874-CO to EPM, with filling of the reservoir to the new level begun in May 1978). The second phase of San Carlos is required for peaking purposes and for additional generation related to the additional diversion of Nare river waters to the Guatape river through the Jaguas Hydro plant (to be completed at the same time as San Carlos II) which is being financed by IDB. In order to transmit the additional capacity and energy throughout the interconnected system, a second 230-kV line will be required between San Carlos and Medellin, and between Esmeralda and Yumbo for supply to the area of Cali in the south, both of which form part of the Project. In addition the Project would include a study to identify the requirements for least cost dispatching and training in the interconnected system, and a study and training program for other staff. 4.05 The possibility of diverting the Calderas and Tafetanes rivers (5-6 m3/s) to the San Carlos river was already identified in 1973 in the San Carlos feasibility study. The feasibility study shows that total genera- tion in a small (15 MW) plant near the top of the San Carlos reservoir and at the San Carlos plant would be about 345 GWh/a of which 255 GWh pertain to the Calderas river diversion and 90 GWh to the Tafetanes river diversion. The Calderas facilities would also be financed by the loan in view of its economic benefits. Its cost (MUS$22) would be about 5% of the cost of San Carlos, while increasing the San Carlos generation by about 6% (excluding Jaguas' contribution). The Tafetanes diversion, to be completed at a later date, also appears justified since its cost (MUS$5.5) would be about 25% of the cost of Calderas, while generation would increase by 90 GWh or 35% of the Calderas contribution. Consequently, the Calderas plant has been designed for the combined flow to be diverted from both rivers to the San Carlos reservoir at an extra cost of about MUS$1.5. 4.06 The San Carlos I Project (1582-CO). International competitive bidding for the San Carlos I civil works resulted in lower costs, particularly  - 25 - foreign, than estimated during appraisal; current estimates of internal infla- tion are also lower than the projections used for San Carlos 1. Thus, sub- stantial savings would be realized under that loan. The original and adjusted estimates (Annex 4.3) are summarized below: Original Estimate Revised Estimate 1/ Local Foreign Total Local Foreign Total -------MUS $ -mus$ --------- Engineering 15.0 1.7 16.7 14.4 1.7 16.1 Civil Work 59.7 76.5 136.2 74.0 49.0 123.0 Electro-mechanical equipment 7.0 48.7 55.7 6.4 48.4 54.8 Transmission 6.4 15.2 21.6 6.1 17.3 23.4 Contingencies 75.2 61.8 114.1 28.5 37.6 66.1 Total project cost 163.3 203.9 367.2 129.4 154.0 283.4 Loan 1582-CO was made to ISA for the amount of MUS$126 to cover the foreign cost of the San Carlos I underground works (the dam is being financed by IDB), miscellaneous hydro-mechanical equipment, transmission, and interest during construction. However, in accordance with the revised estimate, only some MUS$90 would be required from the loan account. Thus, loan 1582-CO would cover the foreign cost of the underground works required for San Carlos II (i.e., the second power tunnel). This would avoid cancellation of some MUS$36 and the loan for San Carlos II has been adjusted accordingly. Both loans combined would thus finance the works for San Carlos I and II in two tranches, as originally envisioned. The presently estimated cost of San Carlos 1, including the underground work for San Carlos II takes into account the contractor's discount of 10% on the underground works contract for San Carlos II, provided that ISA accepts, as anticipated, the option within 16 months after the signing of the base contract for San Carlos I (May 1978). 4.07 Objectives. The Bank would continue promoting the sector and project objectives supported under San Carlos I: (a) to enhance ISA's role as the agency, operating throughout the country on behalf of the main utilities, to harness the larger hydro potentials for meeting future power requirements; (b) to coordinate through ISA sound overall sectoral development; (c) through ISA, as dispatch agency, to enable the efficient and economic operation of the interconnected system, including the CORELCA System where, after completion of the 500-kV interconnection project presently in execution, part of the expensive thermal generation would be replaced by hydro generation available in the Central System; and 1/ The decrease is substantially due to lower assumptions for both local and foreign inflation. Local inflation averaged 23.6% in 1975, 20.0% in 1976 and 34.7% in 1977, and is expected to average about 18% in 1978, decreasing to 12% by 1981.  - 26 - (d) to encourage the financial viability of the various entities in the sector, and to institute operational policies (including administration and accounting) designed to increase efficiency and allow the monitoring of performance on a common basis, through- out the sector. 4.08 Description. The San Carlos plant will use an average discharge of 143 m3/s (Annex 4.2) supplied by the Guatape river and the flows diverted from the Nare river, through the Guatape and Jaguas hydro stations, and from the Calderas river through the Calderas hydro station. The project comprises: San Carlos II (a) Four 6-jet vertical shaft Pelton turbines operating under a gross head of 595 m, with single runner, 300 rpm and four vertical shaft 60 Hz generators rated 183 MVA at 80 C and 85% power factor; (b) Two 3-phase banks of single-phase transformers, each 122 MVA, 16/230 kV, water-cooled. Two generating sets will be connected to each bank; (c) Electrical equipment related to the 4 additional generators includ- ing control boards, auxiliary panels, cables, and expansion of the San Carlos switchyard; (d) A 90 km long 230-kV double circuit transmission line between the San Carlos substation and substation Alcoa South at Medellin and expansion of both substations; and (e) A 200 km long 230-kV double circuit transmission line between substations Esmeralda and Yumbo (Cali) and expansion of both substations. Calderas (a) A concrete gravity type dam 22 m high, impounding a small reservoir for dayly regulation an intake structure feeding directly into a vertical pressure tunnel, concrete lined, 140 m deep and an inclined pressure tunnel 3.2 km long, unlined except for the last 500 m which will be steel lined, with a crosssection of 5.9 m2; and (b) A surface power station with two Francis type turbine - generators of 7.7 MW each, operating at a gross head of 210 m and ancillary equipment including transformers to connect the station to the existing 44-kV line San Carlos-Granada at a distance of 1 km. Studies (a) A study for operating the interconnected system at least cost, recommendations for the preparation of a dispatch agreement, required computer programs, and training of dispatch personnel; and  - 27 - (b) A study of ISA's manpower requirements and execution of a program of specialized training for ISA's professional staff. 4.09 Estimated Cost. The project is estimated to cost MUS$156.1, with a foreign component of MUS$110.5. The costs, which are detailed in Annex 4.4, are summarized as follows: Local Foreign Total Local Foreign Total ---------MCol$ - -MUS$-------- San Carlos II Engineering 383 53 436 10.1 1.4 11.5 Electrical/Mechanical Equipment 194 1,582 1,776 5.1 41.7 46.8 Transmission 300 859 1,159 7.9 22.6 30.5 Sub-Total 877 2,494 3,371 23.1 65.7 88.8 Calderas Engineering 25 35 60 0.6 0.8 1.4 Civil works 173 173 346 4.1 4.1 8.2 Equipment 79 178 257 1.9 4.3 6.2 Sub-Total 277 386 663 6.6 9.2 15.8 Studies Sub-Total 36 132 168 0.7 2.9 3.6 Contingencies Physical 102 303 405 2.6 7.8 10.4 Price 922 2,090 3,012 12.6 24.9 37.5 Sub-Total 1,024 2,393 3,417 15.2 32.7 47.9 Total Project Cost 2,214 5,405 7,619 45.6 110.5 156.1 4.10 The cost estimate is based largely on prices for the main contracts already awarded for San Carlos I, (civil works) or already evaluated (turbines and generators). The physical contingencies for local cost have been estimated to average about 12% for San Carlos II and 18% for Calderas; for foreign cost, 10% for San Carlos II and 15% for Calderas. These percentages are considered appropriate in view of the advanced status of the design and contracting (including options, see paras 4.06 and 4.12) of San Carlos and the preliminary design stage of Calderas. The estimated base cost is in prices calculated for early 1978, to which a contingency has been added for inflation as follows: local cost was assumed to decrease from 18% in 1978 to 12% in 1981, remaining constant thereafter; foreign cost 7% in 1978, 6.5% in 1979 and 6% thereafter. The average exchange rate (Col$39.10 per US$ in 1978) was assumed to increase to Col$60.51 by 1985. 4.11 Financing. A Bank loan of MUS$72 is proposed, representing 65% of the foreign exchange component of MUS$110.5 as follows:  - 28 - MUS$ San Carlos II 54*5 Penstock 10.5 Electro-mechanical equipment except turbine-generators 10.2 Transmission: Lines 22.1 Substations 11.7 Calderas 11.0 Civil works 5.9 Equipment 5.1 Engineering/Studies 6.5 Engineering 3.0 Studies 3*5 Total 72.0 4.12 Under bids made for the San Carlos I turbines and generators (for which the award is pending, awaiting Government agreement), ISA would have an option to acquire four additional units and obtain suppliers' credit financing amounting to about MUS$30.1. ISA's shareholders would finance the remaining foreign cost (MUS$8.4) comprising mainly the down payments on suppliers' credit financed items and price contingencies for these items not financed by suppliers. The local cost would be financed by equity contribu- tions and equity securities to be subscribed by ISA shareholders and internally generated funds. Engineering; Studies; Training 4.13 San Carlos II. With Bank agreement, ISA has retained the services of the Colombian consultants firm Integral for final design and supervision of construction of both San Carlos I and II. Integral has already engaged outside expertise for special4zed tasks during construction of San Carlos I and this policy will be continued for San Carlos II. The proposed loan would finance, similarly to San Carlos I, the foreign cost, or 50% of the total cost, of Integral's services, estimated at MUS$5. The estimated base cost of engineering services for San Carlos II is MUS$3.8-4.0. The consultants are paid on the basis of the cost of all personnel assigned from time to time to the project, including salary costs social benefits and a profit margin.  - 29 - Their present base salaries average about US$670/month. It is estimated that some 5,300 man.months of such services will be required. Super- vision of the underground work for the second tunnel (the civil works of which would be financed by Loan 1582-CO for San Carlos I, see para. 4.06) is included in this estimate. 4.14 Calderas. At the time of appraisal, only a prefeasibility study was available for Calderas. Since then, ISA has undertaken a crash program for surveys and has updated the feasibility study including the cost estimate. The Bank has engaged an expert geologist to evaluate the status of readiness for construction of Calderas. His findings were satisfactory and risks, within the assumed contingencies, considered minimal. Final design has been initiated and bid documents for the main civil works are expected to be issued by November 1979. The estimated foreign cost of the consultants services (which also are being provided by Integral) and surveys of about MUS$0.3 would be financed by the proposed loan. The total cost (about MUS$1.0) includes about 750 man.months in services as defined above for San Carlos II. 4.15 Transmission. ISA, with the assistance of its consultants, would design and supervise construction of the transmission lines to be financed by the loan within the scope of its continuing transmission expansion program. Because ISA already has considerable experience in this work, no difficulties are expected and no particular monitoring conditions are required. 4.16 Dispatch Study. A load dispatch center to be completed by 1981 and financed by IDB under its loan for Chivor II expansion, will now be located at Medellin. Although the system and its general operational objectives have been technically well-defined, ISA has no experience with operating a system as large as envisioned for the eighties, and the operation has not yet been studied in depth. The contract for the supply of power from Chivor (ISA's first power station) is limited to Chivor only and does not provide yet for an inter-regional power sale and purchase pool. Computer programs will have to be acquired (and modified to be applicable in the Colombian system) and developed for operating the system at least cost, to monitor power exchanges and operational data, institute a system of billing and sharing of benefits, etc. A dispatch agreement between the entities operating in the system, setting forth the responsibilities and the rights of the entities, on the subjects outlined above will have to be prepared. Operators will have to be trained within and outside Colombia. In order to prepare ISA for its role of national dispatch agency, the loan would finance a study for coordinated dispatch in the interconnected system as discussed above, including training, the cost of which is estimated at MUS$1.5. ISA would engage the services of consultants not later than December 31, 1979, under conditions and terms of reference acceptable to the Bank, which would be consulted regularly and timely on all major aspects of the study as it progresses. Proposals for the terms of reference are being discussed with ISA. The study and training would be completed by December 31, 1981. 4.17 Training of ISA's Staff. ISA's professional staff, numbering about 800, is supplemented by large numbers of consultant personnel, some of whom are providing nonspecialized services. At the same time, ISA has no  - 30 - plans to increase substantially its staff in order to take over work now executed by consultants. A preliminary study of the total manpower require- ments in the energy sector has been made, estimating that of the total of about 7,100 needed, some 4,100 will be employed in the power sector, implying greatly increased ISA responsibility for sector control. Although the universities graduate engineers in sufficient annual numbers to meet these needs, specialized graduate training in specific areas required by the sector, such as hydrology, soil and rock mechanics, geomorphology, seismology and ecology is not available locally. In view of the expected rapid growth of the sector, ISA's need for specialized staff is great, not only to enable it to adequately supervise the consultants, but to reduce gradually its reliance on outside services where economically justified. Total staff requirements, over the next three to four years, whether employed by ISA or by its consultants, are estimated at about 340 engineers -- although ISA has not yet decided what proportion of these staff should be employed by itself. The preliminary study, however, indicates the urgency of training in general and post-graduate studies in particular for selected ISA personnel. 4.18 As a first step towards assisting ISA to solve this problem within the limits of its absorbing capacity, the proposed loan, at an estimated cost of MUS$2, would finance: (a) a study of ISA's manpower requirements up to 1985. For this purpose, ISA would engage, by December 31, 1979, the services of expert consultants, under terms and conditions acceptable to the Bank, to complete the study by June 30, 1980 for review and discussion with the Bank. The study, which would also review the present capability of Colombia's educational programs to meet the requirements of the power sector, would make recommendations for (i) the creation, organization and staffing of a manpower and training department in ISA; (ii) a training program to be imple- mented for new and existing staff in Colombia and abroad, clearly stating the objectives, numbers and specializations of staff required, together with an appropriate time-scale; (iii) identify programs and resources, through which such training can be obtained most efficiently; (iv) identify existing staff capable of absorbing such training in each specialty; (v) provide job descriptions (and minimum educational requirements) for staff to be recruited for further training in specific specializations; and (vi) conditions of employment, including the long-term contracting of trainees, plus an evaluation of all training programs both during and at completion; and (b) the implementation of an agreed training program to be completed by June 30, 1983; the proposed loan should finance 50% of the cost of training in Colombia and 100% of the foreign cost of training elsewhere. 4.19 The cost estimate is based on the assumption that 60-70 staff of ISA would be trained outside Colombia for a period of two years at an annual cost of US$10,000/man.year, about MUS$0.5 would be spent in Colombia for training and MUS$0.2 would be required for the consultant study. A further  - 31 - objective is to ensure that ISA's manpower and training department would be capable, in the future, of developing further recruitment and training programs. 4.20 Retroactive Financing. Consulting services for San Carlos were all charged to San Carlos I until September 31, 1978 and, during appraisal, it was agreed that services for San Carlos I and II would be separated administra- tively. For this reason, retroactive financing is proposed, not exceeding MUS$l for engineering services incurred since October 1, 1978 for San Carlos II and Calderas. 4.21 Implementation Schedule. The construction schedule of the San Carlos II Project would largely overlap construction of the San Carlos I Project (completion mid-1982) and works are expected to be completed by mid-1984. The project implementation schedule, of which key dates are shown in Annex 4.4, would be used to monitor progress during the construction period; this schedule also covers the transmission lines and the studies. 4.22 Procurement. Procurement of goods and services to be financed by the proposed loan (other than consulting services and training) would be through international competitive bidding under Bank guidelines for procurement. Colombian manufacturers would receive a preference of 15%, or applicable duties, whichever is lower, for purposes of bid evaluation. The cost estimate assumes that local manufacturers would supply conductors, towers and some miscellaneous electromechanical equipment, with an estimated cost of about MUS$10-12, the ex-factory cost (net of taxes) of which would be financed by the loan. 4.23 Disbursements. Funds from the proposed loan would finance (a) 100% of the foreign expenditures for imported equipment, materials and ancillary works and services; (b) 100% of the foreign cost of civil works for Calderas; (c) the foreign expenditures for consultant's services or 50% of total; (d) 50% of the cost of surveys and drilling, (e) 94% of the ex-factory cost of locally produced materials and equipment, and (f) 50% of the cost of training in Colombia and 100% of the foreign cost of training abroad. Annex 4.5 shows the estimated loan disbursements. The first unit (i.e. the fifth in the San Carlos Power Station) is expected to be operational in September 1983 and the project would be completed by June 30, 1984. The closing date would be June 30, 1985 to allow for payment of retention monies and some unforeseen delays. Environmental Aspects 4.24 The agreements reached under San Carlos I, with respect to protection of the environment, have been repeated in the agreements for the proposed loan: (a) Taking of all necessary measures to ensure the project is carried out with due regard to ecological and environmental factors; (b) Evacuation of the areas of the San Carlos work areas to be completed by June 30, 1979; (c) Acquisition of all land and rights in respect of land required for the carrying out of the San Carlos project by December 31, 1979;  - 32 - (d) Monitoring and inspection of dams at least once a year by qualified and experienced experts; and (e) Preparation of a program for rational use of the project basins by December 31, 1980 and establishment of a unit by December 31, 1984, for carrying out the program. 4.25 In addition to the above, ISA has agreed to carry out, by December 31, 1980, a plan, satisfactory to the Bank, for the evacuation of the areas where the works included in the San Carlos II project will be carried out. By the same date it would acquire all lands and rights in these areas and by December 31, 1981 all other lands and rights in respect of land required for the carrying out of the project. Project Risks 4.26 Because the project, except for the transmission lines, cover substantially the San Carlos area, the physical risks are practically equal to those of the San Carlos I project, which are summarized as follows: (a) Climatic conditions. The main effect of climatic conditions on the project is that progress largely depends on completion of specific items (e.g. cofferdams) during the five months dry season in order to avoid interruption of operations during floods. Work has progressed as scheduled and no major difficulties are expected in this respect. (b) Geology. The facilities are, for the greater part, located on or in sound igneous rocks and only a small portion of tunnelling would be done across fault zones. The first power tunnel will be concrete-lined throughout for protection against blasting in the second tunnel; the latter will be concrete-lined only to the extent necessary in view of rock conditions found and across fault zones. The surveys for the exact location of the powerhouse caverns have been completed and exploratory tunnels are being constructed for the length of the caverns to ascertain rock conditions more precisely, before blasting of the caverns is started. ISA has engaged the services of consultants to provide assistance during construction to monitor geological conditions and solve problems related to it; they are Soil and Rock Instrumentation of Boston, Dr. A. Merrit - a U.S. Engineering Geologist, Mr. J.L. Sherard of Bermuda - a dam consultant and Mr. W. Clyde - a U.S. Seismic Expert. (c) Seismicity. Although there are a number of faults in the area, only two of them are classified as probably active (although there is little evidence). The works have been designed for a seismic acceleration of 0.4 g (3.9 m/s2) with its epicenter in one of the faults and a spectrum to the October 1960 earthquake in Lima, Peru. The dam will be monitored continuously (4.24). Project File 4.27 Reference is made to Annex 4.7 for the contents of the Project File.  - 33 - 5. FINANCES Introduction 5.01 ISA depends on its shareholders to finance its operations through energy sales and service charges, and to finance the portion of its invest- ments not covered by loans through equity shares and securities contributions. Since its incorporation in 1967 and particularly during the period 1971-1977, ISA encountered major problems whenever its shareholders had financial diffi- culties (as a consequence of their low rates). Since January 1978 the finances of ISA and its shareholders have improved substantially as noted in paragraph 5.02 below. No financial difficulties are expected through 1985, the end of the forecast period provided that current application of adequate tariff policies are maintained, together with Government contributions on behalf of CORELCA and ICEL. ISA's Performance and Financial Position 5.02 During 1967-1978 ISA functioned in accordance with its original lylaws, which were based on the concept of sharing ISA's operating costs, debt service and local construction expenditures among its shareholders according to agreed formulae. The revenue covenants for IBRD loans 575-CO and 681-CO were consistent with those provisions. 1/ ISA's main financial problems during this period, particularly over 1971-77, resulted from slow payment by its shareholders for amounts owed; secondary problems stemmed from ISA's not including depreciation charges in the operating expenses recovered from its shareholders and the tendency of some shareholders to invest in ISA's bonds while allowing arrears to accumulate on accounts payable for transmission charges, energy and equity contributions. The improved financial performance of ISA and its shareholders since early 1978 resulted from regular rate increases of up to 2.2% per month which have been sanctioned by JNT to remain in effect through 1980. Through 1985, the end of the project forecast period, no financial difficulties are anticipated provided that current tariff policies are maintained and Government contributions to ISA on behalf of ICEL and CORELCA are made in time. In support of these policies, the agreements reached with ISA and its shareholders, under the San Carlos I loan with respect to investments and financial arrangements, have been repeated in the agreements for the proposed San Carlos II loan. The prin- cipal undertakings of ISA and its shareholders are the following: - No generating plant would be constructed exceeding 200 MW (ISA) and 100 MW (shareholders) unless economically justified; additionally ISA would not undertake without Bank concurrence any further project costing in excess of 2.5% of the value of its net fixed assets; 1/ Except that they required that ISA earn a 9% rate of return on generating assets. However, ISA's first generating plant, Chivor I, did not commence operations until mid-1977 (at which time minimum levels of performance agreed to under San Carlos I were being discussed).  - 34 - The shareholders would not transfer any asset or take any action that would interfere with compliance with their obligations to ISA; The shareholders would: (i) reimburse ISA for the cost of borrowing due to late payment of amounts due; (ii) give priority ranking to the various types of payments to be made to ISA; (iii) make scheduled payments to ISA of arrears for depreciation; (iv) make payments to ISA within 60 days of billing. Similarly, the Government reconfirmed that it would make available to CVC, CORELCA and ICEL any funds they may require to fulfill their financial obligations to ISA, and assist EEEB and EPM in securing any loans they may require to comply with their financial obligations to ISA. Since September 1978, the above shareholders commitments have been met satisfactorily with the exception of ICEL. As of December 31, 1978, ICEL owed for energy purchases and transmission charges MCol$426 (equivalent to 260 days of billings, or 59% of the total owed to ISA by its shareholders). Because ICEL's payments to ISA for energy purchases are credited to the oldest outstanding accounts, ICEL, as of March 31, 1979, was in arrears for its 1979 purchases. Since then ICEL has improved its rate of payments to ISA and, through the Colombian Government, has committed itself to become up to date in its 1979 payments to ISA by July 15, 1979. By the same date it would present to the Bank a government approved schedule of payments to liquidate its end-1978 arrears to ISA. Regarding payments for shares and securities subscriptions (excluding reimbursement of the debt service of the FDE loan - see para. 5.13 - which will be collected during 1979), as of December 31, 1978, ICEL is up to date and CORELCA owes only some MUS$0.25. 5.03 The recent amendments of ISA's bylaws specify that ISA will earn a reasonable rate of return on its revalued transmission and generating assets. Also, the subsequently signed agreement for the sale and exchange of energy from the Chivor I plant stipulates that tariff rates be based on a 9% rate of return on revalued assets. These are major improvements over the previous procedure, since it allows ISA to generate funds internally for future expansion (5.07). 5.04 ISA's long-term capitalization (Annex 5.2) reflects the recently amended provisions of its bylaws which require that a high proportion of the foreign cost of its projects be financed by debt and a high proportion of local costs be financed by equity (previously by debt also). As of December 31, 1977, ISA's capitalization was:  - 35 - MCol$ 1/ % 1/ % 2/ Capital and reserves 1,790 10 16 Equity securities 2,047 11 19 Capital revaluation 1/ 6,905 39 - Government contributions 10 - Total Equity 10,752 60 35 Long Term Debt: IBRD (575-CO, 681-CO) 2,830 16 26 IDB 2,320 13 21 Other foreign 870 5 8 Other local 1,082 6 10 Total Long Term Debt 7,102 40 65 Total Capitalization 17,854 100 100 1/ This is in accordance with the agreements reached under San Carlos I for calculation of the rate of return on fully revalued net assets in operation: Capital revaluation=full revaluation of gross assets using the national consumer price index for Colombian workers less revalued accumulated depreciation less revalued foreign currency liabilities calculated at year end exchange rates. 2/ As presently allowed by Colombian law these percentages, which reflect ISA's official audited figures, include only a partial revaluation of assets resulting from the yearly revaluation of ISA's foreign currency liabilities. It excludes therefore the capital revaluation mentioned in 1/ above. ISA's relatively low 40/60 debt to equity ratio takes into account the full revaluation of its assets. An additional improvement in ISA's capital structure has resulted from the 1977 change in the characteristics of share- holders' bonds features whereby they are now almost equivalent to common stock and could be more aptly called "equity securities" 1/. Of ISA's long term debt, 72% pertains to the Bank and IDB loans. Because ISA started generating its own power only in the second half of 1977 its debt service coverage ratio for that year was only 0.85. Preliminary results for 1978 show an improved rate of about 2.18. The favorable structure of ISA's debt and the planned rate increases through 1980 should allow it to obtain the additional debt financing which it will need from commercial sources for its investment program (5.08). As to equity financing, ISA's bylaws require each shareholder to make equity contributions in the form of shares and equity securities to cover the costs (mainly local) which cannot be obtained from other sources. While share 1/ The differences from common stock are: (a) they have no voting rights and (b) they rank before common stock and after current and long-term liabilities upon liquidation of the company.  - 36 - costs (mainly local) which cannot be obtained from other sources. While share contributions are proportional to shareholdings, equity security contributions are proportional to each shareholder's agreed participation in the output of each plant (5.09) with the proviso that share contributions cannot be less than 20% of the total required from the shareholders to fund any given project. 5.05 It should be observed that ISA's official financial statements understates its equity (5.04) because, for accounting purposes, Colombian legislation allows revaluation of assets only to offset exchange rate adjust- ments on external borrowings. Nevertheless, for the purpose of financial performance monitoring under the San Carlos I Project, ISA, EEEB, EPM, CORELCA and CVC/CHIDRAL agreed to revalue fully their assets yearly and to present to the Bank annually a report on such revaluation. The first reports for 1977 were presented in December 1978. These agreements have been repeated under the San Carlos II loan (5.27). Financing Plan 5.06 ISA's 1978-1985 investment program (Chapter 4) includes: (a) the Project (San Carlos II); (b) the completion of Chivor I and II, San Carlos I, 500 kV Interconnection, Termozipa IV, Jaguas, various river diversions; and (c) future expansion in generating facilities required by the national inter- connected system and the corresponding transmission expansion. ISA's projected sources and applications of funds up to 1984, year of completion of disburse- ments of the San Carlos II loan, are shown in Annex 5.3. The summarized financing plan for this period is:  - 37 - 1978 - 1984 MCol$ Mus $ % Financial Requirements Construction Project: San Carlos II 7,746 156.1 5.2 Jaguas 7,347 149.5 5.0 Interconnection 12,459 250.4 8.4 Ongoing works 24,407 550.1 18.5 Future works 80,310 1,478.0 49.7 Other studies and General Plant 4,547 93.4 3.2 Interest capitalized 9,821 193.5 6.6 Total Construction 146.637 2,871.0 96.6 Fondo de Desarrollo Debt Service 1/ 2,438 52.1 1.7 Increase in working capital 2,582 52.8 1.7 TOTAL 151,657 2,975.9 100.0 Sources Internal cash generation 37,459 732.0 24.6 Less: Net debt service 2/ 18,642 360.1 12.1 ISA's net internal cash generation 18,817 371.9 12.5 Shareholders'contributions w/own funds 3/ 30,860 600.8 20.2 Total power sector sources 49,677 972.7 32.7 Government Contributions: For the Interconnection project 12,459 250.4 8.4 Other contributions 4/ 20,736 401.9 13.5 Total Government Contributions 33,195 652.3 21.9 Borrowings: IBRD San Carlos II loan 2/ 3,589 72.0 2.4 Other loans related to San Carlos II 1,901 38.1 1.2 Jaguas 5,022 100.0 3.4 Existing loans 12,904 291.6 9.8 Future loans (incl. for studies) 45,369 849.2 28.6 Total Borrowings 68,785 1,350.9 45.4 TOTAL: 151,657 2,975.9 100.0 1/ See para. 5.13. 2/ Excludes interest capitalized. 3/ Includes capital and securities contributions. 4/ Contributions to CORELCA and ICEL to cover their contributions to ISA (capital and securities). 5.07 During the period, ISA's net internal cash generation represents 12.5. of the investment program. This is low, but acceptable when viewed in conjunction with the shareholders' contribution of 20.2% towards ISA's expansion program, the latter representing an important consumers' contribution of the main cities of Bogota, Medellin and Cali through EEEB, EPM and CVC.  - 38 - The annual amounts contributed by each shareholder in the form of equity and equity securities are shown in Annex 5.6. Since ISA will not be in a position to pay cash dividends, the shareholders agreed to reinvest any dividend on shares and securities during construction of San Carlos I and thereafter unless ISA would meet a debt service test of 1.5. This agreement has been repeated under the San Carlos II loan agreement, taking into account that all shareholders' bonds have been converted to equity securities (5.04). 5.08 In line with ISA's bylaws, the financing plan assumes that borrow- ings would cover most of the foreign cost of San Carlos II (4.11). The terms assumed are: (a) San Carlos II IBRD Loan: interest 7.5%, 1/ maturity 17 years, including 4 years of grace; (b) Tokai Bank (through IDB); interest 9.0%, maturity 10 years, including 3-1/2 years of grace; and (c) supplier's credits; interest 8.5%, maturity 12 years, including 4 years of grace. The effectiveness of the Bank loan for the San Carlos II Project would be conditional on receipt of evidence that ISA has made satisfactory arrange- ments for: (i) the balance of the foreign exchange requirements of the San Carlos II Project; and (ii) the foreign exchange requirements of the Jaguas project. 5.09 Under San Carlos I, the shareholders agreed to guarantee principal and interest on the Bank loan in proportion to their shareholding and to cover the portion of the foreign costs of the project not covered by other long term financing, as well as local costs which exceed ISA's net internal cash generation, in the following proportions: EEEB, 19%; EPM, 22%; CVC, 16%; ICEL, 30% and CORELCA, 13%. At least 77% of these contributions would be in the form of shares and the rest in the form of equity securities. The same agree- ment has been made for San Carlos II. These same proportions also apply to the Jaguas project to be financed by IDB. Future Finances 5.10 ISA's forecast financial statements 1978-85 (Annexes 5.1, 5.2 and 5.3), and financial indicators (Annex 5.4) are based on the assumption that ISA operates on a sound commercial basis ensuring an adequate rate of return. 1/ The impact on the financial results of this assumption, as compared to the 7.9% interest rate currently charged on Bank, loans, is negligible as the project represents only some 5% of ISA', investment program over the period.  - 39 - Projected sales are based on a forecast (3.04) which reflects average hydro- logical conditions. The supply of secondary hydroenergy, therefore, has not been taken into account which, under favorable hydrological conditions, can substitute for thermal generation, particularly in the CORELCA system once the 500-kV line becomes operational in 1982. The forecasts are based on the purchase of all of ISA's output as provided by the April 1978 sales agreement which specifies the amounts of capacity and energy to be purchased in each hydro year by each shareholder on a take-or-pay basis. This sales agreement, finalizing of which was a condition for San Carlos I loan effectiveness, will be in force until the expected entry into operation of Chivor II in 1980. Thereafter, modifications would be introduced to cover forecast sales through the commissioning of San Carlos I in 1983. Further modifications will be introduced as new plants come on stream. 5.11 To improve its internal cash generation and sector self-financing ratio in relation to the expansion program, ISA also projects that from 1978 its internally-generated cash, together with shareholders' contributions would cover: (a) the local cost of all projects for which financing had not been secured prior to December 31, 1978; (b) the portion of equipment costs of all such projects not financed by loans or suppliers' credits; and (c) interest during construction on all new loans negotiated after December 31, 1978. In line with the agreements reached under San Carlos I, which have been repeated for the San Carlos II loan, the above financing policy would apply at any time that ISA would fail to meet the covenanted 1.5 debt service test when planning to incurr new debt. Although this arrangement would not provide ISA with sufficient debt service coverage in 1982 and 1985 (5.12, 5.13), it would provide a mechanism for substantial improvement of ISA's liquidity. 5.12 ISA's projected rates of return (Annex 5.4) are in line with the values agreed under the San Carlos I and 500 kV projects. With respect to the annual debt service coverage ratio, however, ISA's finances show two distinct periods: (a) The first period, 1978-1984, shows overall satisfactory results except for 1982, in which debt service coverage drops to 1.36 because ISA assumes no tariff increase for that year since such increase would not be required to meet the agreed rate of return. During this period, the San Carlos I and II and Jaguas projects become operational in 1982 and 1983, while the construction begins on other projects in ISA's large investment program (4.01).  - 40 - (b) The second period appears to begin in 1985 with a substantial drop in the coverage ratio to 1.02 due to the increase in debt service without a corresponding increase in revenues. This is caused by the time lag between the 4 year average grace periods assumed in future loans and the up to 6 years construction periods required for new plants. Thus, while difficulties are not expected in maintaining a minimum annual coverage ratio of 1.5 until San Carlos II is completed in 1984. a similar statement cannot be made regarding 1985 without analyzing ISA's finances at least until 1990, a task which would be undertaken during supervision or preparation of possible future Bank loans. In the meantime, wle ISA should continue to achieve rates of return equivalent to those agreed under San Carlos I (5.14), confirmation has been obtained that it would not, without Bank concurrence, incur further long-term debt unless it would meet a debt service test of at least 1.5 as agreed under San Carlos I. 5.13 ISA's projected annual debt service coverage ratio dces not take account of the debt service related to three loans obtained from the Fondo de Desarrollo Electrico (FDE) in 1977/78. The proceeds of these loans (MCol$ 1,453) were applied to refinance the external debt servIce payments and to cover foreign cost of Chivor I (overruns) and Chivor IlL According to ISA's statutes, such application should have been covered by shareholder contributions. The FDE refinancing was used in 1977 because of the shareholders' financial difficulties, and in 1978 because of FDE's relatively soft lending terms. Debt service associated with the FDE loans is not included in ISA's debt service ratio calculation because ISA expects to obtain full reimburse- ment from its shareholders, as reflected in the financial projections. This assumption is in line with the shareholders' obligations under ISA's bylaws. 5.14 As a negotiating compromise under San Carlos I, two different sets of rates of return were agreed, one based on ISA's generation and transmis- sion assets except 500 kV, the other on the 500-kV assets. Since then, ISA's attitude has become more favorable toward the Bank's recommendation that a common rate of return would be advantageous because it would permit optimum operation of the system based upon equitable distribution of all system costs and benefits among the users. The rates of return (Annex 5.4)9 calculated by including all of ISA's assets in the rate base, show that they are in line with those agreed under San Carlos I. Agreement to the principle of a common rate of return on all of ISA's revalued assets has been reached. The target, in line with the agreement reached under San Carlos I and with ISA's own projections would be a rate of return of not less than 8% in 1979, 9% in 1980, 11% in 1981, and 9% in 1982 and thereafter. Financial Outlook of ISA's Shareholders 5.15 To assess the shareholders' capacity to meet their obligations to ISA on account of capital contributions, security subscriptions and pay- ments for the purchase of energy and transmission charges, the financial forecasts of EEEB, EPM, CVC and CORELCA over 1978-1985 have been reviewed (Annex 5.4). ICEL's obligations will continue to be covered with Government  - 41 - contributions from the national budget. As under the agreements for San Carlos I (2.12), the shareholders would not transfer any assets or take any other action which would jeopardize compliance with their obligations to ISA. 5.16 The financial projections of EEEB, EPM, CVC assume a rate increase program of up to 2.2% per month (30% per year) through 1980 as approved by JNT in October 1977. While CORELCA's projections assume rate increments of up to 38% per year in order to meet performance targets agreed to under San Carlos I. EEEB 5.17 EEEB's internal cash generation during the past ten years covered more than 50% of its annual investment needs, including substantial contribu- tions to ISA. This may be attributed in large part to low-cost facilities (given the area's geographic advantages for hydro generation) and the high density of its market. The balance of the company's investment funds have been obtained through borrowings, generally at reasonable cost; no government funding has been required. 5.18 EEEB's 1978-1985 financial forecasts are based on the continued application of 2.2% increases per month through 1982, and on the assumption that the end 1982 average tariff level will be maintained in real terms thereafter by the application of a constant yearly increase of 14%. These assumptions are in line with those made under the Mesitas Project (approved by the Board on November 14, 1978). Under that project, EEEB agreed to achieve annually a specific minimum rate of return which was also included in the San Carlos I shareholders agreement and would be maintained under San Carlos II. Although EEEB's financial performance is expected to continue to be satisfactory under the already agreed targets, its annual levels of performance (Annex 5.4) estimated in February 1979 are somewhat different from those made under the Mesitas project. These new figures reflect some revisions to the development program made by EEEB's new senior management who assumed office toward the end of 1978. EPM 5.19 EPM's financial situation was unsatisfactory in 1974 and 1975; it improved in 1976 and 1977 as a result of the application of the JNT approved rate increases. During 1978, EPM's performance regained its former satisfactory level. 5.20 EPM's projected performance is expected to remain satisfactory (Annex 5.4). In order to meet its financial commitments to ISA, EPM has projected tariff rates at levels which provide rates of return substantially higher than the minimum values agreed to under San Carlos I. Its annual debt service coverage ratio would exceed 1.5, except in 1979 and 1983. Although EPM in view of the JNT approval could increase its rates by a maximum of 30% per year through 1980, it projected only a compounded 24% for 1979, when the annual debt service coverage would be only 1.4. Similarly, in 1983, when it converts from an exporter of energy to other systems to an importer, EPM assumes a rate increase of only 21% and its annual debt service coverage  - 42 - ratio drops to 1.1 from 1.6 in 1982. The existing debt service test covenant under Toan 874-CO has been modified to include contributions to ISA in the calculation of debt; thus EPM would not incurr new long term debt, without Bank concurrence, unless its debt service test in 1979 and thereafter would meet or exceed 1.5. EPM would also maintain rates of return as agreed under San Carlos I. CvC 5.21 CVC's financial situation was poor in the past because it charged inadequate bulk rates to its main customer, EMCALI. Its 1976-77 rate of return on revalued assets averaged less than 3% and internally generated funds did not cover its debt service in that year. However, CVC's application of the maximum authorized rate increase during 1978 has lead to a considerable improvement; CVC is expected to achieve a 5.7% rate of return in 1978, in comparison to the 5% agreed under San Carlos I (Annex 5.4). CVC's rates of return would exceed the levels agreed under San Carlos I because of the increased revenues required to meet its financial obligations to ISA. In order to assure adequate availability of funds, it has been agreed that CVC would not incur long term debt, without Bank concurrence, unless its debt service test (including contributions to ISA) would meet at least 1.2 in 1980, 1.3 in 1981 through 1983 and 1.5 thereafter. 5.22 The main item in CVC's investment program is the Salvajina Multi- purpose Project (4.01) which the IDB and the Japanese Government have been requested to finance. CVC would require Government contributions of MCol$ 720 to undertake Salvajina. CORELCA 5.23 CORELCA's system depends entirely on thermal generation. Although the Government subsidizes CORELCA through low fuel prices, the utility's operating costs are substantially higher than those of other bulk suppliers in Colombia, which generate most of their power in hydroelectric plants. In the past these costs were not fully reflected in CORELCA's rates, and its financial performance has been poor. Under the 500-kV interconnection project (Loan 1583-CO), the Government undertook to increase gradually the prices for fuel purchased by CORELCA with the objective that by 1982 it would be more costly for CORELCA to generate energy than purchase it from the Central System. In line with this, the Government's national fuel price increase in December 1978 results in an effective 41% increase in the final price CORELCA pays. CORELCA's forecasts, reflecting the measures agreed under San Carlos I and the 500-kV project, and repeated under the proposed loan, are based on a gradual elimination of the fuel subsidy, accompanied by sizeable rate increases exceeding the JNT limits in 1979, 1980 and 1981 and designed to offset these fuel costs and improve the utility's rate of return to the values agreed under San Carlos I (CORELCA's final results are expected to show that the entity has achieved a 4% rate of return in 1978, as agreed). However, as in the past, CORELCA's insufficient cash generation in relation to its own debt service requirements and investment commitments to ISA is expected to be  - 43 - compensated for by Government contributions. The recommendations of the institutional study of CORELCA provided for under San Carlos I (2.18) is expected to be implemented by March 31, 1981 to strengthen CORELCA's management, organization, planning and operations, including finances. Because of the financial implications of CORELCA's tariff increase program on its subsidiaries, to which it sells in bulk, agreement has been reached with CORELCA that the scope of the above-mentioned study would be enlarged to cover at least the finances and tariff aspects of its three largest subsidiaries which together account for over 70% of CORELCA's sales (2.18). The rates of return agreed to under San Carlos I would be maintained as well as the government guarantee on CORELCA's timely contributions to ISA. ICEL 5.24 ICEL functions essentially as a holding company for eleven local power utilities which serve largely rural areas (2.16). It does not have any revenues of its own and its expenses, debt service and investments (including its contributions to ISA) are covered with Government budgetary appropriations. ICEL's largest subsidiaries are currently applying monthly tariff increases similar to those approved by other utilities. Under the San Carlos I guarantee agreement, the Government undertook to cover ICEL's contri- butions to ISA for the project, in the event the company would be unable to make timely payments. 5.25 On the request of the Bank, ISA is presently executing a preliminary review of ICEL (2.17). In the interim, ICEL has agreed to provide available financial information to the Bank. The resulting information is expected to provide a somewhat fuller picture of the entity but would not be sufficient for determining ICEL's capacity to meet its financial commitments to ISA, including energy purchases which are projected to reach 45% of ISA's sales in 1982 (5.02). Thus, assurances have been obtained from the Government that such commitments would be met timely. Performance Indicators and Reporting 5.26 Over the project implementation period, ISA is expected to generate an increasing share of the power sold by its shareholders and, together with its shareholders, to achieve generally satisfactory financial performance. The expected performance of ISA and the shareholders is reflected in the forecast indicators in Annex 5.4, which would be used as a basis for monitoring performance during project execution. 5.27 Under San Carlos I, ISA and its shareholders agreed to report quarterly on their performance in meeting targets. In addition, ISA agreed to include in its quarterly reports on the progress of the project, detailed information on its financial condition, the status of payments from the Government and the shareholders to ISA. They would also provide annual reports on asset revaluation. These reports are aimed at enabling ISA and the Bank to identify any deviations from the agreed financial performance early enough to permit timely corrective action. These undertakings have been repeated under the San Carlos II loan.  - 44 - Uniform System of Power Sector Accounts 5.28 The varied formats, criteria and presentation of financial forecasts by ISA and its shareholders indicate that a uniform system of accounting would be desirable, as this would facilitate sound system planning and management. Thus, agreement has been reached that ISA and its shareholders would undertake a study on this matter under terms of reference to be reviewed in discussion with the Government and by the Bank. For this purpose, the terms of reference would be submitted by December 31, 1979 and the study would be completed by June 30, 1981. 6. ECONOMIC ANALYSIS 6.01 San Carlos (1240 MW) would be the largest facility in the inte- grated system, located near the center of the load in the central system. The station cannot be considered in isolation, since its generation depends substantially on concurrent completion of the Jaguas hydro station (170 MW) and diversion works and, to a lesser extent, on the Calderas hydro station. The average annual incremental generation, once these works have been com- pleted, broken down to show the contributions of the various rivers (Annex 4.2) and power stations, is the following: San Carlos (GWh) Nare river (through Guatape) 2,030 Guatape river (to San Carlos reservoir) 1,170 San Carlos river (to San Carlos reservoir) 1,030 Nare river (through Jaguas) 1,670 Calderas and Tafetanes river (to San Carlos reservoir) 250 Jaguas' own generation 670 Calderas' own generation 90 6,910 Comparison of Alternatives 6.02 A comparison of 3 alternative development programs, prepared for the San Carlos I project 1/ showed the economic justification of ISA's development program, including San Carlos, having the highest proportion of hydro development, up to a discount rate of at least 12.5%. In view of the lower than expected cost of San Carlos, a new comparison would therefore show a slightly higher equalizing discount rate. For this reason, and because San Carlos is already being constructed, the calculation has not been repeated. 1/ Staff Appraisal Report: San Carlos I Hydro Power and 500-kV Interconnec- tion Projects No. 1850a-CO; May 17, 1978.  - 45 - 6.03 Because ISA would not undertake any project in excess of 200 MW unless economically justified (5.02), the Bank's main concern is that ISA regularly update the economic ranking of future projects. A first report 1/, using the method of economic comparison in accordance with least incremental cost was submitted to the Bank in 1978. ISA recently repeated the study 2/, this time using the discounted cash flow method of comparison, substantially confirming the findings with respect to economic ranking of the first report. The results of the latest study are discussed below. 6.04 Fifteen alternative power developments to meet energy requirements through 1990 were stochastically examined with the constraint that, on the basis of simulation studies, adverse hydrological events occurring less than once in 20 years would not have to be met, i.e., the event that energy requirements could not be met would have a 5% probability of occurring. Subsequent to assessing the least-cost development program, the latter is simulated and the probabilities calculated that demand requirements could not be met. Adjustments are then made in plant timing to ensure that capacity deficits have a probability of less than 5% of occurring (in the present study these adjustments are negligibly small; one thermal plant has to be advanced by one month in 1982 and two respectively 1 and 3 months in 1988 and 1990). The simulation also provides operational costs and fuel costs for the various alternatives. 6.05 Five alternatives were eliminated for not meeting the probability constraint and, for the remaining 10 alternatives, the present values of the cost streams were calculated (all at constant 1976 prices), using a discount rate of 11%, representing the estimated opportunity cost of capital in Colombia. System effects beyond the end of the discount period (1991) were accounted for by making corrections for differences in capacities and related costs, calculating present values of steam plants to be replaced after 25 years, valuing differences in generation (thermal and hydro) at their respective long-term marginal cost, and calculating present values of continuing differ- ences in operational cost and fuel. A sensitivity analysis was made with respect to the discount rate (10%, 12%) and the assumed economic fuel prices ($20/t for coal, $13/bbl for residual oil and $1.40/1000 ft3 for gas, increas- ing by 10% and 20%). The economic ranking of the lowest and next lowest ranking alternatives does not change as a result of this analysis. The third and fourth lowest ranking alternatives would change place in merit order if a discount rate of 12% is assumed. 6.06 The analysis also shows that the results are insensitive to a reasonable range in variation of the standard conversion factor (corres- ponding to the shadow exchange rate). The results are also insensitive to the use of conversion factors, i.e. neither the timing of individual plants within a development scheme nor the ranking of alternative development schemes are affected whether or not conversion factors are applied. 1/ Programa de Expansion del Sistema Interconectado 1984-88; Junio 1977. 2/ Verificacion y actualizacion expansion 1984-1988; Diciembre 1978.  - 46 - 6.07 The ranking of future plants in the least-cost alternative develop- ment generation program (including transmission lines related to each item in the program) compared with the present plan (4.01) is the following: ----------Least Cost Plan-------- MW 1977 1978 Tasajero 132 December 1982 1985 Cerrejon II 150 October 1984 1985 Guadalupe IV 260 January 1985 1984 Playas 240 October 1985 - Betania 500 March 1986 1985 Guavio 975 November 1986 - Urra 1,050 April 1988 - Patia 1,200 July 1989 - San Juan 1,500 December 1990 - The advancement of Tasajero and Cerrejon II, both coal fired thermal plants, is required because of delays in plant completion and security of supply. Guadalupe IV and Playas, both hydro, should follow these 2 plants because the larger hydro plants, Betania and Guavio, cannot be completed earlier than indicated. The most important changes with respect to the present program are the advancement of the thermal expansion at Tasajero (ICEL) and Cerrejon II (CORELCA). ISA's Board is expected to approve a revised program of future generating plant substantially in accordance with the above and ICEL and CORELCA would take the necessary steps to execute their respective part of the program in accordance with the scheduled as agreed to by the Board. 6.08 The comparison as originally prepared by ISA did not include the replacement of EPM's Guadalupe I hydro plant with a capacity of 100 MW and the Troneras hydro addition of 26 MW. The diversion of 3 rivers to the Guadalupe reservoir, however, were included and justified. Simulation, including these plants indicate that for capacity reasons they are not required. Because generation would be increased only marginally, it appears that neither the renovation of Guadalupe I, nor the addition of a second unit at Troneras have substantial economic merits and could be deleted from the future program. 6.09 The present program also includes CVC's multipurpose Salvajina hydro project, the construction of which would be subject to Bank review under the San Carlos I agreements. In ISA's report, all but one alternative development plan include Salvajina (180 MW). The one excluding Salvajina has been con- ceived on the basis of the least-cost development program by adjusting the timing of plants in the least-cost program to meet power requirements. This changes the ranking of the least-cost scheme from 1 to 9, which shows that Salvajina forms part of the least-cost development program. 6.10 The net present value differences of the 10 alternatives are the following:  - 47 - Ranking Alternative Net Present Value 1 6 0 2 4 8.5 3 5 11.2 4 13 13.7 5 12 22.2 6 14 23.4 7 8 25.8 8 7 30.1 9 10 35.8 10 9 40.0 Return on Investment 6.11 The return on investment is the discount rate which equates the present value of the cost and benefits streams associated with a project over the economic life of the project. Because San Carlos I, II, Calderas and Jaguas would now be constructed concurrently, they cannot be considered in isolation (6.01) and the calculations were made on the combination of these plants (Annex 6.1). The cost streams comprise capital cost, including the 1980-1986 distribution expansion commensurate with these projects, and operating and maintenance cost related to these works. These costs were converted to border prices, based on conversion factors for individual cost components. As a proxy for benefits, the estimated average 1978 revenue for the Central and Atlantic Regions of USJ2/kWh (1.27), multiplied by the standard conversion factor (0.92), was used taking into account total average generation and deducting losses. 6.12 The resulting rate of return of 13.5% is higher than the 7.5% calculated for the San Carlos I project, due to: (a) for the San Carlos I projects, the rate of return was calculated for this project alone (7.5%) and in combination with the 500-kV interconnection project (13%); (b) reduction in project estimated cost (4.06); (c) the substantial average increase in rates (some 50% in real terms since 1977); (d) the improved efficiency of the system due to the construction of San Carlos II, Jaguas and Calderas; (e) the use of the standard conversion factor (for San Carlos I the average consumption conversion factor of 0.785 was used). 6.13 A sensitivity analysis was carried out to measure the impact of major uncertainties underlying the return calculation. Sensitivity to changes in operational cost is negligibly small, i.e. the rate of return would only  - 48 - depend on possible variations in capital cost and revenues (rates and/or sales). With respect to capital cost, the possibility that ISA's shareholders will have to step-up their investments in distribution (1.21) compared with its present 25% of total investments, appears probable and the sensitivity to an increased program should be investigated. The analysis shows the following: Assumptions Rate of Return (%) Basic 13.5 10% increase in revenue 14.6 10% increase in capital cost 12.4 100% increase in distribution expansion 11.5 10% increase in capital cost and 10% reduction in revenues 11.1 100% increase in distribution expansion and 10% increase in capital cost and 10% reduction in revenues 9.5 Because even assuming that cost would increase by 10%, revenues decrease by 10% and that investments in distribution related to the project would double, the rate of return would barely drop below 10%, the probability appears high that the rate of return on the project exceeds the opportunity cost of capital (assumed to be 11%) by a comfortable margin. 7. AGREEMENTS REACHED AND RECOMMENDATION 7.01 During negotiations the following agreements were reached: (a) The Government undertaking in the San Carlos I agreements (Loan 1582-CO) that it will meet ICEL and CORELCA's financial commitments to ISA in a timely fashion, has been modified to include payments for the purchase of power (2.17); (b) ISA would engage Consultants by December 31, 1979 for carrying out a study of the requirements for coordinated dispatch, including training, under conditions and terms acceptable to the Bank; the study would be completed by December 31, 1981 (4.16); (c) ISA would engage consultants by December 31, 1979 for carry- ing out a study assessing ISA's manpower requirements and training, under conditions and terms acceptable to the Bank. The study would be completed by June 30, 1980. An agreed training program would be instituted for completion by June 30, 1983 (4.18); (d) ISA would execute the Project in accordance with an agreed implementation schedule (4.21);  - 49 - (e) ISA would acquire all lands and rights in respect of land and make arrangements for the evacuation to be completed, by December 31, 1980, for any area required for the works of the Calderas hydro plant and, by December 31, 1981, all other lands and rights in respect of lands required for the carrying out of the project (4.25); (f) The covenants related to two sets of ISA's rate of returns in the San Carlos I agreements have been modified to reflect a common rate of return on all of ISA's assets including the 500-kV assets, stipulating overall rates of return as agreed to under San Carlos I for the assets other than 500-kV (5.14); (g) EPM's present debt service covenant (Loan 874-CO) has been modified to include contributions to ISA in the calculation of debt service; from 1979 onward it would meet a debt service test of 1.5 (5.20); (h) CVC would not incur any long term debt without Bank concurrence, unless it would meet (including contributions to ISA) a debt service test of 1.2 in 1980, 1.3 in 1981-83 and 1.5 thereafter (5.21); (i) CORELCA's undertaking under San Carlos I (Loan 1502-CO) that it will carry out an overall organizational study of its institution has been amended to include the finances of its 3 largest subsidiaries (5.23); (j) ISA and its shareholders agreed to a set of indicators to be used for monitoring performance during project execution (5.26); and (k) ISA and its shareholders would carry out a study on the possible creation of a common system of accounts. The terms of reference would be furnished to the Government and the Bank for review and comments by December 31, 1979 and the study would be completed by June 30, 1981 (5.28). 7.02 Effectiveness of the proposed loan would be subject to: Receipt of evidence that ISA has made satisfactory arrangements for the balance of foreign exchange requirements for the project and for the financing of the Jaguas plant (5.08). 7.03 With the above assurances the project would be suitable for a Bank loan of MUS$72 equivalent to be made to ISA with the guarantee of the Govern- ment of Colombia. The loan would have a repayment period of 17 years including a grace period of 4 years. May 30, 1979  - 50 - ANX 12.1 COLOM3TA ( SAN CARLOS II EYDRO POWER PROJECT IBRD Power Loans ( Borrowers and Year of Loan Amount Loan No. Agreement Project Description (MUS$) GOVERNMENT 1583-CO 1978 500-kV Interconnection (Central System/Atlantic System) 50.00 ISA 575-CO 1968 Central System Interconnection (230 kV transmission lines and substations) 18.0 681-CO 1970 Chivor I project (4 x 125 MW hydro) 52.3 1582-CO 1978 San Carlos I (4 x 155 MW hydro) 126.00 EEEB 246-CO 1960 Laguneta unit 4 (1 x 18.0 MW hydro) 17.60 Salto II units 1 and 2 (2 x 33.0 MW hydro) Zipaquira unit 1 (1 x 33.0 MW thermal) 313-CO 1962 Zipaquira unit 2 (1 x 37.5 MW thermal) 50.00 El Colegio units 1, 2, and 3 (3 x 50.0 MW hydro) 537-CO 1968 El Colegio units 4, 5, and 6 (3 x 50.0 MW hydro) 18.00 Canoas project (1 x 50.0 MW hydro) 1628-CO 1978 Mesitas Hy8ro (El Paralso 3 x 90 MW; Laguaca 3 x 110 MW; pumping 3 x 10 MEP; Sequile dam strengthening) 84.00 EPM 225-C0 1959 Troneras unit 1 (1 x 18.0 MW hydro) 12.00 Guadalupe III units 1 and 2 (2 x 45.0 MW hydro) 282-CO 1961 Troneras unit 2 (1 x 18.0 MW hydro) 22.00 Guadalupe III units 3, 4, and 5 (3 x 45.0 MW hydro) 369-CO 1964 Guatape I units 1 and 2 (2 x 66.0 MW hydro)-/ 45.00 874-CO 1973 Guatape II units 1, 2, 3, and 4 (4.x 70 MW hydro) 56.00 CVC/CHIDRAL 38-CO 1950 Anchicaya units 1 and 2 (2 x 12.0 MW hydro) 3.53 113-CO 1955 Anchicaya unit 3 (1 x 20.0 MW hydro) 4.50 Yumbo unit 1 (1 x 10.0 MW thermal) 215-CO 1958 Yumbo unit 2 (1 x 10.0 MW thermal) 2.80 255-CO 1960 Yumbo unit 3 (1 x 33.0 MW thermal) 25.00 Calima units I and 2 (2 a 30.0 MW hydro) 339-CO 1963 Calima units 3 and 4 (2 x 30.0 MW hydro) 8.80 CHEC 39-CO 1950 La Inaula units 1 and 2 (2 x 10.0 MW hydro) 2.60 217-CO 1959 La Esmeralda units 1 and 2 (2 x 13.3 MW hydro) 4.60 LEBRIJA 54-CO 1951 Palmas units 1 and 2 (2 x 4.4 MW hydro) 2.40 ELECTRIBOL 347-CO 1963 Cospique units 2 and 3 (2 x 12.5 MW thermal) 5.00 a/ Subsequently increased to 4 x 70 MW. March 0, 1979  - 51 - ANNEX 1.2 COLOMBIA SAN CARLOS II HYDRO POWER PROJECT 1977 Sector Installed Capacities and Power Generation Capacity (MW) Generation (GWh) Hydro Thermal Total % Hydro Thermal Total % 1. Public Service 2,715 837 3,552 94.3 10,317 3,892 14,209 93>O EEEB 583 136 719 19.1 2,890 738 3,628 23.8 EPM 729 - 729 19.3 3,418 - 3,418 22.4 CVC-CHIDRAL 540 58 598 15.9 1,758 155 1,91:3 12.3 ICEL-CHEC 363 203 566 15.0 1,243 809 2,052 13.4 CORELCA - 440 440 11.7 - 2,190 2,190 14.3 ISA 500 - 500 13.3 1,008 - 1,008 6.6 2. Self-Producers 20 193 213 5.7 88 982 1,070 7.0 Ecopetrol - 55 55 1.5 - 289 289 1.9 Paz del Rio - 20 20 0.5 - 105 105 0.7 Monomeros - 12 12 0.3 - 63 63 0.4 Others 20 106 126 3.4 88 525 613 4.0 3. Total 2,735 1,030 3,765 100.0 10,405 4,874 15,279 100.0 Percentage 72.6 27.4 100.0 68.1 31.9 100.0 Breakdown of Thermal Capacity and Generation Capacity (MW) Generation (GWh) Public Self- Public Self- Service Producers Total % Service Producers Total % Steam 528 132 660 64.1 2,684 698 3,382 69.4 Gas turbine 266 39 305 29.6 1,041 188 1,229 25.2 Diesel 53 22 65 6.3 167 96 263 5.4 Total 837 193 1,030 100.0 3,892 982 4,874 100.) Percentage 81.3 18.7 100.0 79.9 20.1 100.0 Source: ISA March 8, 1979  COLOMBIA INTERCONEXION ELECTRICA S.A. Organizational Chart KA-,, ~ ~ ~ ~ ~ ~ ~ ~~~.i~oo oOloto OOOatcfl C,oO, plantHOd,o Elec,,ca, SoocI P,oroOO Cff,C,eooo ao,o,o-ca- -d SW~~ ~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~s,r~ ~ Aolnt,o Onganloation Safety Tar,lla Pooy,ooo,oo Montenanos C~~~~~~~~~~~~~~~~~~~~~~~s;oo OMan Tnafl,m,SS;On ItO~~~~A11- f. ri~~~~~~~~~~~~~~I oOOtn loin oO,O SOOto lo OSCOol0 j- 197B 20299~AC,,.tOS eile Soe Snle;SnoneSooe  - 53 - Annex 2.2 Page 1 of 4 COLOMBIA SAN CARLOS I HYDRO POWER AND 500-kV INTERCONNECTION PROJECTS DESCRIPTION OF ISA'S SHAREHOLDERS Empresa de Energia Electrica de Bogota 1. EEEB is an autonomous company, owned by the Municipality of the Special District of Bogota, which generates, transmits and distributes electricity. It serves some 483,000 consumers in metropolitan Bogota directly and sells power in bulk to ICEL's subsidiary in the department of Cundinamarca. EEEB has received four loans from the Bank, three of which, (totalling MUS$ 85.6) have been fully disbursed. The fourth (MUS$84) was made in 1978 for the Mesitas project. A Project Performance Audit 1/ on the most recent loan (537-CO of August 2, 1968) concluded that EEEB was a well-managed utility, and that the project was successfully executed. 2. EEEB is administered by a seven member Board of Directors and a General Manager. The Mayor of Bogota, or his representative, serves as the Chairman of the Board of Directors. The General Manager, who is responsible for the day-to-day management of the company, is appointed by the Board subject to the Mayor's approval. EEEB's management is adequate for the execution of its expansion program and for the operation of its facilities. 3. EEEB has an installed capacity of 719 MW, 583 MW from hydro and 136 MW from thermal power stations. The Mesitas project is scheduled to come into operation by mid-1982. A distribution project covering the city and valley of Bogota is being considered for possible Bank financing. Empresas Publicas de Medellin 4. EPM is an autonomous company, owned by the Municipality of Medellin, which provides power, water, sewerage, and telephone services for the city of Medellin and vicinity. It serves some 255,000 power consumers in metropolitan Medellin and sells in bulk to ICEL's subsidiary in the department of Antioquia. EPM has received four loans from the Bank totalling MUS$ 129. A Project Performance Audit 2/ on the third project (Loan 369-CO of February 7, 1964) concluded that the project was 1/ Project Performance Audit Report on Colombia: Third Power Expansion Program (Sec M77-536 of June 29, 1977). 2/ Performance Audit on Colombia: Third Medellin Power Project (Sec M74-376 of May 24, 1974).  - 54 - Annex 2.2 Page 2 of 4 worthwhile and that, with the exception of the distribution component, it was well executed. The most recent project financed by the Bank (Guatape II, Loan 874-CO) is currently under construction and is scheduled for completion by the first quarter of 1979, 20 months behind schedule. During construction, difficulties have been encountered in relocating the population of El Penol, which has been flooded by the Santa Rita reservoir, mainly because of poor planning and excessive demands for compensation. 5. EPM is managed by a seven member Board of Directors and the General Manager. The Mayor of Medellin, or his representative, is the Chairman of the Board of Directors. After some difficulties in the mid-1970s resulting from political interference in EPM by the municipal government, EPM's management is now generally adequate and the improvements recently made have increased its capacity to execute its expansion program and to operate its facilities. 6. The various services of EPM are managed as separate entities with separate accounting systems. Including Guatape II, EPM has an installed capacity of 4,014 MW (all hydro). In addition to this project, EPM's investment program for 1977-84 includes expansion in generation, transmission, and distribution facilities, as well as the initial expenditures for the new Guadalupe IV (260 MW) hydro station. Corporacion Autonoma Regional del Cauca 7. CVC is an autonomous multipurpose State corporation under the National Planning Department, responsible for developing the Cauca Valley. One of its main activities is generating and transmitting power in the Valley, undertaken in part through CHIDRAL, which is owned by CVC (65%), the Municipality of Cali (17%) and Empresas Municipales de Cali (EMCALI--18%). CVC-CHIDRAL sells power in bulk to EMCALI and other distributing companies (subsidiaries of ICEL and CVC) serving a total of some 298,000 consumers. 8. CVC-CHIDRAL has received five loans from the Bank totalling MUS$ 44.6 (the last of which was made in 1963) which have been fully disbursed. CVC-CHIDRAL has an installed capacity of 598 MW (540 MW hydro, 58 MW thermal). The CVC-CHIDRAL expansion program includes the execution of the multipurpose Salvajina project (intended mainly for flood control and irrigation), which includes 180 MW of generating capacity, and the corresponding transmission facilities. 9. CVC is administered by a seven member Board of Directors and an Executive Director appointed by the President of the Republic. CVC's various activities 1/ are managed as separate enterprises with relatively 1/ These activties, in addition to power generation and transmission, include rural electrification (carried out through the local sub- sidiaries); irrigation and rural development; development of natural resources (including operation of a captive coal mine for thermal power generation); and operation of hotels.  - 55 - Annex 2.2 Page 3 of 4 independent accounting systems. Some of CVC's generation and transmission facilities are leased to and operated by CHIDRAL. CHIDRAL is administered by a seven member Board of Directors and a General Manager. EMCALI is respon- sible for power distribution in the city of Cali and vicinity. It is a municipal company which also provides water, sewerage and telephone services. 10. CVC and EMCALI are considering setting up a new regional power company to take charge of power generation and transmission in the Cauca Valley. They have expressed their intention of consulting their creditors (among which the Bank is included because of its early power loans to CVC and CHIDRAL and its more recent loans for water supply: 682-CO and 1523-CO in 1970 and 1978 respectively) on this proposal. Corporacion Electrica de la Costa Atlantica 11. CORELCA is an autonomous corporation in operation since 1972. It is responsible for power generation and transmission in seven departments on the Atlantic Coast. The seven distributing companies in the area are subsidiaries of CORELCA and buy power in bulk from it. Together they have an installed capacity of 440 MW (all thermal) and serve about 322,000 consumers. One of CORELCA's subsidiaries, ELECTRIBOL, which at the time was a subsidiary of ICEL, received a MUS$ 5 Bank loan (347-CO) in 1963, which is fully disbursed. CORELCA is in the process of completing a 132-MW steam station. Through 1980-81, its investment program comprises 132 MW of gas-fired steam plant in the Barranquilla and another of 66 MW in Cartagena, and the expansion of its transmission system. A 150 MW steam station that is to use coal from the Cerrejon project is planned for commissioning in 1983. CORELCA became an ISA shareholder in 1978 and thus will participate in ISA's generation and transmission projects. 12. CORELCA is administered by a seven member Board of Directors and a Managing Director. Its organization, budgeting, budget control, admini- stration and accounting require strengthening to enable it to keep pace with its rapid growth. Under the San Carlos I loan, CORELCA agreed, to this end, to carry out, a study under terms of reference discussed with the Bank. CORELCA has agreed under the proposed loan for San Carlos II to extend the study to its 3 main subsidiaries and to a revised program for executing the study (see para. 2.18). Instituto Colombiano de Energia Electrica 13. ICEL is a government institute, responsible to the Ministry of Mines and Energy, and provides electric power services for the rest of the country through 11 subsidiary companies in which it is the majority shareholder (the other shareholders are the respective local governments).  - 56 - Annex 2.2 Page 4 of 4 ICEL's subsidiaries have an installed capacity of 543 MW (340 MW hydro, 203 MW thermal) and serve about 580,000 customers. ICEL's role was intitially conceived as that of coordinator of the power sector development. It was not, however, successful in this function and its mission presently consists largely of supervising the extension of service to smaller towns and rural areas. In keeping with Government policy, ICEL will concentrate its activities in areas not served by other entities, which are expected to be largely rural; the Government would continue to provide budgetary support for these electric power services through ICEL. ICEL is also responsible for the investment program of most of its subsidiaries, which essentially comprises expansion of the various transmission and distribution systems connected to the interconnected system, and generating additions to isolated systems. The projects executed by ICEL are transferred to its subsidiaries in the form of capital contribution. Three 1/ of ICEL's subsidiaries have received four loans from the Bank, totalling MUS$ 14.6, which have been fully disbursed. ICEL is the executing agency for the rural electrification component (US$2.1) of Loan 1352-CO, which is proceeding well after some initial delays. 14. ICEL is administered by a five member Board of Directors (chaired by the Minister of Mines and Energy) and by a General Manager appointed by the President of the Republic. ICEL and its subsidiaries have organizational and administrative shortcomings, resulting from frequent changes in middle management, low salaries, lack of qualified staff, poor accounting systems and insufficient control exercised by ICEL over the operations of its subsidiaries. To formulate an improvement program, ICEL undertook under the San Carlos I loan to conduct a study of at least five of its larger subsidiaries. The study would be presented to the Bank, together with ICEL's proposals for implementation by December 31, 1979 during negotiation for San Carlos II, this date was amended to March 31, 1980. Implementation of the proposals (as amended resulting from comments of the Bank), would be completed by December 31, 1981. 1/ Central Hidroelectrica de Caldas (CHEC) (39-CO and 217-CO), Central Hidroelectrica del Rio Lebrija (54-CO), now known as Electrificadora de Santander, and Electrificadora de Bolivar (347-CO), now a sub- sidiary of CORELCA.  5' - .C-1 S. -RLOS T7 I.RO DO- IR.-
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111 I 2 'IE 3 2S1 2. 5K6 2 , I I ? b.E b- I   --58 ANNEX 3.2 COLOMSBIA SAN CARLOS II HYDRO POWER PROJECT Forecast Energy Requirements Interconnected System 1978-1985 1977 1978 1979 1980 1981 1982 1983 1984 1985 Historic --------Systems Isolated------ Central and Atlantic Systems Interconnected- EEEB System Gross generation: Hydro 2,890 2,182 2,239 2,697 3,500 3,917 3,907 3,299 3,321 Thermal 738 798 798 798 798 798 763 714 711, Purchases from (sales to) other systems, net 337 1,408 1,796 1,825 1,549 1,719 2,403 3,774 4,524 Gross energy available for system 3,965 4,388 4,833 5,320 5,847 6,434 7,073 7,787 8,559 Losses (648) (656) (683) (766) (803) (844) (875) (909) (922) Sales in system 3,317 3,732 4,150 4,554 5,044 5,590 6,198 6,878 7,637 Maximum Demand Mi' 783 833 920 1,003 1,103 1,211 1,333 1,466 1,613 EPM System Gross generation: Hydro 3,418 3,390 4,280 5,238 5,620 5,880 4,242 5,715 6,598 Purchases from (sales to) other systems, net (222) 429 (149) (771) (781) (650) 1,491 470 86 Gross energy available for system 3,196 3,819 4,131 4,467 4,839 5,230 5,733 6,185 6,684 Losses (639) (728) (746) (800) (865) (900) (1,100) (1,109) (1,199) Sales in system 2,557 3,091 3,385 3,667 3,974 4,330 4,633 5,076 5,483 Maximum Demand MW 628 713 775 837 909 982 1,076 1,167 1,263 CVC-CHIDRAL System Gross generation: Hydro 1,758 1,803 1,955 2,048 2,240 2,196 2,064 2,802 2,851 Thermal 155 284 284 284 284 284 271 263 263 Purchases from (sales to) other systems, net 117 280 340 480 536 834 1,265 837 1,132 Gross energy available for system 2,030 2,367 2,579 2,812 3,060 3,314 3,600 3,902 4,246 Losses (259) (302) (329) (359) (390) (423) (459) (498) (542) Sales in system 1,771 2,065 2,250 2,453 2,670 2,891 3,141 3,404 3,704 Maximum Demand MW 427 471 512 557 607 660 718 778 846 ICEL-CHEC System Gross generation: Hydro 1,243 1,274 1,365 1,365 1,267 1,217 1,155 1,108 1,103 Thermal 809 1,675 1,917 1,958 1,615 1,948 1,907 1,624 1,966 Purchases from (sales to) other systems, net 575 716 1,029 1,482 2,305 2,577 3,105 3,910 4,268 Gross energy available for system 2,627 3,665 4,311 4,805 5,187 5,738 6,167 6,692 7,337 Losses (620) (880) (1,035) (1,105) (1,193) (1.262) (1,356) (1. 395) (L1 46 7) Sales in system 2,007 2,785 3,276 3,700 3,994 4,476 4,811 5,247 5,870 Maximum Demand MW 583 800 913 1,011 1,094 1,209 1,304 1,406 1,551 CORELCA System Gross generation: Thermal 2,190 2,431 2,686 3,262 4,027 4,017 4,447 4,869 5,730 Purchases from (sales to) other systems, net 123 569 563 604 492 Gross energy for system 2,190 2,431 2,686 3,262 4,150 4,586 5,010 5,473 6,222 Losses (499) (428) (483) (570) (708) (764) (852) (948) (1.085) Sales in system 1,691 2,003 2,203 2,792 3,442 3,822 4,158 4,525 5,137 Maximum demand MW 386 447 491 582 727 810 884 971 1,133 ISA System Gross generation: Hydro 1,008 2,957 3,165 3,192 3,621 5,061 9,044 9,910 10,901 Thermal 387 387 370 347 347 Purchases from other systems 222 149 771 781 650 Gross available energy 1,230 2,957 3,314 3,963 4,789 6,098 9,414 10,257 11,248 Losses (55) (124) (149) (176) (276) (399) (587) (662) (746) Sales to other systems 1,175 2,833 3,165 3,787 4,513 5,699 8,827 9,595 10,502 of which to: EEEB 337 1,408 1,796 1,825 1,549 1,719 2,403 3,774 4,524 EPM 146 429 1,491 470 86 CVC-CHIDRAL 117 280 340 480 536 834 1,265 837 1,132 ICEL-CHEC 575 716 1,029 1,482 2,305 2,577 3,105 3,910 4,268 CORELCA 123 569 563 604 492 Total Interconnected System Gross generation: Hydro 10,317 11,606 13,004 14,540 16,248 18,267 20,412 22,834 24,774 Thermal 3,892 5,188 5 685 6.302 7,111 7.434 7,758 7.817 9,020 Total generation 14,209 16,804 18,689 20,842 23,359 25,701 28,170 30,651 33,794 Losses (2,866) (3,128) (3,425) (3.676) (4,235) (j,592) (5.229) (5,517) (5.963) Sales to final consumers 11,343 13,676 15,264 17,166 19,124 21,109 22,941 25,134 27,831 Maximum Demand 1/ 2,737 3,182 3,521 3,925 4,329 4,760 5,182 5,643 6,246 Source: Financial statements ISA and its Shareholders. I/ Sum of maximum demands times diversity factor 0.975. May 9, 1979   _ 59 _ ANNEX 3.3 COLOMBIA SAN CARLOS II RYDRO POWER PROJECT Balances of Energies and Capacities Interconnected System 1977 1978 1979 1980 1981 1982 1983 1984 1985